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UNITED STATES FORM 10-K |
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(Mark One) |
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[X] |
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES For the fiscal year ended December 31, 2005 |
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OR |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES For the transition period from to |
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Commission file number 1-8222 Central Vermont Public Service Corporation |
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Vermont |
03-0111290 |
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77 Grove Street, Rutland, Vermont |
05701 |
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Registrant's telephone number, including area code |
(802) 773-2711 |
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Securities registered pursuant to Section 12(b) of the Act: |
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Name of each exchange on which |
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Common Stock $6 Par Value |
New York Stock Exchange |
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Securities registered pursuant to Section 12(g) of the Act: NoneIndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No X Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No X 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 Cover page Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No X The aggregate market value of voting and non-voting common equity held by non affiliates of the registrant as of June 30, 2005 (2nd quarter) was approximately $188,588,871 (based on the $18.50 per share closing price of the Company's Common Stock, $6 Par Value, as reported on the New York Stock Exchange Market on June 30, 2005). In determining who are affiliates of the Company for purposes of computation, it is assumed that directors, officers, and other persons who held on December 31, 2005, more than 5 percent of the issued and outstanding Common Stock of the Company are "affiliates" of the Company. The characterization of such directors, officers, and other persons as affiliates is for the purposes of this computation only and should not be construed as a determination or admission for any other purpose. On February 28, 2006 there were outstanding 12,301,915 shares of voting Common Stock, $6 Par Value. DOCUMENTS INCORPORATED BY REFERENCE The Company's Definitive Proxy Statement relating to its Annual Meeting of Stockholders to be held on May 2, 2006 to be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Act of 1934, is incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.
Cover page continued |
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FORM 10-K - 2005 TABLE OF CONTENTS |
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PART I |
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Item 1. |
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . |
4 |
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PART II |
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Item 5. |
Market for Registrant's Common Equity, Related Stockholder Matters |
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PART III |
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Item 10. |
Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . |
129 |
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PART IV |
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Item 15. |
Exhibits, Financial Statement Schedules. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . |
130 |
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Page 3 of 153
Item 1. Business.
Central Vermont Public Service Corporation (the "Company" or "we" or "our") makes available free of charge through its Internet Web Site, http://www.cvps.com its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after those reports are electronically filed with the Securities and Exchange Commission ("SEC"). Access to the reports is available from the main page of the Company's Internet Web site through "Investor Relations." The Company's Corporate Ethics and Conflict of Interest Policy, Corporate Governance Guidelines, and Charters of the Audit, Compensation and Corporate Governance Committees are also available on our Internet Web Site. Access to these documents is available from the main page of the Company's Internet Web Site through "Corporate Governance and Ethics." Printed copies of these documents are also available upon written request to the Assistant Corporate Secretary at our principal executive offices. The Company's reports, proxy, information statements and other information are also available by accessing the SEC's Internet Web Site, http://www.sec.gov, or at the SEC's Public Reference Room at 100 F Street N.E., Washington DC 20549. Information regarding operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0330.
Overview
The Company, incorporated under the laws of Vermont on August 20, 1929, is engaged in the purchase, production, transmission, distribution and sale of electricity. The Company has various wholly and partially owned subsidiaries. These subsidiaries are described below. Also see Part II Item 8, Note 14 - Segment Reporting for financial information regarding the Company's business segments.
The Company is the largest electric utility in Vermont and serves more than 151,000 customers in nearly three-quarters of the towns, villages and cities in Vermont. In addition, the Company supplies electricity to one municipal utility, one rural cooperative and one private utility.
The Company's sales are derived from retail sales, resale firm sales and other resale sales. Retail sales accounted for 78 percent of total mWh sales in 2005, resale firm sales accounted for less than 1 percent and other resale sales accounted for about 22 percent. The Company's retail sales are derived from a diversified customer mix including residential, commercial and industrial customers. Sales to the five largest retail customers receiving electric service from the Company during 2005 accounted for about 6 percent of the Company's total electric revenues for the year. This compares to 6 percent during 2004 and 5 percent during 2003. The Company's other resale sales are related to contract sales to third parties in New England, sales to ISO-New England and short-term system capacity sales. See Part II Item 7, Results of Operations for detailed information regarding the Company's Operating Revenues for the years ended December 31, 2005, 2004 and 2003.
The Company owns 47.05 percent of the common stock and 48.03 percent of the preferred stock of Vermont Electric Power Company, Inc. ("VELCO"). VELCO owns the high-voltage transmission system in Vermont. VELCO's wholly owned subsidiary, Vermont Electric Transmission Company, Inc. ("VETCO"), was formed to finance, construct and operate the Vermont portion of the 450 kV DC transmission line connecting the Province of Quebec with Vermont and New England.
The Company owns 58.85 percent of the common stock of Vermont Yankee Nuclear Power Corporation ("VYNPC"), which was initially formed by a group of New England utilities for the purpose of constructing and operating a nuclear-powered generating plant in Vernon, Vermont. On July 31, 2002, VYNPC completed the sale of its nuclear power plant to Entergy Nuclear Vermont Yankee, LLC ("ENVY"). VYNPC administers the purchased power contracts among the former plant owners and ENVY.
The Company owns 2 percent of the outstanding common stock of Maine Yankee Atomic Power Company, 2 percent of the outstanding common stock of Connecticut Yankee Atomic Power Company and 3.5 percent of the outstanding common stock of Yankee Atomic Electric Company.
The Company's wholly owned subsidiary, Catamount Resources Corporation ("CRC"), was formed for the purpose of holding the Company's subsidiaries that invest in unregulated business opportunities. CRC's wholly owned subsidiary, Eversant Corporation, engages in the sale or rental of electric water heaters through a wholly owned subsidiary, SmartEnergy Water Heating Services, Inc. to customers in Vermont and New Hampshire.
Page 4 of 153
Other wholly owned subsidiaries of the Company include:
The Company's wholly owned subsidiary, Connecticut Valley Electric Company Inc. ("Connecticut Valley"), incorporated under the laws of New Hampshire on December 9, 1948, distributed and sold electricity in parts of New Hampshire bordering the Connecticut River. On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to Public Service Company of New Hampshire ("PSNH"). Connecticut Valley no longer conducts business as an electric utility in New Hampshire.
On October 31, 2005, CRC's wholly owned subsidiary, Catamount Energy Corporation ("Catamount"), which invested primarily in wind energy projects in the United States and the United Kingdom, issued shares of its common stock to CEC Wind Acquisition, LLC, a Delaware limited liability company established by Diamond Castle Holdings ("Diamond Castle"). The stock issuance was based on Diamond Castle's firm commitment to invest $62.5 million in Catamount over a three-year period including its initial investment of $16 million made on October 31, 2005. The transaction diluted CRC's ownership interest in Catamount to 79 percent and its voting rights to 49 percent. On December 20, 2005, CRC sold all of its interest in Catamount to Diamond Castle.
The Company's consolidated financial statements included herein present Catamount and Connecticut Valley as discontinued operations, in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"). See Part II Item 8, Note 3 - Discontinued Operations.
The Company also owns small generating facilities and has joint ownership interests in certain generating facilities. These are described in Power Resources below.
Tender Offer
On February 7, 2006, the Company announced that its Board of Directors approved using about $50.0 million in proceeds from the December 20, 2005 sale of Catamount to buy back shares of its common stock in a reverse Dutch auction tender offer. The tender offer commenced on February 14, 2006 and was scheduled to expire on March 15, 2006, unless extended by the Company. Under the procedures of the tender offer, shareholders may offer to sell some or all of their stock to the Company at a target price in a range from $20.50 to $22.50 per share. Upon expiration of the tender offer, the Company will select the lowest-bid price that will allow it to buy up to 2,250,000 shares, which represents about 18.3 percent of the Company's outstanding common stock. On March 14, 2006, the Company announced that it was extending the tender offer until April 5, 2006.
REGULATION AND COMPETITION
State Commissions
The Company is subject to the regulatory authority of the Vermont Public Service Board ("PSB") with respect to rates and terms of service, and the Company and VELCO are subject to PSB jurisdiction related to securities issuances, planning and construction of major generation and transmission facilities and various other matters. Additionally, the Public Utilities Commission of Maine and the Connecticut Department of Public Utility Control exercise limited jurisdiction over the Company based on its joint-ownership interest as a tenant-in-common of Wyman #4, a 610 MW generating plant, and Millstone Unit #3, a 1155 MW nuclear generating facility, respectively.
The Company was subject to the regulatory authority of the New Hampshire Public Utilities Commission ("NHPUC"), through its wholly owned subsidiary Connecticut Valley, with respect to rates, securities issuances and various other matters. On January 1, 2004, substantially all of Connecticut Valley's plant assets and its franchise were sold to PSNH.
Page 5 of 153
Federal Power Act
Certain phases of the businesses of the Company and VELCO, including certain rates, are subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC") as follows: the Company as a licensee of hydroelectric developments under Part I of the Federal Power Act, and the Company and VELCO as interstate public utilities under Parts II and III, as amended and supplemented by the National Energy Act. The Company is in the process of relicensing or preparing to relicense six separate hydro-projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent about 24.5 MW, or 54.8 percent, of the Company's hydroelectric nameplate capacity. The Company has obtained an exemption from licensing for the Bradford and East Barnet projects. See Power Resources below.
Federal Energy Policy Act of 2005
In August 2005, the Federal Energy Policy Act of 2005 was enacted, which includes numerous provisions meant to increase domestic gas and oil supplies, improve energy system reliability, build new nuclear power plants, and expand renewable energy sources.
Public Utility Holding Company Act
The Federal Energy Policy Act of 2005 repealed the Public Utility Holding Company Act of 1935, effective February 2006. The Company, by reason of its ownership of utility subsidiaries, is a holding company, as defined in the Public Utility Holding Company Act of 2005. The Company intends to make all required filings with FERC of notices required under the Public Utility Holding Company Act of 2005 by the required due dates.
Environmental Matters
The Company is subject to environmental regulations in the licensing and operation of the generation, transmission, and distribution facilities in which it has an interest, as well as the licensing and operation of the facilities in which it is a co-licensee. These environmental regulations are administered by local, state and federal regulatory authorities and may impact the Company's generation, transmission, distribution, transportation and waste handling facilities on air, water, land and aesthetic qualities.
The Company cannot presently forecast the costs or other effects that environmental regulation may ultimately have on its existing and proposed facilities and operations. The Company believes that any such prudently incurred costs related to its utility operations would be recoverable through the ratemaking process. For additional information see Part II Item 8, Note 13, herein for disclosures relating to environmental contingencies, hazardous substance releases and the control measures related thereto.
Nuclear Matters
The nuclear generating facilities in which the Company has an interest are subject to extensive regulation by the Nuclear Regulatory Commission ("NRC"). The NRC is empowered to regulate siting, construction and operation of nuclear reactors with respect to public health, safety, and environmental and antitrust matters. Under its continuing jurisdiction, the NRC may, after appropriate proceedings, require modification of units for which operating licenses have already been issued, or impose new conditions on such licenses, and may require that the operation of a unit cease or that the level of operation of a unit be temporarily or permanently reduced.
Competition
Competition currently takes several forms. At the wholesale level, New England has implemented its version of FERC's "standard market design" ("SMD"), which is a detailed competitive market framework that has resulted in bid-based competition of power suppliers rather than prices set under cost of service regulation. Similar versions of SMD have been implemented in New York State and a large abutting multi-state region referred to as PJM. At the retail level, customers have long had energy options such as propane, natural gas or oil for heating, cooling and water heating, and self-generation. Another competitive threat is the potential for customers to form municipally owned utilities in the Company's service territory.
Pursuant to Vermont statute (30 V.S.A. Section 249), the PSB has established the service area for the Company in which it currently operates. Under 30 V.S.A. Section 251(b) no other company is legally entitled to serve any retail customers in the Company's established service area except as described below.
Page 6 of 153
An amendment to 30 V.S.A. Section 212(a) enacted May 28, 1987 authorizes the Vermont Department of Public Service ("DPS") to purchase and distribute power at retail to all consumers of electricity in Vermont, subject to certain preconditions specified in new sections 212(b) and 212(c). Section 212(b) provides that a review board, consisting of the Governor and certain other designated legislative officers, review and approve any retail proposal by the DPS if they are satisfied that the benefits outweigh any potential risk to the State. However, the DPS may proceed to file the retail proposal with the PSB either upon approval by the review board or failure of the review board to act within sixty (60) days of the submission. Section 212(c) provides that the DPS shall not enter into any retail sales arrangement before the PSB determines that it is appropriate. The PSB assesses the following factors in reaching its conclusion: (1) the need for the sale; (2) the rates are just and reasonable; (3) the sale will result in economic benefit; (4) the sale will not adversely affect system stability and reliability; and (5) the sale will be in the best interest of ratepayers.
Section 212(d) provides that upon PSB approval of a DPS retail sales request, Vermont utilities shall make arrangements for distributing such electricity on terms and conditions that are negotiated. Failing such negotiation, the PSB is directed to determine such terms as will compensate the utility for all costs reasonably and necessarily incurred to provide such arrangements. Such sales have not been made in the Company's service area since 1993.
In addition, Chapter 79 of Title 30 authorizes municipalities to acquire the electric distribution facilities located within their boundaries. The exercise of such authority is conditioned upon an affirmative three-fifths vote of the legal voters in an election and upon payment of just compensation including severance damages. Just compensation is determined either by negotiation between the municipality and the utility or by the PSB after a hearing, if the parties fail to reach an agreement. If either party is dissatisfied, the statute allows them to appeal the PSB's determination to the Vermont Supreme Court. Once the price is determined, whether by agreement of the parties or by the PSB, a second affirmative three-fifths vote of the legal voters is required.
There have been two instances where Chapter 79 of Title 30 has been invoked. In one instance, the Town of Springfield acted to acquire the Company's distribution facilities in that community pursuant to a vote in 1977; that action was discontinued in 1985. The other instance, which occurred in 2002, involved the Town of Rockingham, which voted to pursue purchase of the Company's distribution facilities, Green Mountain Power's ("GMP") distribution facilities, and another party's hydroelectric facility located in Bellows Falls. The Company and GMP refused to voluntarily sell their distribution facilities. In November 2003, the Company was notified that Rockingham intended to obtain their facilities by eminent domain under Title 24 V.S.A. Section 2805. The Company opposed this action as being contrary to Title 30, and in December 2003 obtained a permanent injunction from the Superior Court prohibiting Rockingham from pursuing this course of action. If Rockingham decides to continue this action in the future, it must proceed with the PSB under Title 30. The Company currently serves about 260 residential and small general service customers in Rockingham, whose usage amounts to substantially less than one percent of the Company's annual retail sales.
Competition in the energy services market exists between electricity and fossil fuels. In the residential and small commercial sectors, this competition is primarily for electric space and water heating from propane and oil dealers. Competitive issues are price, service, convenience, cleanliness, automatic delivery and safety.
In the large commercial and industrial sectors, cogeneration and self-generation are the major competitive threats to network electric sales. Competitive risks in these market segments are primarily related to seasonal, one-shift milling operations that can tolerate periodic power outages common to such forms of cogeneration or self-generation, and for industrial or institutional customers with steady heat loads where the generator's waste heat can be used in their manufacturing or space conditioning processes. Competitive advantages for electricity in those segments are: cost stability; convenience; cost of back-up power sources or alternatively, reliability; space requirements; noise problems; air emission and site permit issues; and maintenance requirements.
New Developments
The electric utility industry is in a period of transition that in some cases has resulted in a shift away from ratemaking based on cost of service and return on equity to more market-based rates for power supply services, with energy sold to customers by competing retail energy service providers. Many states have implemented 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.
Page 7 of 153
The State of Vermont continues to examine changes to the provision of electric service absent introduction of retail choice. The Vermont Legislature passed, in the concluded 2005 session, Act 61, "Renewable Energy, Efficiency, Transmission, and Vermont's Energy Future" ("Act 61"), a new law that includes two major provisions of interest to the Company.
The new law establishes a Sustainably Priced Energy Enterprise Development ("SPEED") Program with a collective requirement of all Vermont retail electricity providers to, in aggregate, supply all of their incremental load growth between January 1, 2005 and January 1, 2012 from new renewable supplies, new Renewable Energy Certificates, or a combination of the two, capped at a total of 10 percent of the statewide kWh sales during calendar year 2005. Under SPEED the PSB may: 1) offer the contracts secured by a PSB-named statewide entity or entities to utilities on a pro rata basis; 2) establish a process by which utilities may demonstrate that their power supply portfolio is sufficiently renewable so as to relieve them of having to accept a pro-rata share of additional SPEED renewable power; 3) encourage utilities to secure long-term contracts for renewable energy; and 4) encourage utility sponsorship and partnerships in the development of renewable energy projects. The SPEED program begins on January 1, 2007.
By July 1, 2013, the PSB must determine whether Vermont's retail electricity providers have met the SPEED program's requirements. If the requirements have been met, no other PSB action is required. If not met, the law states that the SPEED program's collective requirement reverts to a utility-specific renewable portfolio standard ("RPS"). Under the RPS, each retail electricity provider would have to supply an amount of energy equal to its total incremental energy growth between January 1, 2005 and January 1, 2012 through the use of electricity generated by new renewable resources, capped at a total of 10 percent of the statewide kWh sales during calendar year 2005. As with the SPEED program, this requirement can be met from new renewable supplies, new Renewable Energy Certificates, or a combination of the two.
Under either program, the Company could be required to purchase certain amounts of its energy supply requirement from new renewable sources while maintaining existing renewable power resources. Alternatively, if the utility-specific RPS takes effect, the Company may choose to pay an as-yet-undetermined charge per kWh, set by the PSB. The PSB is currently developing a rule to implement the SPEED program. The rule is expected to be finalized and adopted in September 2006.
Act 61 also allows the DPS and PSB to initiate proceedings to adopt alternative forms of regulation for electric utilities that, besides other criteria, establish a reasonably balanced system of risks and rewards to encourage utilities to operate as efficiently as possible. Prior to the law's passage, only an electric utility could initiate an alternative regulation plan proposal. The PSB may only approve an alternative regulation plan if it finds that the plan will not adversely affect eligibility for rate-regulated accounting in accordance with GAAP and reasonably preserves the availability of equity and debt capital resources on favorable terms and conditions. To date, neither the Company nor the regulators have sought to implement an alternate form of regulation for the Company's operations.
RATE DEVELOPMENTS
Vermont Retail Rates
The Company recognizes adequate and timely rate relief is required to maintain its financial strength, particularly since Vermont law does not allow purchased power and fuel costs to be passed on to consumers through purchased power and fuel adjustment clauses. The Company will continue to review costs and request rate increases when warranted.
On April 7, 2004, the PSB issued an order to investigate the Company's retail rates. On July 15, 2004, the Company filed a cost of service study pursuant to the rate investigation, and filed a separate request for a 5.01 percent rate increase, effective April 1, 2005. The Company also requested that the two cases be consolidated; that request was later approved by the PSB.
On February 18, 2005, the PSB approved the Company's request for an Accounting Order that allowed for deferral of 2004 utility earnings in excess of an 11 percent return on equity. Per the Accounting Order, the Company reduced 2004 utility earnings by about $2.3 million after-tax to achieve the 11 percent, and recorded an offsetting pre-tax regulatory liability of $3.8 million to be used or accounted for as the PSB determined in its final order.
Page 8 of 153
On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and the Company's request for a rate increase. The PSB concluded that the Company's rates were higher than was just and reasonable, and must be reduced. In the Rate Order, the PSB determined the annual revenue requirement for the period beginning April 1, 2004, established rates retroactive to April 7, 2004 and established new rates beginning April 1, 2005. The Rate Order included, among other things, the following: 1) a 1.88 percent rate reduction beginning April 1, 2005; 2) a $3.3 million refund to customers; 3) a 10 percent return on equity (reduced from 11 percent); and 4) a requirement that the gain resulting from termination of the power contract related to the 2004 Connecticut Valley sale be applied to the benefit of ratepayers to compensate for increased costs.
The PSB finalized the rate refund and rate reduction amounts in its April 4, 2005 Compliance Order. The rate refund amounted to about $6.5 million pre-tax ($1.7 million is attributed to 2005, $4.5 million is attributed to 2004 and $0.3 million is related to carrying costs). The rate reduction amounted to 2.75 percent ($7.2 million pre-tax on an annual basis). For accounting purposes, the Rate Order resulted in a $21.8 million pre-tax unfavorable effect on utility earnings in the first quarter of 2005. The primary components of the charge to earnings included: 1) a revised calculation of overearnings for the period 2001 - 2003; 2) application of the gain resulting from termination of the power contract with Connecticut Valley to reduce costs; 3) a customer refund for the period April 7, 2004 through March 31, 2005; and 4) amortization of costs and other adjustments required in the Rate Order. These are described in more detail in Item 8, See Note 12 - Retail Rates.
On June 22, 2005, the Company filed an appeal of portions of the Rate Order with the Vermont Supreme Court. On July 11, 2005, the Company filed a docketing statement with the court in which it outlined the issues in its case. The docketing statement describes the ordered payback of earnings from periods prior to the opening of the rate investigation, namely the years 2001 to 2003 and also the first quarter of 2004, when the Company recorded a gain from the Connecticut Valley sale. The issues that were raised on appeal primarily focus on whether the Rate Order set rates retroactively without statutory authorization. On July 27, 2005, the DPS filed a response opposing the Company's position. The Company filed its legal brief and other materials in the case on August 22, 2005. Expedited oral argument occurred on January 31, 2006. The Company expects a Vermont Supreme Court decision on the case in the second or third quarter of 2006. The Company is not able to predict the outcome of this matter at this time.
The Company's August 29, 2005 rate design proposal that it filed in compliance with the Rate Order maintains the Company's overall revenue requirement approved in the Rate Order, but modestly reallocates rate class revenue between some rate classes. The proposal includes a 1 percent rate increase for residential Rates 1 and 8, a 2.99 percent increase in off peak water heating Rates 3 and 14 and a 2.83 percent decrease in general service Rate 2. In addition, the Company's proposal includes lower demand charges and higher energy charges for rate classes with those components, which would be revenue neutral for each rate class. Several Vermont ski areas have intervened, and the Company has participated in several workshops to seek a settlement with all parties. If settlement discussions are not successful, a schedule for hearings will be determined.
Wholesale Rates
The Company provides wholesale transmission service to nine network customers and five point-to-point customers under its FERC Open Access Transmission Service Tariff No. 7, and to four network customers under two FERC rate schedules. One interconnection request is in process under Tariff No. 7. The Company maintains an OASIS site for transmission on the ISO-New England web page. Effective February 1, 2005, Tariff No. 7 was succeeded by ISO-New England FERC Electric Tariff No. 3, Section II - Open Access Transmission Tariff as Schedule 21-CV.
Rochester Electric Light and Power is the only remaining customer taking wholesale power service under Rate R-12 of FPC Electric Tariff, First Revised Volume No. 1. New Hampshire Electric Cooperative, Inc. and Woodsville Fire District Water and Light Department take wholesale power service under FERC Electric Tariff, Original Volume No. 5.
Prior to January 1, 2004, the Company sold firm power to Connecticut Valley under a wholesale rate schedule based on forecast data for each calendar year, which was reconciled to actual data annually. The rate schedule provided for an automatic update of annual capacity rates, as well as a subsequent reconciliation to actual data. The long-term contract under which the Company sold power to Connecticut Valley was terminated by Connecticut Valley as a result of the January 1, 2004 sale. The sale also resolved all Connecticut Valley restructuring litigation in New Hampshire and the Company's stranded cost litigation at FERC. The sale is described in more detail in Part II Item 8, Note 3 - Discontinued Operations.
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Prior to the January 1, 2004 sale, Connecticut Valley's retail rate tariffs were approved by the NHPUC, and contained a Fuel Adjustment Clause and a Purchased Power Cost Adjustment. Under these clauses, Connecticut Valley recovered its estimated annual costs for purchased energy and capacity; these estimates were reconciled annually when actual data was available.
POWER RESOURCES
Overview
The Company's energy generation and purchased power required to serve retail and firm wholesale customers was 2,488,790 mWh for the year ended December 31, 2005, compared to 2,423,227 mWh for the year ended December 31, 2004. The maximum one-hour integrated demand during that period was 412.0 MW, which occurred on July 19, 2005, compared to 426.5 MW, which occurred on December 27, 2004. Total energy generation and purchased power in 2005, including that related to all resale customers, was 3,098,554 mWh.
The following table shows the sources of such energy and capacity available to the Company for the year ended December 31, 2005. For additional information related to purchased power, refer to PART II Item 7, Results of Operations and Power Supply Matters.
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Year Ended December 31, 2005 |
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Net Effective Capability |
Generated and |
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Wholly Owned Plants Diesel and Gas Turbine Jointly Owned Plants Millstone #3 Wyman #4 McNeil Major Long Term Purchases VYNPC Hydro-Quebec Other Purchases System and other purchases Independent power producers NEPOOL (ISO-New England) Total |
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Wholly Owned Plants
The Company's wholly owned plants are located in Vermont, and have a combined nameplate capacity of about 74.2 MW. The Company owns and operates all of these plants which, include: 1) 20 hydroelectric generating facilities with nameplate capacities ranging from a low of about 0.3 MW to a high of about 7.5 MW, for an aggregate nameplate capacity of 45.3 MW; 2) two oil-fired gas turbines with a combined nameplate capacity of 26.5 MW; and 3) one diesel-peaking unit with a nameplate capacity of 2.4 MW.
Jointly Owned Plants
The Company's joint-ownership interests in generating and transmission plants are shown in the table below. The Company is responsible for its share of the operating expenses of these facilities (dollars in thousands).
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In Service Date |
MW Entitlement |
December 31 |
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Wyman #4 |
Oil |
1.7769% |
1978 |
10.8 |
$3,419 |
$3,385 |
The Company receives its share of output and capacity of Millstone Unit #3, a 1,155 MW nuclear generating facility; Wyman #4, a 610 MW generating facility and Joseph C. McNeil, a 54 MW generating facility, as shown in the table above.
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The Highgate Converter, a 225 MW, facility is directly connected to the Hydro-Quebec System to the north of the Converter and to the VELCO System for delivery of power to Vermont utilities. This facility can deliver power in either direction, but normally delivers power from Hydro-Quebec to Vermont.
Major long-term power purchase commitments
Hydro-Quebec The Company is purchasing varying amounts of power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract through 2016. The VJO includes a group of Vermont electric companies and municipal utilities, of which the Company is a participant. The VJO Power Contract has been in place since 1987 and purchases began in 1990. Related contracts were subsequently negotiated between the Company and Hydro-Quebec, which altered the terms and conditions contained in the original contract by reducing the overall power requirements and related costs.
There are specific contractual provisions that provide that in the event any VJO member fails to meet its obligation under the contract with Hydro-Quebec, the balance of the VJO participants, including the Company, will "step-up" to the defaulting party's share on a pro-rata basis. The VJO contract runs through 2020, but the Company's purchases related to the contract end in 2016. As of December 31, 2005, the Company's obligation is about 47 percent of the total VJO Power Contract through 2016, which translates to about $606 million, on a nominal basis. The average annual amount of capacity that the Company will purchase from January 1, 2006 through October 31, 2012 is about 144.7 MW, with lesser amounts purchased through October 31, 2016. See Part II Item 7, and Item 8, Note 13 - Commitments and Contingencies, for additional information regarding the Hydro-Quebec contract.
VYNPC The Company has a 35 percent entitlement in Vermont Yankee plant output sold by Entergy Nuclear Vermont Yankee, LLC ("ENVY") to VYNPC, through a long-term power purchase ("PPA") contract with VYNPC. One remaining secondary purchaser continues to receive a small percentage of the Company's entitlement, reducing its entitlement to about 34.83 percent. The long-term contracts between VYNPC and the entitlement holders and between VYNPC and ENVY became effective on July 31, 2002, the same day that the plant was sold to ENVY. The Company no longer bears the operating costs and risks associated with running the plant or the costs and risks associated with the eventual decommissioning of the plant. ENVY has no obligation to supply energy to VYNPC over the amount the plant is producing, so entitlement holders receive reduced amounts of energy when the plant is operating at a reduced level, and no energy when the plant is not operating.
The PPA through which VYNPC purchases power from ENVY and in turn sells to its sponsors includes prices that range from 3.9 cents to 4.5 cents per kilowatt-hour through March 2012. Effective November 2005, the contract prices are subject to a "low-market adjuster" that protects the Company and its power consumers if power market prices drop significantly. The low-market adjuster is a mechanism in which the PPA base contract price for each billing month is compared to a 12-month average (ending in same billing month) of hourly market prices as defined in the PPA. If the 12-month average market price is less than 95 percent of the base PPA contract price, then 105 percent of the 12-month average market price will be used for the billing month. The low-market adjusted price cannot exceed the base PPA contract price. If market prices rise, however, contract prices are not adjusted upward. In addition to PPA charges, VYNPC's billings to the sponsors include certain of its residual costs of service through a FERC tariff to the VYNPC sponsors.
ENVY has announced that, under current operating parameters, it will exhaust the capacity of its nuclear waste (spent fuel) storage pool in 2007 or 2008 and will need to store nuclear waste in so-called 'dry cask storage' facilities to be constructed on the site. Construction and use of such dry cask storage facilities requires approval from the Vermont State Legislature, in addition to PSB approval. In early June 2005, the Vermont State Legislature passed a law authorizing ENVY to construct and use dry cask storage facilities on the site through its current license. In late June 2005, ENVY filed an application with the PSB for permission to install dry cask storage facilities at the site. At this time the PSB has not ruled on ENVY's application.
If the PSB does not approve dry cask storage, ENVY has announced that it could be required to shut down the Vermont Yankee plant in 2007 or 2008, instead of its current license life of 2012. If the Vermont Yankee plant is shut down, the Company would lose about 50 percent of its committed energy supply and would have to acquire replacement power resources comprising about 40 percent of its estimated power supply needs. Based on projected market prices, the value of the lost output is estimated to be about $55 million on an annual basis. Based on this estimate, the Company would require a retail rate increase of about 20 percent for full cost recovery. The Company
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is not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB will allow timely and full recovery of increased costs related to any such shutdown. The implications of an early shutdown of the Vermont Yankee plant could have a material effect on the Company's financial position and future results of operations, if those costs are not recovered in retail rates in a timely fashion.
Ratepayer Protection Proposal: In March 2004, the PSB approved ENVY's request to increase generation at the Vermont Yankee plant by 110 megawatts. The PSB's approval included a condition that ENVY provide outage protection indemnification ("Ratepayer Protection Proposal" or "RPP") for times the uprate causes reductions in output that reduce the value of the PPA. The Company's maximum right to indemnification under the RPP is about $2.8 million for the three-year period beginning in May 2004 and ending after completion of the uprate (or a maximum of three years).
Plant output has been reduced since the April 2004 scheduled refueling outage, and will continue until ENVY receives NRC approval for the uprate. The Company's entitlement was reduced by an average of about 4 MW during this period. The financial effect of such a reduction will be covered under the terms of the RPP. Additionally, the Company has sought recovery from ENVY, under the RPP, for incremental replacement energy costs incurred when the plant was shut down for 19 days beginning in mid-June 2004. The Company believes the plant went off line due to problems associated with uprate-related improvements made by ENVY, and sought about $0.8 million from ENVY. ENVY contends that the problem would have occurred regardless of the uprate. Having failed to reach a settlement with ENVY, the Company petitioned the PSB for resolution.
There are risks that may not be covered under the RPP. After the Vermont Yankee plant uprating is complete, our percentage of energy output under the PPA would decline proportionately such that we would receive the same quantity of energy from the plant. Four other nuclear plants with steam dryers similar to Vermont Yankee's have experienced problems, and all were required to return to their pre-uprate power level until the problems were corrected. If such a problem were to occur with the Vermont Yankee plant's uprate, it is possible that under the PPA, the Company's entitlement to plant output could be reduced proportionately to the derating until operation is permitted at the post-uprate MW level. While this risk is mitigated in part by additional, controlled testing, during the process of increasing power output, under the supervision of the NRC and DPS, the Company estimates that this could have a material adverse effect on net power costs.
The NRC gave final approval to the uprate on March 2, 2006. If the uprate were to be ultimately unsuccessful, it is also possible that the plant could be shut down earlier than its current licensed life. Any material reduction in output that is not compensated under the terms of the RPP or otherwise by ENVY could have a material impact on the Company's financial position and results of operations, if those increased costs are not recovered in retail rates in a timely fashion.
On March 16, 2006, the Company, Green Mountain Power, ENVY and the DPS filed a settlement with the PSB resolving all issues raised in the petition before the PSB, plus the related derate issue described above. The settlement would resolve all issues through February 28, 2006. The Company's share of the settlement is estimated to be about $1.6 million including $0.7 million related to the June 2004 outage described above and the remaining for uprate-related costs. Pursuant to the Rate Order, any partial or full reimbursement received by the Company from ENVY under the RPP shall be recorded as a regulatory liability for return to ratepayers in the Company's next rate proceeding. The settlement is not effective until the PSB issues a final order. The Company cannot predict the timing or outcome of this matter at this time.
Also see Part II Item 7, and Item 8, Note 13 - Commitments and Contingencies, for additional information regarding VYNPC.
Other Purchases
Cogeneration/Independent Power Qualifying Facilities The Company purchases power from several Independent Power Producers ("IPPs") who own qualifying facilities under the Public Utilities Regulatory Policies Act of 1978. These facilities primarily use water and biomass as fuel. Most of the power comes through a state-appointed purchasing agent, which assigns power to all Vermont utilities under PSB rules. In 2005, total IPP purchases accounted for 6.0 percent of the Company's total mWh purchased and 13.2 percent of purchased power costs. See Part II Item 8, Note 13 - Commitments and Contingencies, for additional information.
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NEPOOL and ISO-New England The Company is a participant in the New England Power Pool ("NEPOOL"), a regional bulk power transmission organization established to assure reliable and economical power supply in the Northeast United States. NEPOOL has been open to all investor-owned, municipal, and cooperative utilities in New England under an agreement in effect since 1971 and amended from time to time. The Restated NEPOOL Agreement offers membership privileges to any entity engaged or proposing to engage in the wholesale or retail electric power business in New England. NEPOOL continues to exist as the entity representing not only traditional electric utilities but companies that participate in the competitive wholesale electricity marketplace. A not-for-profit organization, New England Independent System Operator ("ISO-New England"), was established in July 1997, following FERC approval, and immediately assumed responsibility for the management of the New England region's power grid and transmission systems and administration of the region's open access tariff. ISO-New England was formed by transferring staff and equipment from NEPOOL to the new organization. ISO-New England has a service contract with NEPOOL to operate the bulk power system and to administer the wholesale marketplace.
Beginning May 1, 2004, the Company began to settle its power accounts with ISO-New England on a standalone (direct) basis. Up until this time, all Vermont utilities were settled at ISO-New England, and VELCO then performed the settlement for each utility in Vermont. With changes in power markets and NEPOOL/ISO rules and procedures, many of the benefits of a single Vermont settlement have disappeared, and direct settlement now provides advantages to the Company in terms of efficiency and cost savings. Hourly purchases and sales through ISO-New England are described in Short-term Purchases and Sales below.
ISO-New England is governed by FERC, under rules defined by NEPOOL and approved by FERC. These rules include providing independent, open and fair access to the regional transmission system, establishing a non-discriminatory governance structure, facilitating market-based wholesale electric transactions, and ensuring efficient management and reliable operation of the regional bulk power system. In March 2003, ISO-New England moved to SMD, a significant step to restructuring the wholesale energy markets in the Northeast.
NEPOOL's peak for 2005 occurred on July 27, 2005 and totaled 26,885 MW. The Company's peak demand occurred on July 19, 2005 and totaled 412 MW, and the Company had a reserve margin of about 19.04 percent at the time.
Short-term Purchases and Sales The Company engages in short-term purchases and sales in the wholesale markets administered by ISO-New England and with other third parties, primarily in New England, to minimize net power costs and risks to its customers. Such short-term purchases and sales are not considered energy trading activities. The Company enters into forward purchase contracts when additional supply is needed and enters into forward sale contracts when it forecasts excess supply. On an hourly basis, power is sold or bought through ISO-New England's settlement process to balance the Company's resource output and load requirements. On a monthly basis, the Company aggregates the hourly sales and purchases through ISO-New England and records them as Operating Revenue or Purchased Power, respectively.
Power Resources - Future
The Company's long-term power forecast shows energy purchase and production amounts in excess of load requirements in most periods through 2011. Because of this general surplus, the Company enters into forward sale transactions from time to time to reduce price volatility of forecasted net power costs. At times, such as when Vermont Yankee is not operating, the Company may also enter into forward purchase transactions.
In November 2004, the Company entered two separate forward sale transactions, one through October 2006 for an average of about 37 MW per hour and another through December 2008 for an average of about 15 MW. Delivery under the first contract is contingent on Vermont Yankee output, eliminating the risks of sourcing the sale when Vermont Yankee is not operating. The Company expects that any future forward sales will also be contingent on Vermont Yankee output, or will be for relatively small volumes.
Based on existing commitments and contracts, the Company expects that net purchased power and production fuel costs will average $124 million per year for the years 2006 through 2010. These projections are dependent, in part, on wholesale power market prices. Because of the Company's excess supply, increases in the wholesale price should generally reduce net power costs, while decreases should generally increase costs. Our power contract with
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VYNPC for purchase of Vermont Yankee plant output ends in March 2012, and deliveries under the Hydro-Quebec contract are reduced significantly in 2012. These contracts supported about 84 percent of our total energy (mWh) purchases in 2005.
Also see Regulation and Competition - New Developments above for discussion of Act 61, Renewable Energy, Efficiency, Transmission and Vermont's Energy Future.
Derivative Financial Instruments
The Company accounts for various power contracts as derivatives under the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted and SFAS No. 149, Amendment of Statement 133 Derivative Instruments and Hedging Activities, (collectively "SFAS No. 133"). These statements require that derivatives be recorded on the balance sheets at fair value.
The Company's long-term contracts for the purchase of power from VYNPC and Independent Power Producers do not meet the definition of a derivative under the requirements of SFAS No. 133 because delivery of power under these contracts is contingent on plant output. Additionally, the Company's long-term power contract with Hydro-Quebec does not meet the definition of a derivative because there is no defined notional amount.
The Company has a long-term purchased power contract that allows the seller to repurchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative under SFAS No. 133. The derivative's estimated fair value was an unrealized loss of $5.0 million at December 31, 2005 and $5.7 million at December 31, 2004. The estimated fair value of this derivative is valued using a binomial tree model, and quoted market data when available along with appropriate valuation methodologies.
The Company has a long-term forward sale contract for the sale of about 15 MW per hour, or a total of 522,544 mWh, beginning November 17, 2004 through December 31, 2008. As of December 31, 2005 about 141,800 mWh have been delivered under the contract. This contract has been determined to be a derivative under SFAS No. 133. The Company utilizes over-the-counter quotations or broker quotes at the end of the reporting period for determining the fair value of this contract. The derivative's estimated fair value was an unrealized loss of $12.9 million at December 31, 2005 and a $0.4 million unrealized gain at December 31, 2004.
The Company records derivative contracts on the balance sheet at fair value. Based on a PSB-approved Accounting Order, the Company records the change in fair value of these derivatives as deferred charges or deferred credits, depending on whether the fair value is an unrealized loss or gain. The corresponding offsets are recorded as current and long-term assets or liabilities depending on the duration.
NUCLEAR DECOMMISSIONING COSTS
The Company has a 1.7303 percent joint-ownership interest in Millstone Unit #3. The Company is one of several sponsor companies with ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic, and is responsible for paying its ownership percentage of decommissioning and all other costs for each plant. These companies have permanently shut down generating activities and are conducting decommissioning activities. The Company's obligations related to the eventual decommissioning of the Vermont Yankee plant ceased when the plant was sold to Entergy on July 31, 2002.
Millstone Unit #3 As a joint owner of the Millstone Unit #3 facility, in which Dominion Nuclear Corporation ("DNC") is the lead owner with about 93.47 percent of the plant joint-ownership, the Company is responsible for its share of nuclear decommissioning costs. The Company has an external trust dedicated to funding its joint-ownership share of future decommissioning costs. DNC has suspended contributions to the Millstone Unit #3 Trust Fund because the minimum NRC funding requirements are being met or exceeded. The Company has also suspended contributions to the Trust Fund, but could choose to renew funding at its own discretion as long as the minimum requirement is met or exceeded. If a need for additional decommissioning funding is necessary, the Company will be obligated to resume contributions to the Trust Fund.
In January 2004, DNC filed, on behalf of itself and the two minority owners, including the Company, a lawsuit against the DOE seeking recovery of costs related to storage of spent nuclear fuel arising from the failure of the DOE to comply with its obligations to commence accepting such fuel in 1998. The schedule for further proceedings in the lawsuit is not known at this time. Millstone Unit #3 spent fuel from the beginning of commercial operations in
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1986 resides in the spent fuel pool. The Company continues to pay its share of the DOE Spent Fuel assessment expenses levied on actual generation and will share in recovery from the lawsuit, if any, in proportion to its ownership interest. On November 28, 2005, the NRC renewed the operating license for Millstone Unit #3 for an additional 20 years. This extends the licensed life from November 2025 to November 2045.
Maine Yankee, Connecticut Yankee and Yankee Atomic
Maine Yankee, Connecticut Yankee and Yankee Atomic collect decommissioning and closure costs through FERC-approved wholesale rates charged under power agreements with several New England utilities, including the Company. Information related to decommissioning and closure costs, including the Company's share of estimated future payments for each plant, follows (dollars in millions):
|
Date of Study |
Total |
Remaining Obligation (b) |
Revenue Requirements (c) |
Company Share (d) |
|
|
Maine Yankee |
2003 |
$522.8 |
$144.0 |
$241.3 |
$4.8 |
|
(a) Total cumulative decommissioning expenditures incurred through 2005, net of proceeds received from |
|||||
|
(b) Estimated remaining decommissioning costs in 2005 dollars for the period 2006 through 2023 for |
|||||
|
(c) Estimated future payments required by Sponsor companies to recover estimated decommissioning and |
|||||
|
(d) The Company's share of revenue requirements based on its ownership percentage of each plant. |
|||||
The Company's share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Consolidated Balance Sheets as regulatory assets and nuclear decommissioning liabilities (current and non-current). These amounts are adjusted when revised estimates are provided by the companies. At December 31, 2005, the Company had regulatory assets of about $4.8 million related to Maine Yankee, $10.3 million related to Connecticut Yankee and $5.9 million related to Yankee Atomic (including about $0.7 million for incremental decommissioning costs already paid by the Company that are now being recovered in retail rates pursuant to the Rate Order). These estimated costs are being collected from the Company's customers through existing retail rate tariffs. Pursuant to the Rate Order, beginning April 1, 2006, the Company will defer any differences between actual decommissioning cost payments and amounts included for rate recovery, until its next rate proceeding.
Historically, the Company's share of these costs has been recovered from its retail customers through PSB-approved rates. Based on the regulatory process, Management believes its share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process. There is a risk, however, that FERC may not allow full recovery of Connecticut Yankee's increased costs in wholesale rates as described below.
The following is a summary of the status of activities at each of the plants. See Note 2 - Investments in Affiliates for additional information.
Department of Energy ("DOE") Litigation: Maine Yankee, Connecticut Yankee and Yankee Atomic are seeking recovery of fuel storage-related costs stemming from the default of the DOE under the 1983 fuel disposal contracts that were mandated by the United States Congress under the Nuclear Waste Policy Act of 1982. On September 9, 2005, the United States Court of Appeals for the Federal Circuit issued a decision involving another nuclear utility's spent fuel that, among other things, found plaintiffs in "partial breach" cases, such as Maine Yankee, Connecticut Yankee and Yankee Atomic, were not entitled to future damages. The date or event beyond which damages were to be considered "future damages" was not clarified by the Court. The ruling does not bar a plaintiff from seeking future damages in subsequent proceedings after the damages have been incurred. In response to the trial judge's request for supplemental briefing on the impact of the future-damages ruling, Maine Yankee, Connecticut Yankee and Yankee Atomic contended that the Court should award damages through 2002 initially and direct the parties to promptly pursue additional proceedings for recovery of post-2002 incurred damages. The DOE contended that all
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three companies could recover damages in the ongoing proceeding only through the date when they filed suit in June 1998. On February 28, 2006, all three companies asked the Court to allow amended damage claim filings to cover the period ending December 31, 2002. The proposed amended damage claims are about $79 million for Maine Yankee, $82.8 million for Connecticut Yankee and $101.8 million for Yankee Atomic. This compares to original claims of $160 million for Maine Yankee, $197.1 million for Connecticut Yankee and $191 million for Yankee Atomic. Due to the complexity of the issues and the possibility of appeals, the three companies cannot predict the amount of damages to be received or the timing of the final determination of such damages. None of the companies have included any allowance for potential recovery of these claims in their FERC-filed cost estimates.
Maine Yankee: The Company has a 2 percent ownership interest in Maine Yankee. Beginning November 1, 2004, Maine Yankee's billings to sponsor companies have been based on its September 16, 2004 FERC-approved settlement, which provides for recovery of Maine Yankee's forecasted costs of providing service through a formula rate contained in its power contracts through October 31, 2008 and replenishment of the DOE Spent Fuel Obligation through collections from November 2008 through October 2010. On October 3, 2005, Maine Yankee completed its decommissioning efforts and the Nuclear Regulatory Commission ("NRC") amended its operating license for operation of the Independent Spent Fuel Storage Installation.
In October 2005, Maine Yankee provided an updated forecast for ongoing costs which reflects an estimated increase of about $10.1 million. The increase is primarily related to higher-than-expected interest expense. The Company's share of these estimated increased costs is about $0.2 million.
Connecticut Yankee: The Company has a 2 percent ownership interest in Connecticut Yankee. Costs billed by Connecticut Yankee are based on FERC-filed rates effective February 1, 2005 for collection through 2010. Before February 1, 2005 costs were based on FERC-approved rates that became effective September 1, 2000 for collection through 2007. Connecticut Yankee is involved in a contract dispute and a FERC rate case filing as described below.
Bechtel Litigation: On February 27, 2006, Connecticut Yankee and Bechtel participated in a mediation process related to a contract dispute that resulted in default termination of the decommissioning services contract between Connecticut Yankee and Bechtel effective July 2003. On March 7, 2006, Connecticut Yankee and Bechtel entered a settlement, the material terms of which are: the litigation shall be terminated by dismissals with prejudice of all claims and counterclaims, with each party bearing its own costs; Bechtel shall release all liens, garnishments and attachments that it has obtained against Connecticut Yankee assets; Bechtel shall petition FERC to withdraw its intervention in the Connecticut Yankee rate case; the parties shall exchange mutual general releases including releases of Connecticut Yankee shareholders and their affiliates; Bechtel shall pay Connecticut Yankee the sum of $15.0 million; and Connecticut Yankee shall withdraw its termination of the decommissioning contract for default, and the contract shall be deemed terminated by agreement. At this time, the Company cannot predict the effect, if any, this settlement will have related to the FERC litigation described below. To the extent any amounts of the settlement payment are ultimately returned to the Company, these amounts will be credited for the future benefit of retail ratepayers.
FERC Rate Case Filing: In December 2003, Connecticut Yankee established an updated estimate of decommissioning and plant closure costs for the period 2000 through 2023 ("2003 Estimate"). The 2003 Estimate of about $831 million represents an aggregate increase of about $395 million compared to the cost estimate in Connecticut Yankee's 2000 FERC rate case settlement (stated in 2003 dollars). In the Filing, Connecticut Yankee sought to increase its annual decommissioning collections from $16.7 million to $93 million through 2010 beginning January 1, 2005. The CT DPUC and Bechtel intervened in this rate case, and both filed testimony in the FERC proceeding claiming that Connecticut Yankee was imprudent in its management of the decommissioning project.
On November 22, 2005, the ALJ issued an Initial Decision that found: there was no evidence of Connecticut Yankee imprudence. The only adjustment to Connecticut Yankee's decommissioning charges required by the Initial Decision relates to the escalation rate, which is the factor used to translate the 2003 Estimate (stated in 2003 dollars) into spending projections and decommissioning charges. The Initial Decision found that Connecticut Yankee should recalculate its decommissioning charges to reflect a lower escalation rate. The Initial Decision is subject to review by FERC.
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The Company continues to believe that FERC will approve recovery of Connecticut Yankee's increased costs in wholesale rates based on the nature of costs and previous rulings at other nuclear companies. Once approved by FERC, the Company believes it is unlikely that the PSB would not allow these FERC-approved costs to be recovered in retail rates. However, there is a risk, notwithstanding the ALJ Initial Decision, that some portion of the increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings. If FERC disallows cost recovery in wholesale rates, the Company anticipates that the PSB would disallow these costs for recovery in retail rates as well. The timing, amount and outcome of the FERC rate case filing cannot be predicted at this time.
Yankee Atomic: The Company has a 3.5 percent ownership interest in Yankee Atomic. Costs billed by Yankee Atomic are based on a November 23, 2005 FERC filing primarily to recover increased costs associated with remediation of non-hazardous and hazardous waste volumes in excess of estimates in the previously concluded rate case. Prior to this filing, costs billed by Yankee Atomic were based on its April 4, 2003 FERC-approved rate filing. The decommissioning effort is largely complete and final site-work is expected to conclude in 2006. Following the completion of decommissioning, the remaining on-site function will be to operate the Independent Spent Fuel Storage Installation.
On November 23, 2005, Yankee Atomic submitted an application to FERC for increased decommissioning charges based on its updated estimate of costs of completing the decommissioning effort. Yankee Atomic proposed to collect decommissioning charges of about $54.9 million in 2006 and $23.5 million annually for 2007 through 2010. This compares to previously scheduled annual charges of about $12.8 million for 2006 through 2010. Hearings on the FERC rate case began in December 2005, and several parties including the DPS filed motions to intervene and protest. On January 1, 2006, FERC issued an Order: 1) accepting Yankee Atomic's rate filing; 2) permitting the proposed rates to go into effect, subject to refund, as of February 1, 2006; and 3) referring the parties to a settlement judge to facilitate a possible settlement. The Company's share of the rate increase amounts to about $1.5 million for 2006 and $0.4 million annually for 2007 through 2010.
Nuclear Liability and Insurance
The Price-Anderson Act ("Act") currently limits public liability from a single incident at a nuclear power plant to about $10 billion. The Act has been renewed five times since it was first enacted in 1957, and expired in August 2003. The Energy Policy Act of 2005, enacted in August 2005, extends the Act for 20 years and provides a framework for immediate, no-fault insurance coverage for the public in the event of a nuclear reactor accident. The Act consists of two levels of coverage. The primary level provides liability insurance coverage of $300 million. If this amount is not sufficient to cover claims arising from an accident, the second level, referred to as secondary financial protection, applies. For the second level, each nuclear plant must pay a retrospective premium equal to its proportionate share of the excess loss, up to a maximum of $95.8 million per reactor per incident, limited to a maximum annual assessment of $15 million. These assessments will be adjusted for inflation. Currently, based on its joint-ownership interest in Millstone Unit #3, the Company could become liable for about $0.3 million of such maximum assessment per incident per year. The Maine Yankee, Connecticut Yankee and Yankee Atomic plants have received exemptions from participating in the secondary financial protection program under the Act.
TRANSMISSION
VELCO
VELCO engages in the operation of a high-voltage transmission system, which interconnects electric utilities in the State, including areas served by the Company. VELCO provides transmission services for the State of Vermont, acting by and through the DPS, and for all of the electric distribution utilities in the State of Vermont. VELCO is reimbursed for its costs (as defined in the agreements relating thereto) for transmission of power for such entities. The Company, as the largest electric distribution utility in Vermont, is the major user of VELCO's transmission system.
The Company owns 48.5 percent of VELCO's outstanding Class B voting common stock, 31.45 percent of VELCO's outstanding Class C non-voting common stock (approved by the FERC on July 15, 2002), and 48.03 percent of VELCO's outstanding Class C preferred stock. Shares of Class C preferred stock have no voting rights except the limited right to vote VELCO's shares of common stock in VETCO if certain dividend requirements are not met.
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NEPOOL Arrangements
VELCO is a participant with all of the major electric utilities in New England in NEPOOL, acting for itself and as agent for the Company and 21 other Vermont utilities. The generating and transmission facilities of all of the participants are coordinated on a New England-wide basis through a central dispatching agency to assure their operation and maintenance in accordance with proper standards of reliability, and to attain the maximum practicable economy for all of the participants through the interchange of economy and emergency power.
On March 24, 2004, FERC conditionally approved the filing made by ISO-New England and the New England transmission owners to create a Regional Transmission Organization ("RTO") for New England. The RTO parties submitted a compliance filing to FERC in December 2004, and the RTO began operating on February 1, 2005. Currently, about one-third of the cost of New England's existing and new high-voltage transmission system (115 kV looped facilities), Pool Transmission Facility ("PTF"), is shared by all New England utilities, and by 2008 all of the PTF costs will be shared. Under the RTO, Highgate and related facilities, owned by a number of Vermont utilities and VELCO, are classified as Highgate Transmission Facility ("HTF") with a five-year phase-in of Regional Network Service ("RNS") reimbursement treatment. At the end of the phase-in period, the Company's net cost for Highgate will be based on our NEPOOL load ratio (about 2 percent) rather than our 46 percent ownership share of the facilities.
At this time, VELCO is planning several significant upgrades, portions of which have been approved by NEPOOL for shared cost treatment in New England-wide rates for transmission services, including the so-called Northwest Reliability Project ("NRP"). The estimated cost of the NRP is about $228 million, including a 15 percent contingency, which represents a $78 million increase from the original estimate that was completed in early 2003. Citing the cost increase, certain interveners asked the PSB to reopen the proceeding in which VELCO received the overall Certificate of Public Good for the NRP. The PSB declined to reopen the proceeding, and the Vermont Supreme Court subsequently denied certain interveners request for an appeal.
Although the RTO cost-sharing approach will limit the Company's costs related to Vermont transmission upgrades, the Company will also be required to pay a share of projects undertaken to support region-wide reliability elsewhere in New England. The net economic effect on the Company is expected to be beneficial, as the sharing approach provides cost and reliability benefits in providing service to customers, because the Company's load share is a small fraction of New England's load, and the facilities upgrades VELCO is planning improve the reliability and efficiency of the transmission network. Certain future transmission facilities will not qualify for cost sharing, and those costs will be charged locally rather than regionally; the Company's share of such costs will be affected by FERC-approved cost-allocation process contained in VELCO's and the Company's tariffs and agreements.
In addition to the NRP, VELCO is working with the Company on a project to solve load serving and reliability issues related to a 46-kV transmission line extending from Bennington to Brattleboro, Vermont, referred to by the Company as the Southern Loop. It serves about 25 percent of the Company's load. The Company is evaluating alternatives to resolve the Southern Loop issues, including significant upgrades to the transmission system as well as non-transmission alternatives. Certain alternatives would provide regional reliability benefits and therefore some of the upgrades could be eligible for cost sharing on a New England-wide basis under the current regional tariff. The estimated total cost of these system upgrades ranges from $70 million to $110 million with construction likely to begin on some components of the project in 2007 or 2008. In October 2005, the Company initiated a public involvement process to gain input on how best to improve and ensure reliable electric service in southern Vermont. A Utility Search Conference was held in southern Vermont at the end of January 2006. The participants identified public preferences for solutions and processes to solve the Southern Loop problems. The Company and VELCO accepted the public recommendations and agreed to work with a smaller community working group to develop ideas and implement solutions.
Capitalization
At December 31, 2005, VELCO has authorized 430,000 shares of Class B common stock, $100 par value, of which 219,977 shares were outstanding; 20,000 shares of Class C common stock, $100 par value, of which 19,901 were outstanding; and 125,000 shares of Class C preferred stock, $100 par value, of which 97,068 shares were outstanding. In addition, four issues of First Mortgage Bonds, aggregating $58,521,000 issued under an Indenture of Mortgage dated as of September 1, 1957, as amended, between VELCO and Deutsche Bank Trust Company Americas, as Trustee (the "VELCO Indenture") were authorized and outstanding at December 31, 2005. The issuance of bonds under the VELCO Indenture is unlimited in amount but is subject to certain restrictions.
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Management
The Company and GMP entered into a Three-Party Transmission Agreement, dated November 21, 1969. Under this Agreement, as amended, the Company and GMP agreed to pay transmission charges in an aggregate amount sufficient, with VELCO's other revenues, to pay all of VELCO's expenses including capital costs. VELCO's Bonds are secured by a first mortgage on the major part of VELCO's transmission properties and by the assignment to the Trustee of the Three-Party Agreement, the Three-Party Transmission Agreement and certain other contracts as specified in the VELCO Indenture.
VELCO operated pursuant to the terms of the 1985 Four-Party Agreement (as amended) with the Company and two other major distribution companies in Vermont, which provided that although the Company owned the majority of voting stock of VELCO, it would not exercise its voting rights to assert control, and also provided the utilities with an option to purchase VELCO assets. The Company no longer owns a majority of the voting stock of VELCO and the 1985 Four-Party Agreement, including the option to purchase assets, has been allowed to terminate without renewal.
VETCO
In connection with importing Canadian power, VELCO created a wholly owned subsidiary, VETCO, to construct, finance, own and operate the Vermont portion of the transmission line that connects the Hydro-Quebec lines at the Canadian border to lines of New England Electric Transmission Corporation, a subsidiary of National Grid USA, formerly New England Electric System, at the New Hampshire border on the Connecticut River. VETCO entered into a Capital Funds Agreement with VELCO pursuant to which VETCO may request up to $12,500,000 (of which $10,000,000 was contributed as of December 31, 2005) of capital contributions from VELCO. VETCO also entered into Transmission Line Support Agreements with 20 New England utilities, including VELCO as representative for 14 Vermont utilities, pursuant to which those utilities have agreed to pay the transmission line costs, whether or not the line is operational. VELCO, as representative, has entered into a similar agreement with New England Electric Transmission Corporation with respect to the New Hampshire portion of the DC transmission line and the DC/AC converter station. Pursuant to a Vermont Participation Agreement and a Capital Funds Support Agreement with VELCO and 14 Vermont electric distribution utilities, including the Company, assume their pro rata share (based upon 1980 sales) of the benefits and obligations of VELCO under the Support Agreements and the VETCO Capital Funds Agreement.
VETCO has authorized 10 shares of common stock, $100 par value, which were outstanding on December 31, 2005 and owned by VELCO, with each share having one vote. During 1986 VETCO paid off its construction financing by issuing $37,000,000 of secured notes, maturing in 2006, and receiving a $9,999,000 equity contribution from VELCO. The notes are secured by a First Mortgage on the major part of VETCO's transmission properties and by the assignment of its rights under the Support Agreements.
Phase I and Phase II
The Company participated with other electric utilities in the construction of the Phase I Hydro-Quebec interconnection transmission facilities in northeastern Vermont, which were completed at a total cost of about $140 million. Under a support agreement relating to participation in the facilities, the Company is obligated to pay its 4.55 percent share of Phase I Hydro-Quebec capital costs over a 20-year recovery period ending in 2006. The Company also participated in the construction of Phase II Hydro-Quebec transmission facilities constructed throughout New England, which were completed at a total cost of about $487 million. Under a similar support agreement, the New England participants, including the Company, contracted to pay their proportionate share of the total cost of constructing, owning and operating the Phase II facilities, including capital costs. The Company is obligated to pay its 5.132 percent share of Phase II Hydro-Quebec capital costs over a 25-year recovery period ending in 2015. These agreements meet the capital lease accounting requirements under SFAS No. 13, Accounting for Leases. All costs under these agreements are recorded as purchased transmission expense in accordance with the Company's ratemaking policies. Future expected payments will range from about $3.2 million to $2.7 million annually from 2006 through 2015 and will decline thereafter. Approximately $0.6 million of the annual costs are reimbursed to the Company pursuant to the NEPOOL Open Access Transmission Tariff.
ENERGY CONSERVATION AND LOAD MANAGEMENT
The primary purpose of Conservation and Load Management programs is to offset need for long-term power supply and delivery resources that are more expensive to purchase or develop than customer-efficiency programs, including unpriced external factors such as emissions and economic risk.
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The Vermont Energy Efficiency Utility ("EEU"), created by the State of Vermont, began operation in January 2000. The Company has a continuing obligation to provide customer information and referrals, coordination of customer service, power quality, and any other distribution utility functions, which may intersect with the EEU's utility activities.
The Company has retained the obligation to deliver demand side management programs targeted at deferral of its transmission and distribution projects, known as Distributed Utility Planning ("DUP"). DUP is designed to ensure that delivery services are provided at least cost and to create the most efficient transmission and distribution system possible. An initial set of rules for DUP was filed by the parties in Docket No. 6290 as a Memorandum of Understanding, which was approved by the PSB on January 15, 2003. It includes: 1) an energy efficiency screening tool; 2) an agreement on default planning assumptions that are subject to modification semi-annually as well as changes to fit specific area conditions; 3) continued collaboration of the parties to update the rules as necessary and to share information; and 4) the creation of ongoing area specific collaboratives ("ASC") to examine resource investment options, including the possible use of distributed generation, energy conservation and load management, to resolve the Company's potentially constrained transmission or distribution areas. The Company has been participating in five such ASCs.
The PSB is currently reviewing the EEU's budget level and its policies that determine where investments are made as required by legislation enacted. The PSB is also examining the role of energy efficiency to defer statewide transmission upgrades in Docket 7081. Docket 7081 was established as part of the PSB Order approving VELCO's Northwest Reliability Project described above.
DIVERSIFICATION
CRC's wholly owned subsidiary, Eversant Corporation, engages in the sale or rental of electric water heaters through a wholly owned subsidiary, SmartEnergy Water Heating Services, Inc. to customers in Vermont and New Hampshire.
On December 20, 2005, CRC sold all of its interest in Catamount to Diamond Castle. Cash proceeds from the sale amounted to $59.25 million, resulting in an after-tax gain of $5.6 million. See Part II, Item 8, Note 3 - Discontinued Operations.
EMPLOYEE INFORMATION
Local Union No. 300, affiliated with the International Brotherhood of Electrical Workers, represents operating and maintenance employees of the Company. On December 31, 2005 the Company had 529 employees, of which 218 are represented by the union. On December 29, 2004, the Company and its employees represented by the union agreed to a new four-year contract, which expires on December 31, 2008. The new contract provided for a net general wage increase of 3.5 percent effective January 2, 2005, January 1, 2006, December 31, 2006 and December 30, 2007. It also included an increase in the Company's 401K match from 4 to 4.25 percent of eligible compensation beginning January 1, 2007.
SEASONAL NATURE OF BUSINESS
The Company's kilowatt-hour sales and revenues are typically higher in the winter and summer than in the spring and fall, as sales tend to vary with weather. Winter recreational activities, longer hours of darkness and heating loads from cold weather contribute to higher sales in the winter, while air conditioning generates higher sales in the summer. Consumption is least in the spring and fall, when there is little heating or cooling load.
CAPITAL EXPENDITURES
The Company's capital expenditures totaled about $17.6 million in 2005, $20.2 million in 2004 and $15 million in 2003. The Company's capital expenditures are expected to range from $40 million to $50 million for the two-year period between 2006 and 2007. This estimate is subject to continuing review and adjustment and actual capital expenditures may vary from this estimate.
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OFFICERS
The following sets forth the present Executive Officers of the Company. There are no family relationships among the executive officers. The term of each officer is for one year or until a successor is elected. Officers are normally elected annually.
Executive officers of the registrant:
|
Name and Age |
Office |
Officer Since |
|
Robert H. Young, 58 |
President and Chief Executive Officer |
1987 |
|
William J. Deehan, 53 |
Vice President - Power Planning and Regulatory Affairs |
1991 |
|
Joan F. Gamble, 48 |
Vice President - Strategic Change and Business Services |
1998 |
|
Joseph M. Kraus, 50 |
Senior Vice President - Operations, Engineering and Customer Service |
1987 |
|
Dale A. Rocheleau, 47 |
Senior Vice President for Legal and Public Affairs, and Corporate Secretary |
2003 |
|
Edmund F. Ryan, 48 |
Acting Chief Financial Officer and Treasurer |
2005 |
Mr. Young joined the Company in 1987. He was elected Senior Vice President - Finance and Administration in 1988. He served as Executive Vice President and Chief Operating Officer (COO) commencing in 1993 and was elected Director, President and Chief Executive Officer (CEO) commencing in 1995. Mr. Young also serves as President, CEO, and Chair of the following CVPS subsidiaries: Connecticut Valley Electric Company Inc.; CVPSC - East Barnet Hydroelectric, Inc.; CV Realty, Inc.; Custom Investment Corporation; Catamount Resources Corporation; Eversant Corporation; AgEnergy, Inc.; and, SmartEnergy Water Heating Services, Inc. He is also Director of the following CVPS affiliates: Vermont Electric Power Company, Inc., Vermont Yankee Nuclear Power Corporation; Vermont Electric Transmission Company, Inc.; and, The Home Service Store, Inc.
Mr. Deehan joined the Company in 1985. Prior to being elected to his present position in May 2001, he served as Vice President - Regulatory Affairs and Strategic Analysis. He previously served as Assistant Vice President - Rates and Economic Analysis from April 1991 to May 1996.
Ms. Gamble joined the Company in 1989. Prior to being elected to her present position in August 2001, she was Director of Marketing Research & Planning from 1989 to 1996; Director of Strategic and Policy Planning from 1996 to September 1997; Director of Human Resources and Strategic Planning from September 1997 to May 1998; and, Assistant Vice President Human Resources and Strategic Planning from May 1998 to May 2000. She previously served as Vice President - Human Resources and Strategic Planning from May 2001 to August 2001. Ms. Gamble also serves as Vice President - Strategic Change and Business Services for the following CVPS subsidiary: Eversant Corporation. She serves as a Director for the following CVPS subsidiaries: Eversant Corporation; AgEnergy, Inc.; and, SmartEnergy Water Heating Services, Inc.
Mr. Kraus joined the Company in 1981. Prior to being elected to his present position of Senior Vice President Operations, Engineering and Customer Service, he served as Senior Vice President Engineering and Operations, General Counsel, and Secretary from May 2003 until November 2003. He previously served as Senior Vice President Customer Service, Secretary, and General Counsel from May 2001 to May 2003 and he served as Vice President, Corporate Secretary, and General Counsel commencing in 1996 and Corporate Secretary and General Counsel commencing in 1994. He previously served as Senior Vice President, Corporate Secretary, and General Counsel from 1999 to May 2001. Mr. Kraus serves as Director of the following CVPS subsidiaries: Connecticut Valley Electric Company Inc.; CVPSC - East Barnet Hydroelectric, Inc.; CV Realty, Inc.; Custom Investment Corporation; Catamount Resources Corporation; Eversant Corporation; AgEnergy, Inc.; and, SmartEnergy Water Heating Services, Inc.
Mr. Rocheleau joined the Company in November 2003 as Senior Vice President for Legal and Public Affairs, and Corporate Secretary. Prior to joining the Company, he served as Director and Attorney at Law from 1992 to 2003 with Downs Rachlin Martin, PLLC. Mr. Rocheleau serves as Director, Senior Vice President for Legal and Public
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Affairs and Corporate Secretary of the following CVPS subsidiaries: Connecticut Valley Electric Company Inc.; CVPSC - East Barnet Hydroelectric, Inc.; CV Realty, Inc.; Custom Investment Corporation; Catamount Resources Corporation; Eversant Corporation; AgEnergy, Inc.; and, SmartEnergy Water Heating Services, Inc.
Mr. Ryan joined the Company in 2003. Prior to being appointed to his present position of Acting Chief Financial Officer and Treasurer, he served as the Director of Internal Audit from August 2003 to October 2005. He previously served as Controller at The Home Service Store, Inc., a CVPS affiliate, from May 2000 to August 2003. Mr. Ryan serves as Director, Acting Chief Financial Officer, and Treasurer of the following CVPS subsidiaries: Connecticut Valley Electric Company Inc.; CVPSC - East Barnet Hydroelectric, Inc.; CV Realty, Inc.; Custom Investment Corporation; Catamount Resources Corporation; Eversant Corporation; AgEnergy, Inc.; and, SmartEnergy Water Heating Services, Inc.
Item 1A. Risk Factors
We regularly identify, monitor and assess our exposure to risk and seek to mitigate the risks inherent in our energy business. However, there are risks that are beyond our control or that cannot be limited cost-effectively or that may occur despite our risk mitigation strategies. The risk factors discussed below could have a material effect on our financial position, results of operations or cash flows.
Risks related to timing and adequacy of rate relief: We are regulated by the PSB, the Connecticut Department of Public Utility Control and FERC, with respect to rates charged for service, accounting, financing and other matters pertaining to regulated operations. Electric utilities are subject to certain accounting standards that apply only to regulated businesses. We prepare our financial statements in accordance with Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"), for our regulated Vermont service territory and FERC-regulated wholesale business. If we determine that we no longer meet the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $36.1 million on a pre-tax basis as of December 31, 2005, assuming no stranded cost recovery would be allowed through a rate mechanism. We would also be required to determine any impairment to the carrying costs of deregulated plant.
While Vermont does not have a fuel or power adjustment clause, the PSB has previously approved deferral of extraordinary costs incurred that might normally be expensed by unregulated businesses in order to match these expenses with future revenues. Fair regulatory treatment is fundamental to maintaining our financial stability. Rates must be set at levels to recover costs, including a market rate of return to equity and debt holders in order to attract capital.
Risks related to our current credit rating, which is below investment grade: In June 2005, Standard & Poor's Ratings Services ("S&P") lowered our corporate credit rating to below investment grade. Fitch also lowered its ratings on our senior secured debt and preferred stock. According to both agencies, these actions were taken primarily as a result of the Rate Order described in Rate Developments above. The downgrade could hamper our operational flexibility by restricting or increasing the cost of future access to capital, and imposing additional requirements to provide performance assurance associated with certain power purchase and sale transactions. The downgrade has also limited the number of counterparties with which we can transact power purchase and sale transactions, which could increase our future power costs.
We believe that restoration of our credit rating is critical, not only to the long-term success of the Company, but to Vermont's energy future. While our credit rating remains below investment-grade, the cost of capital, which is ultimately passed on to our customers, will be greater than it otherwise would be. That, combined with other collateral requirements from creditors and for power purchases makes restoration of our credit rating critical. Looking ahead, as long-term power contracts with Hydro-Quebec and Vermont Yankee begin to expire five to seven years from now, these ratings become even more important. Since we are the largest electric utility in the state serving the largest number of customers, we shoulder a responsibility to ensure we can obtain needed power from the most environmentally benign sources at the best prices possible. That would be very difficult to accomplish while rated below investment-grade.
Risks related to our power supply and wholesale power market prices: Our material power supply contracts are principally with Hydro-Quebec and VYNPC. These relatively low-priced contracts comprise the majority of our total annual energy (mWh) purchases. If one or both of these sources becomes unavailable for a period of time, there could be exposure to high wholesale power prices and that amount could be material. Additionally, this could
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also significantly impact liquidity due to the potential high cost of replacement power and performance assurance collateral requirements arising from purchases through ISO-New England or third parties. We could seek emergency rate relief from our regulators if this occurred.
We sometimes experience energy delivery deficiencies under the power contract with Hydro-Quebec as a result of outages or other problems with the transmission interconnection facilities over which we schedule deliveries. We are also responsible for procuring replacement energy during periods of scheduled or unscheduled outages at the Vermont Yankee plant. In both cases, we purchase replacement energy, if needed, from third parties in New England or through ISO-New England. Although our retail rates include a provision for estimated replacement power costs, average market prices at the times when we purchase replacement energy might be significantly higher than amounts included for recovery in our retail rates.
Our contract for power purchases from VYNPC ends in 2012, but there is a risk that the plant could be shut down earlier than expected if Entergy determines that it is not economical to continue operating the plant under the current regulatory environment. Our contract for power purchases from Hydro-Quebec ends in 2016, although the level of deliveries will be reduced significantly in 2012. There is a risk that future sources available to replace these contracts may not be as reliable and the price of such replacement power could be significantly higher than what we have in place today.
Risks related to liquidity: We believe that cash on hand, including available-for-sale securities, and cash flow from operations will be sufficient to fund our business for the next 12 months. Based on our current cash forecasts, the borrowing capacity under our $25.0 million credit facility will likely provide sufficient liquidity at least through 2007. Material risks to cash flow from operations include: loss of retail sales revenue from unusual weather; slower-than-anticipated load growth and unfavorable economic conditions; increases in net power costs largely due to lower-than-anticipated margins on sales revenue from excess power or an unexpected power source interruption; required prepayments for power purchases; and increases in performance assurance collateral requirements, primarily as a result of high power market prices.
Risks related to decommissioning of nuclear plants in which we have an interest: Nuclear decommissioning costs related to our ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic have significantly increased over the past several years. Although we continue to believe that these costs will be recovered in retail and wholesale rates, based on the regulatory process, there is a risk that the PSB could disallow these costs for recovery in retail rates, if it or FERC determines that such costs were imprudent.
We have a joint ownership interest in Millstone Unit #3 and are required to maintain funded trusts to satisfy our future obligations to decommission the plant. A decline in the market value of those assets due to poor investment performance or other factors may increase the funding requirements for these obligations.
Risks related to the economic condition of our customers: An economic downturn and increased cost of energy supply could adversely affect energy consumption and therefore impact our results of operations. Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply. Economic downturns or periods of high energy supply costs typically lead to reductions in energy consumption and increased conservation measures. These conditions could adversely impact the level of energy sales and result in less demand for energy delivery. A recession or prolonged lag of a subsequent recovery could have an adverse effect on our results of operations, cash flows or financial position.
Item 1B. Unresolved Staff Comments
None
Item 2. Properties.
The Company The Company's properties are operated as a single system that is interconnected by the transmission lines of VELCO, New England Power and PSNH. The Company owns and operates 23 small generating stations with a total current nameplate capability of 73.6 MW. The Company's joint ownership interests include a 1.7769 percent interest in an oil generating plant in Maine; a 20 percent interest in a wood, gas and oil-fired generating plant in Vermont; a 1.7303 percent interest in a nuclear generating plant in Connecticut; and a 47.35 percent interest in a transmission interconnection facility in Vermont.
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The electric transmission and distribution systems of the Company include about 616 miles of overhead transmission lines, about 7,922 miles of overhead distribution lines and about 380 miles of underground distribution lines, all of which are located in Vermont except for about 23 miles in New Hampshire and about 2 miles in New York.
All of the principal plants and important units of the Company and its subsidiaries are held in fee. Transmission and distribution facilities, which are not located in or over public highways are, with minor exceptions, located on either land owned in fee or pursuant to easements, most of which are perpetual. Transmission and distribution lines located in or over public highways are so located pursuant to authority conferred on public utilities by statute, subject to regulation of state or municipal authorities.
Substantially all of the Company's utility property and plant is subject to liens under the Company's First Mortgage Indenture. See Part II Item 8, Note 7 - Long-Term Debt and Credit Facility for more information related to the First Mortgage Bonds.
VELCO VELCO's properties consist of about 573 miles of high voltage overhead transmission lines and associated substations. The lines connect on the west with the lines of Niagara Mohawk Power Corporation at the Vermont-New York state line near Whitehall, New York, and Bennington, Vermont, and with the submarine cable of NYPA near Plattsburgh, New York; on the south and east with the lines of New England Power Company and PSNH; on the south with the facilities of Vermont Yankee; and on the north with lines of Hydro-Quebec through a converter station and tie line jointly owned by the Company and several other Vermont utilities.
VETCO VETCO has about 52 miles of high voltage DC transmission line connecting with the transmission line of Hydro-Quebec at the Quebec-Vermont border in the Town of Norton, Vermont; and connecting with the transmission line of New England Electric Transmission Corporation, a subsidiary of National Grid USA, at the Vermont-New Hampshire border near New England Power Company's Moore hydro-electric generating station.
Additional information with respect to the Company's properties is set forth under the caption "Power Resources" in Item 1 and is incorporated herein by reference.
Item 3. Legal Proceedings.
The Company is involved in legal and administrative proceedings in the normal course of business and does not believe that the ultimate outcome of these proceedings will have a material adverse effect on its financial position or results of operations, except as otherwise disclosed herein.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to security holders during the fourth quarter of 2005.
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PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities.
(a) The Company's common stock is listed on the New York Stock Exchange ("NYSE") under the trading symbol CV. Newspaper listings of stock transactions use the abbreviation CVtPS or CentlVtPS and the Internet trading symbol is CV.
The table below shows the high and low sales price of the Company's Common Stock, as reported on the NYSE composite tape by The Wall Street Journal, for each quarterly period during the last two years as follows:
|
Market Price |
|||
|
High |
Low |
||
|
2005 |
|||
|
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . |
$ 23.69 |
$ 21.80 |
|
|
2004 |
|||
|
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . |
$ 24.08 |
$ 21.76 |
|
(b) As of December 31, 2005, there were 7,767 holders of the Company's Common Stock, $6 par value.
(c) Common Stock dividends have been declared quarterly. Cash dividends of $.23 per share were paid for all quarters of 2005 and 2004.
So long as any Senior Preferred Stock is outstanding, except as otherwise authorized by vote of two-thirds of such class, if the Common Stock Equity (as defined) is, or by the declaration of any dividend will be, less than 20 percent of Total Capitalization (as defined), dividends on Common Stock (including all distributions thereon and acquisitions thereof), other than dividends payable in Common Stock, during the year ending on the date of such dividend declaration, shall be limited to 50 percent of the Net Income Available for Dividends on Common Stock (as defined) for that year; and if the Common Stock Equity is, or by the declaration of any dividend will be, from 20 percent to 25 percent of Total Capitalization, such dividends on Common Stock during the year ending on the date of such dividend declaration shall be limited to 75 percent of the Net Income Available for Dividends on Common Stock for that year. The defined terms identified above are used herein in the sense as defined in subdivision 8A of the Company's Articles of Association; such definitions are based upon the unconsolidated financial statements of the Company. As of December 31, 2005, the Common Stock Equity of the unconsolidated Company was 60.5 percent of total capitalization.
The Company's First Mortgage Bond indenture contains certain restrictions on the payment of cash dividends on capital stock and other Restricted Payments (as defined). This covenant limits the payment of cash dividends and other Restricted Payments to Net Income of the Company (as defined) for the period commencing on January 1, 2001 up to and including the month next preceding the month in which such Restricted Payment is to be declared or made, plus approximately $77.6 million. The defined terms identified above are used herein in the sense as defined in Section 5.09 of the Forty-Fourth Supplemental Indenture dated June 15, 2004; such definitions are based upon the unconsolidated financial statements of the Company. As of December 31, 2005, $90 million was available for such dividends and other Restricted Payments.
(d) The information required by this item is included in Item 12, herein.
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Item 6. Selected Financial Data.
|
|
As |
As |
As |
As |
|
|
For the Year Operating revenues Income from continuing operations Income from discontinued operations Net income Earnings available for common stock |
|
|
|
|
|
|
Per Common Share Data: Basic: Earnings (loss) from continuing operations Earnings from discontinued operations Earnings per share Diluted: Earnings from continuing operations Earnings from discontinued operations Earnings per share Cash dividends declared per share of common stock Book value per share of common stock |
$1.15 $17.70 |
|
|
|
|
|
At End of Year Long-term debt - excluding current portion Capital lease obligations - excluding current portion Redeemable preferred stock - excluding current portion Total capitalization Total assets |
|
|
|
|
|
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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
In this section we discuss the general financial condition and results of operations for Central Vermont Public Service Corporation (the "Company" or "we" or "our" or "us") and its subsidiaries. Certain factors that may impact future operations are also discussed. Our discussion and analysis is based on, and should be read in conjunction with, the accompanying Consolidated Financial Statements.
Forward-looking statements Statements contained in this report that are not historical fact are forward-looking statements intended to qualify for the safe-harbors from liability established by the Private Securities Litigation Reform Act of 1995. Whenever used in this report, the words "estimate," "expect," "believe," or similar expressions are intended to identify such forward-looking statements. Forward-looking statements involve estimates, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Actual results will depend upon, among other things:
We cannot predict the outcome of any of these matters; accordingly, there can be no assurance that such indicated results will be realized. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.
EXECUTIVE SUMMARY
Subsequent to the issuance of our 2004 audited financial statements, Management determined the need to restate prior period financial statements to correct errors discovered during the 2005 year-end close and reporting process. The errors included an investment impairment that should have been recorded in December 2002, and certain balance sheet misclassifications. Correction of these errors did not affect reported earnings for 2004 or 2003. For a discussion of these errors see Note 16 - Restatement. The detailed discussion that follows reflects effects of these restated amounts as appropriate.
Our consolidated 2005 earnings were $6.3 million, or 48 cents per diluted share of common stock, compared to 2004 earnings of $23.8 million, or $1.90 per diluted share of common stock, and 2003 earnings of $19.8 million, or $1.53 per diluted share of common stock. Our 2005 results include a $5.6 million after-tax gain, or 45 cents per diluted share of common stock, on the December 20, 2005 sale of all of our interest in Catamount Energy Corporation ("Catamount"). Our 2004 results include a $12.3 million after-tax gain, or $1.00 per diluted share of common stock, on the January 1, 2004 sale of Connecticut Valley Electric Company Inc. ("Connecticut Valley") plant assets and franchise. Both Catamount and Connecticut Valley are reported as discontinued operations on the Consolidated Financial Statements, and all periods presented have been reclassified to conform to that presentation. The primary drivers of consolidated earnings for the past three years are discussed in detail in Results of Operations below.
Our primary focus in 2005 has been in working to restore the Company's financial strength given the Vermont Public Service Board's ("PSB") March 29, 2005 Order ("Rate Order"). Among other things, the Rate Order reduced our retail rates by 2.75 percent beginning April 1, 2005, reduced the Vermont utility's allowed rate of return from 11 percent to 10 percent, and resulted in a $21.8 million pre-tax charge to earnings in the first quarter of 2005. We are implementing a plan for restoring the Company to a position of financial strength including:
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Other key financial initiatives in 2005 included:
COMPANY OVERVIEW
We are a Vermont-based electric utility that transmits, distributes and sells electricity. We are regulated by the PSB, the Connecticut Department of Public Utility Control and the Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting, financing and other matters pertaining to regulated operations. Our non-regulated wholly owned subsidiary Catamount Resources Corporation ("CRC") owns Eversant Corporation ("Eversant"), which operates a rental water heater business through its wholly owned subsidiary, SmartEnergy Water Heating Services, Inc. Other wholly owned subsidiaries include Custom Investment Corporation ("Custom"), a passive investment subsidiary that holds our investment in Vermont Yankee Nuclear Power Corporation ("VYNPC"), and Connecticut Valley, which completed the sale of substantially all of its plant assets and franchise to Public Service Company of New Hampshire ("PSNH") on January 1, 2004.
On October 31, 2005, CRC's wholly owned subsidiary, Catamount, which invested primarily in wind energy projects in the United States and the United Kingdom, issued shares of its common stock to CEC Wind Acquisition, LLC, a Delaware limited liability company established by Diamond Castle Holdings, a New York-based private equity investment firm ("Diamond Castle"). The transaction diluted CRC's ownership interest in Catamount to 79 percent and its voting rights to 49 percent. On December 20, 2005, CRC sold all of its interest in Catamount to Diamond Castle.
The Vermont utility operation is our core business. As a regulated electric utility, we have an exclusive right to serve customers in our service territory, which can generally be expected to result in relatively stable revenue streams. However, the ability to increase our customer base is limited to growth within the service territory, which has been relatively flat for several years. Given the nature of our customer base, weather and economic conditions are factors that can significantly affect our retail sales revenue. Electricity sales growth can vary from a 2 percent decrease to a 3 percent increase on an annual basis. We currently have sufficient power resources to meet our forecasted load requirements, mostly through long-term power contracts. We sell any excess power we have in the wholesale markets administered by ISO-New England or to third parties primarily in New England. Such sales help to mitigate overall power costs; but wholesale power market volatility can affect these mitigation efforts.
Our retail rates are set by the PSB after considering recommendations of Vermont's consumer advocate, the Vermont Department of Public Service ("DPS"). While Vermont does not have a fuel or power adjustment clause, the PSB has previously approved deferral of extraordinary costs incurred that might normally be expensed by unregulated businesses in order to match these expenses with future revenues. Fair regulatory treatment is fundamental to maintaining our financial stability. Rates must be set at levels to recover costs, including a market rate of return to equity and debt holders, in order to attract capital.
In June 2005, Standard & Poor's Ratings Services ("S&P") lowered our corporate credit rating to below investment grade. Fitch also lowered its ratings on our senior secured debt and preferred stock. According to both agencies, these actions were taken primarily as a result of the Rate Order. As a result of the downgrades, we are now required to post collateral under performance assurance requirements for certain of our power contracts. At December 31, 2005, we had posted $19.1 million of collateral. We were also required to prepay for replacement power purchases related to the Vermont Yankee scheduled refueling outage in the fourth quarter of 2005. In October 2005 we closed on a $25.0 million unsecured credit facility to bolster liquidity. Although we have taken steps to help ensure liquidity is maintained over the next two years, an unscheduled and prolonged outage of one of our significant power sources such as Vermont Yankee or Hydro-Quebec could have a detrimental effect on our liquidity without some form of rapid rate relief from our regulators. See discussion of Liquidity and Capital Resources below.
Improving communications with our Vermont regulators and achieving investment-grade status are top priorities for us. Although we have made progress in implementing our restoration plan described above, our ongoing liquidity and ability to make necessary investments in our electric system would be greatly impacted without a combination
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of a rate increase within the next 18 months and ongoing efforts to control rising costs. We believe restoration of the Company's credit rating is critical, not only to the long-term success of the Company, but to Vermont's energy future. While our credit rating remains below investment-grade, the cost of capital, which is ultimately passed on to our customers, will be greater than it otherwise would be. That, combined with other collateral requirements from creditors and for power purchases makes restoration of our credit rating critical. Looking ahead, as long-term power contracts with Hydro-Quebec and Vermont Yankee begin to expire six years from now, these ratings become even more important. Since we are the largest electric utility in the state serving the largest number of customers, we shoulder a responsibility to ensure we can obtain needed power from the most environmentally benign sources at the best prices possible. That would be very difficult to accomplish while rated below investment-grade.
In the fourth quarter of 2005, we incurred net incremental replacement power costs for a Vermont Yankee scheduled refueling outage that were about $4.7 million above amounts currently being recovered in retail rates. The high price for replacement power resulted from very high wholesale power market prices driven primarily by the extraordinary effects of hurricanes Katrina and Rita on the price of natural gas. In December 2005 we requested an Accounting Order from the PSB to defer $4.7 million for recovery in our next rate proceeding. These costs have not been deferred, since the PSB has not yet ruled on our request. See Power Supply Matters below.
After the issuance of the Rate Order and the ratings downgrade, we decided not to make additional equity investments in Catamount in 2005. In July 2005, Catamount repaid a $12.8 million bridge loan that we had extended in April 2005. In July 2005, Catamount closed on a $31.0 million credit facility that was non-recourse to us. On October 12, 2005, we reached an agreement to sell a controlling interest in Catamount to Diamond Castle, through issuance of Catamount's common stock. The underlying agreements provided for Diamond Castle to make a series of equity investments in Catamount, totaling $62.5 million, over a three-year period. The agreements with Diamond Castle included an option for us to sell all of our interest in Catamount for $60.0 million less certain transaction expenses. Catamount received Diamond Castle's initial investment of $16.0 million on October 31, 2005 and Diamond Castle received a 21 percent equity ownership and a majority of the voting rights in Catamount.
On November 21, 2005, we announced our decision to sell all of our interest in Catamount to Diamond Castle, and the sale was consummated on December 20, 2005. Cash proceeds from the sale amounted to $59.25 million, resulting in an after-tax gain of $5.6 million. See Discontinued Operations below.
On February 7, 2006, we announced a buyback of our common stock in a reverse Dutch auction tender offer, using about $50.0 million in proceeds from the Catamount sale. We also announced plans to use about $20.0 million in cash on hand in 2006 to fund capital construction projects and to contribute additional amounts to our post-retirement medical and pension trust funds. The tender offer commenced on February 14, 2006 and was scheduled to expire on March 15, 2006, but we extended it until April 5, 2006. Under the procedures of the tender offer, shareholders may offer to sell some or all of their stock to us at a target price in a range from $20.50 to $22.50 per share. Upon expiration of the tender offer, we will select the lowest-bid price that will allow us to buy up to 2,250,000 shares, which represents about 18.3 percent of our outstanding common stock.
We believe these funding decisions will benefit shareholders and customers. By returning proceeds from the Catamount sale to shareholders who participate in the buyback, we will reduce the number of outstanding shares, which will boost earnings per share for remaining shareholders. We believe the additional funding for utility infrastructure and reduction in retirement plan expenses in our utility cost of service will benefit our customers. See Liquidity and Capital Resources below.
RETAIL RATES
On April 7, 2004 the PSB issued an order to investigate our retail rates. On July 15, 2004, we filed a cost of service study pursuant to the rate investigation, and filed a separate request for a 5.01 percent rate increase, effective April 1, 2005. We also requested that the two cases be consolidated; that request was later approved by the PSB. In October 2004, both the DPS and AARP, interveners in the case, filed testimony with the PSB. Technical hearings with the PSB began in early November 2004, and hearings and filings continued through February 2005.
On February 18, 2005, the PSB approved our request for an Accounting Order that allowed for deferral of 2004 utility earnings in excess of an 11 percent return on equity. Per the Accounting Order, we reduced 2004 utility earnings by about $2.3 million after-tax to achieve the 11 percent, and recorded an offsetting pre-tax regulatory liability of $3.8 million to be used or accounted for as the PSB determined in its final order.
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On March 29, 2005, the PSB issued the Rate Order concluding that our rates were higher than was just and reasonable, and must be reduced. In the Rate Order, the PSB determined the annual revenue requirement for the period beginning April 1, 2004, established rates retroactive to April 7, 2004 and established new rates beginning April 1, 2005. The Rate Order included, among other things, the following: 1) a 1.88 percent rate reduction beginning April 1, 2005; 2) a $3.3 million refund to customers; 3) a 10 percent return on equity (reduced from 11 percent); and 4) a requirement that the gain resulting from termination of the power contract related to the 2004 Connecticut Valley sale be applied to the benefit of ratepayers to compensate for increased costs. We were also required to file a compliance filing by April 1, 2005, which we did, and file a new rate design. We filed a new rate design on August 29, 2005, based on the PSB's approval for an extension on the filing date.
The PSB finalized the rate refund and rate reduction amounts in its April 4, 2005 Compliance Order. The rate refund amounted to about $6.5 million pre-tax and the rate reduction amounted to 2.75 percent ($7.2 million pre-tax on an annual basis).
For accounting purposes, the Rate Order resulted in a $21.8 million pre-tax charge to utility earnings in the first quarter of 2005. The primary components of the charge to earnings include: 1) a revised calculation of overearnings for the period 2001 - 2003; 2) application of the gain resulting from termination of the power contract with Connecticut Valley to reduce costs; 3) a customer refund for the period April 7, 2004 through March 31, 2005; and 4) amortization of costs and other adjustments required in the Rate Order. The effects on the 2005 Consolidated Statement of Income are discussed in more detail below in Results Operations under the caption 2005 Rate Order.
On April 12, 2005, we filed with the PSB a Request for Reconsideration of the Rate Order. Specific items for reconsideration included: 1) treatment of the costs and benefits associated with the January 1, 2004 Connecticut Valley sale; 2) the 10 percent return on equity; and 3) various other matters for clarification.
On April 12, 2005, the DPS filed with the PSB a Motion for Reconsideration of the Rate Order. Specific items for reconsideration included: 1) treatment of costs formerly recovered by the Company through a service contract with Connecticut Valley; and 2) certain adjustments related to the calculation of overearnings for 2001 - 2003.
We, the DPS and AARP submitted responses to these motions by April 26, 2005 as required by the PSB. On May 25, 2005, the PSB issued its Order on both Motions for Reconsideration. All requests to modify the Rate Order were denied with the exception of a minor modification to one sentence in the Rate Order, and a request for us to inform the PSB and other parties on treatment of construction work in process in the overearnings calculation. That matter has been resolved.
On June 22, 2005, we filed an appeal of portions of the Rate Order with the Vermont Supreme Court. On July 11, 2005, we filed a docketing statement with the court in which we outlined the issues in our case. The docketing statement describes the ordered payback of earnings from periods prior to the opening of the rate investigation, namely the years 2001 to 2003, and also the first quarter of 2004 when we recorded a gain from the Connecticut Valley sale. The issues that were raised on appeal primarily focus on whether the Rate Order sets rates retroactively without statutory authorization. On July 27, 2005, the DPS filed a response opposing our position. We filed our legal brief and other materials in the case on August 22, 2005. Expedited oral argument occurred on January 31, 2006, and we expect a Vermont Supreme Court decision on the case in the second or third quarter of 2006. We are not able to predict the outcome of this matter at this time.
Our August 29, 2005 rate design proposal maintains our overall revenue requirement approved in the Rate Order, but modestly reallocates rate class revenue between some rate classes. Several Vermont ski areas have intervened, and we have participated in workshops to seek a settlement with all parties. If settlement discussions are not successful, a schedule for hearings will be determined.
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DISCONTINUED OPERATIONS
Discontinued operations of the Company include: 1) Catamount based on our November 2005 decision to sell all of our interest in Catamount, and consummation of the sale on December 20, 2005; and 2) Connecticut Valley due to the January 1, 2004 sale of its plant assets and franchise. These sales are described in more detail below. The components of Income from discontinued operations (net of income tax) on the Consolidated Statements of Income follow (in thousands):
|
For the Years Ended December 31, |
|||
|
2005 |
2004 |
2003 |
|
|
Catamount's results of operations |
$(671) |
$3,922 |
$1,207 |
|
4,936 |
3,922 |
1,207 |
|
|
Connecticut Valley's results of operations |
- |
(14) |
1,446 |
|
Gain on Connecticut Valley sale |
- |
12,354 |
- |
|
- |
12,340 |
1,446 |
|
|
Income from discontinued operations |
$4,936 |
$16,262 |
$2,653 |
Catamount Energy Sale
|
Cash proceeds |
$59,250 |
Under the terms of the Stock Subscription Agreement, we agreed to indemnify Catamount and Diamond Castle, and certain of their respective affiliates, in respect of a breach of certain representations and warranties and covenants, most of which survive until June 30, 2007, except certain items that customarily survive indefinitely. We indemnified all losses related to taxes for periods prior to the initial closing, subject to a "true up" post-closing. Indemnification is net of insurance and taxes, and materiality is disregarded from all representations and warranties.
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Indemnification is subject to a $1.5 million deductible and a $15.0 million cap, excluding certain customary items. Environmental representations are subject to the deductible and the cap, and such environmental representations for only two of Catamount's underlying energy projects survive beyond June 30, 2007.
In the fourth quarter of 2005, we recorded a $0.3 million contingent liability related to one of Catamount's projects. This amount represents our estimate of the fair value of the indemnification which is not subject to the deductible. Our estimated "maximum potential" amount of future payments related to these indemnifications is limited to $15.0 million. We have not recorded any additional liability related to these indemnifications.
Catamount's results of operations included in discontinued operations reflect the reallocation of certain corporate costs back to continuing operations since they were not eliminated by the sale. These pre-tax costs amounted to about $0.5 million in 2005, $0.5 million in 2004 and $0.8 million in 2003 and are included in Catamount's operating expenses, net of tax. Catamount's results of operations are summarized in the table below (in thousands).
|
For the years ended December 31, |
|||
|
Operating revenues |
$- |
$- (315) 315 4,220 2,518 1,895 (6,674) 1,928 3,887 4,202 280 3,922 - $3,922 |
$- (471) 471 6,362 - 1,046 (7,823) 1,808 1,393 1,864 657 1,207 - $1,207 |
Connecticut Valley Sale On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to PSNH. The sale, including termination of the power contract between us and Connecticut Valley, resolved all Connecticut Valley restructuring litigation in New Hampshire and our stranded cost litigation at FERC.
For accounting purposes, components of the sale transaction were recorded in both continuing and discontinued operations on the 2004 Consolidated Statement of Income. Income from discontinued operations included a gain on disposal of about $21.0 million pre-tax, or $12.3 million after-tax. In addition to the gain on disposal, we recorded a loss on power costs of $14.4 million pre-tax, or $8.4 million after-tax relating to termination of the power contract with Connecticut Valley. The loss is included in Purchased Power on the 2004 Consolidated Statement of Income. When the two accounting transactions are combined to assess the total impact of the sale, the result was a gain of $3.9 million recorded in the first quarter of 2004.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows: At December 31, 2005, we had cash and cash equivalents of $6.6 million included in total working capital of $91.5 million. During 2005, cash and cash equivalents decreased by $5.1 million. The decrease resulted from the following:
Operating Activities of Continuing Operations: Operating activities from continuing operations provided $5.3 million, including $1.9 million of dividends from utility investments, and $1.1 million related to our portion of an IRS tax settlement at VYNPC, partially offset by $19.1 million used to meet performance assurance requirements under power transaction agreements, $6.1 million of income tax payments net of refunds, including
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$4.9 million related to the Catamount sale, and $8.9 million of net interest payments. In 2005, we paid customer refunds related to the Rate Order of $6.5 million. The majority of this amount was credited to customer bills. We also contributed $4.5 million to Pension and Postretirement trust funds, in addition to Postretirement out-of-pocket payments of $2.5 million, offset by $0.5 million of contributions received from plan participants.
Investing Activities of Continuing Operations: Investing Activities of Continuing Operations: Investing activities from continuing operations provided $6.1 million, including $59.25 million of proceeds from the sale of Catamount, less transaction costs of $1.4 million, and $11.0 million from repayment of a note receivable from Catamount. Offsetting these items were $17.6 million of construction expenditures, $38.9 million for net investments in available-for-sale securities, and $5.9 million invested in Catamount during the first half of 2005. Investments in available-for-sale securities increased primarily because we invested the cash proceeds from the Catamount sale. These investments were partially offset by the sale of securities, in part to make collateral payments of $19.1 million under the performance assurance requirements described below.
Financing Activities of Continuing Operations: Financing activities from continuing operations used $14.0 million, including $12.1 million for dividends paid on common and preferred stock, $2.0 million for preferred stock sinking fund payments, and $1.0 million for capital lease payments, partially offset by $1.2 million from stock issuance proceeds.
Discontinued Operations: Cash from discontinued operations used $2.5 million, including a decrease in cash resulting from deconsolidation of Catamount and proceeds received from Diamond Castle related to the October 2005 stock issuance. Cash from operating activities provided $3.8 million, cash of $12.0 million was used for investing activities and cash of $22.0 million was provided by financing activities. Catamount's liquidity contributed towards funding their non-utility investments and related activities; therefore, the sale of Catamount will not affect our ongoing liquidity. See Discontinued Operations above.
At December 31, 2004, we had cash and cash equivalents of $11.7 million ($2.5 million was included in Assets of discontinued operations) and working capital of $79.4 million. During 2004, cash and cash equivalents increased by $0.7 million due to the following: 1) $25.0 million provided by operating activities; 2) $10.5 million used by investing activities, mostly for construction expenditures, a note receivable from Catamount, and investments in VELCO and available-for-sale securities, offset by cash proceeds from the January 1, 2004 sale of Connecticut Valley's plant assets and franchise to PSNH; and 3) $13.0 million used in financing activities primarily related to dividends paid on common and preferred stock and retirement of long-term debt and preferred stock. In addition, activities of discontinued operations related to Catamount used $0.8 million.
Available-for-sale Securities: Investments in available-for-sale securities at December 31, 2005 include $72.4 million with original maturities from 90 days to one year and $5.5 million with original maturities greater than one year. Investments in available-for-sale securities at December 31, 2004 included $17.5 million with original maturities from 90 days to one year and $21.9 million with original maturities greater than one year.
VELCO: We continue to consider additional investments in VELCO at a level intended to maintain VELCO's common equity at 25 percent of its total capitalization. VELCO will require additional equity capital beyond 2005 in order to finance all of the proposed transmission upgrades and we will consider additional investments in VELCO at that time. In total, our investments in VELCO could amount to between $35 million and $40 million through 2008. Based on VELCO's current projections, we could invest about $20 million to $25 million in 2006, $11 million to $13 million in 2007, and $2 million to $4 million in 2008. VELCO's equity projections are subject to change based on a number of factors, including revised upgrade estimates and timing of regulatory approvals. Our investment plans in VELCO are also subject to change due to circumstances such as liquidity deterioration.
Rate Order: Our retail rates were reduced by 2.75 percent ($7.2 million pre-tax on an annual basis) on April 1, 2005. Additionally, the $6.5 million customer refund, mostly through credits on customer bills, occurred in the second quarter of 2005. Both of these items adversely impacted our cash flow from operations in 2005, and the rate reduction combined with the 10 percent allowed return on equity (reduced from 11 percent) will impact our cash flow from operations in future years. See Retail Rates above for additional information.
Dividends: Our dividend level is reviewed by our Board of Directors on a quarterly basis. It is our goal to ensure earnings in future years are sufficient to pay out our current dividend level.
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Tender Offer: On February 7, 2006, we announced our plan to buy back common stock in a reverse Dutch auction tender offer, using about $50.0 million in proceeds from the Catamount sale. The tender offer commenced on February 14, 2006 and was scheduled to expire on March 15, 2006, but we extended it until April 5, 2006. Under the procedures of the tender offer, shareholders may offer to sell some or all of their stock to us at a target price in a range from $20.50 to $22.50 per share. Upon expiration of the tender offer, we will select the lowest-bid price that will allow us to buy up to 2,250,000 shares, which represents about 18.3 percent of our outstanding common stock.
Other: On February 7, 2006, we announced our plans to use cash on hand in 2006 for the following: 1) capital construction projects of $3.3 million; 2) contribution to our post-retirement medical fund benefits of $4.1 million; and 3) contribution to our pension fund of $12.2 million. The contributions to our pension and post-retirement funds were made on March 1, 2006 using cash on hand and short-term investments.
Cash Flow Risks: We believe that cash on hand, including available-for-sale securities, and cash flow from operations will be sufficient to fund our business for the next 12 months. Based on our current cash forecasts, the borrowing capacity under our $25.0 million credit facility will likely provide sufficient liquidity at least through 2007. However, an extended Vermont Yankee plant outage or similar event could significantly impact our liquidity due to the potential high cost of replacement power and performance assurance collateral requirements arising from purchases through ISO-New England or third parties. In the event of an extended Vermont Yankee plant outage, we could seek emergency rate relief from our regulators. Other material risks to cash flow from operations include: loss of retail sales revenue from unusual weather; slower-than-anticipated load growth and unfavorable economic conditions; increases in net power costs largely due to lower-than-anticipated margins on sales revenue from excess power or an unexpected power source interruption; required prepayments for power purchases; and increases in performance assurance collateral requirements described below, primarily as a result of high power market prices.
Financing
Long-Term Debt and Short-term Notes Payable: Scheduled sinking fund payments for the next five years are $0 in 2006, $0 in 2007, $3.0 million in 2008, $5.5 million in 2009, and $0 in 2010. Substantially all utility property and plant are subject to liens under the First Mortgage Bond indenture. Currently, we are not in default under any of our debt financing documents.
Credit Facility: On October 27, 2005, we closed on a three-year, $25.0 million unsecured, committed revolving credit facility with a lending institution pursuant to a Credit Agreement dated October 21, 2005. On September 30, 2005, the PSB approved our plans to enter into a credit facility and on November 15, 2005 the PSB approved all of its terms. The purpose of the facility is to provide liquidity for general corporate purposes, including working capital needs and power contract performance assurance requirements, in the form of borrowings and letters of credit. Financing terms and costs include an annual commitment fee on the unused balance, plus interest on the outstanding balance of borrowings and letters of credit that is based on our unsecured long-term debt rating. Terms also include the requirement to collateralize any outstanding letters of credit in the event of a default under the credit facility. This facility also contains a Material Adverse Effect ("MAE") clause (a standard that requires greater adversity than a Material Adverse Change clause); this clause is in effect only when the Company's credit rating is below investment grade. The MAE clause could allow the lending institution to deny a transaction under the credit facility at the point of request. Once any borrowing is advanced, its maturity cannot be accelerated for reasons other than an event of default. At December 31, 2005 there were no borrowings or letters of credit outstanding under this facility.
Covenants: At December 31, 2005, we were in compliance with all covenants related to our various debt agreements, Articles of Association, letters of credit and credit facility; these agreements contain both financial and non-financial covenants. The most restrictive financial covenants include maximum debt to total capitalization of 50 percent, and minimum interest coverage of 1.75 times. In the second quarter of 2005, we paid a consent fee of about $0.2 million to our bondholders in exchange for a waiver of any interest coverage default that could have resulted from the first-quarter 2005 Rate Order charge. Our Articles of Association also contain a covenant that requires us to maintain a minimum common equity level of about $3.3 million, applicable only as long as Preferred Stock is outstanding.
Our $25.0 million revolving credit facility restricts optional redemptions of capital stock. On November 28, 2005, we received a waiver of terms under the credit facility allowing us to optionally redeem $1.0 million of our 8.3 percent preferred stock at par on January 1, 2006 and to proceed with the buyback of up to $50.0 million of common
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stock. Our First Mortgage Bond indenture and Articles of Association also contain certain restrictions on the payment of dividends on and optional redemptions of all capital stock. Under the most restrictive of these provisions, about $90.0 million of retained earnings was not subject to such restriction at December 31, 2005. The Articles also restrict the payment of common dividends or purchase of any common shares if the common equity level falls below 25 percent of total capital, applicable only as long as Preferred Stock is outstanding.
Off-balance sheet arrangements
Letters of Credit: We have three outstanding unsecured letters of credit, issued by one bank, totaling $16.9 million in support of three separate issues of industrial development revenue bonds totaling $16.3 million, of which $10.8 million are classified as short-term and $5.5 million are classified as long-term. These letters of credit, which expired on November 30, 2005, were extended by the bank to November 30, 2006. These letters of credit are secured under the Company's first mortgage indenture as required by the bank, due to our non-investment grade credit rating. At December 31, 2005 and 2004, there were no amounts outstanding under these letters of credit.
Operating Leases: We lease our vehicles and related equipment under one operating lease agreement. The leases are mutually cancelable one year from each individual lease inception. We have the ability to lease vehicles and related equipment up to an aggregate unamortized balance of $10.0 million, of which about $6.3 was outstanding at December 31, 2005 and $4.4 million was outstanding at December 31, 2004.
Under the terms of the vehicle operating lease, we have guaranteed a residual value to the lessor in the event the leased items are sold. The guarantee provides for reimbursement of up to 87 percent of the unamortized value of the lease portfolio. We had a liability of $0.2 million at December 31, 2005 representing our obligation under the guarantee based on the fair market value of the entire portfolio. Under the guarantee, if the entire lease portfolio had a fair value of zero at December 31, 2005, we would have been responsible for a maximum reimbursement of $5.4 million and at December 31, 2004, we would have been responsible for a maximum reimbursement of $3.9 million.
Other operating lease commitments are considered minimal, as most are cancelable after one year from inception. Total rental expense, including the operating lease agreement described above, included in net income, amounted to about $5.5 million in 2005, $5.2 million in 2004 and $4.4 million in 2003.
Power Supply Commitments: We have material power supply commitments for the purchase of power from VYNPC and Hydro-Quebec. These contracts supported about 84 percent of our total energy (mWh) purchases in 2005.
Equity Investments: We own an equity interest in VELCO in which we are required to pay a portion of VELCO's operating costs based on our network load percentage and to make additional payments if VELCO's transmission rates do not provide for full cost recovery. We own an equity interest in VYNPC in which we are obligated to pay a portion of VYNPC's operating costs based on our entitlement percentage. See Note 2 - Investments in Affiliates for additional information related to these equity investments.
Catamount Indemnifications: We agreed to indemnify Catamount and Diamond Castle, and certain of their respective affiliates, for certain items related to Catamount. Our obligation for these indemnifications is capped at $15.0 million. See Discontinued Operations above.
Other: We do not use off-balance-sheet financing arrangements, such as securitization of receivables, or obtain access to assets through special purpose entities.
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Capital Commitments and Contractual Obligations
The Vermont utility is a capital-intensive operation, as it requires annual construction expenditures to maintain the distribution system. Our capital expenditure plan is expected to range from $40 million to $50 million for the two-year period between 2006 and 2007. This estimate is subject to continuing review and adjustment and actual capital expenditures may vary from this estimate. Our significant contractual obligations as of December 31, 2005 are summarized in the table below.
|
|
Payments Due by Period (in millions) |
||||
|
Total |
Less than 1 year |
1 - 3 years |
3 - 5 years |
After 5 years |
|
|
Long-term debt |
$116.0 |
- |
$3.0 |
$5.5 |
$107.5 |
|
|||||
Pension and Postretirement Benefits
In 2006, we expect to fund $20.8 million into our Pension Plan including the $4.9 million ERISA minimum funding requirement as shown in the table above. In March 2006, we contributed $12.2 million to our Pension Plan and expect to contribute the remainder in the third quarter of 2006. This will offset future Pension funding requirements since additional contribution requirements are expected. See Note 11 to the Consolidated Financial Statements for total expected cash flows related to Pension. Also, in the first quarter of 2006 we contributed $4.1 million and expect to contribute $0.8 million in the third quarter and $0.1 million in the fourth quarter. Various defined benefit pension proposals are currently under consideration by the Government that could have a significant positive or negative impact on our future required Pension contributions. The outcome of these proposals is unclear and we can not predict the impact on future cash flows.
Credit Ratings
On April 4, 2005, S&P placed our corporate credit rating on CreditWatch with negative implications. On June 10, 2005, S&P lowered our corporate credit rating from an investment grade of 'BBB-' to 'BB+', which is below investment grade. S&P also lowered the ratings on our senior secured debt from 'BBB+' to 'BBB' which is investment grade, and our preferred stock from 'BB' to 'BB-', which is below investment grade. S&P's rationale for the downgrade was primarily in response to the Rate Order. S&P said: "The rate order represents an adverse shift in the company's regulatory environment, which heightens its business risk for the foreseeable future." S&P also removed the rating from CreditWatch and changed the outlook from 'negative' to 'stable' saying "the stable outlook reflects the expectation that the company's financial profile will not deteriorate beyond current projections."
On June 16, 2005, Fitch lowered our senior secured debt from 'BBB+' to 'BBB', which is investment grade and lowered the preferred stock rating from 'BBB-' to 'BB+', which is below investment grade. Fitch said: "The rating downgrade reflects the negative impact of the recent rate decision . . . and the increased business risk resulting from the uncertain regulatory environment."
Effective December 6, 2005, Fitch completed the assignment of issuer default ratings ("IDR") for its North American global power issuers with ratings of BB- or better. Fitch explained that "The IDR reflects the ability of an issuer to meet all financial commitments on a timely basis, effectively becoming the benchmark probability of default." Fitch assigned us an IDR of BB+, a non-investment grade rating, reflecting no change in their assessment of us as discussed above.
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Our current credit ratings are shown in the table below. Credit ratings should not be considered a recommendation to purchase or sell stock.
|
S&P (1) |
Fitch (1) |
Moody's |
|
|
Corporate Credit Rating |
BB+ |
N/A |
N/A |
(1) Outlook: Stable
We are also subject to performance assurance requirements under our Vermont Yankee power purchase contract (the 2001 Amendatory Agreement). If Entergy Nuclear Vermont Yankee, LLC ("ENVY"), the seller, has commercially reasonable grounds for insecurity regarding our ability to pay for our monthly power purchases, ENVY may ask VYNPC and VYNPC may then ask us to provide adequate financial assurance of payment. In the fourth quarter of 2005, ENVY contacted us regarding our ability to pay for power purchases. We responded and have not yet had to post collateral under this contract.
Future risks to performance assurance requirements include collateral calls on the contracts described above, increasing power market prices, and an extended Vermont Yankee outage or other unexpected interruption of a major power source that would require us to purchase replacement power through ISO-New England or other third parties.
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Capitalization
Our capitalization for the past two years is as follows:
|
(in millions) |
Percent |
|||
|
2005 |
2004 |
2005 |
2004 |
|
|
Common stock equity |
$217 |
$225 |
61% 4 33 2 100% |
62% 4 32 2 100% |
OTHER BUSINESS RISKS
In addition to the risks described in Company Overview and Liquidity and Capital Resources above, we are also subject to regulatory risk and wholesale power market risk related to our Vermont electric utility business. These are described in more detail below.
Regulatory Risk: Historically, electric utility rates in Vermont have been based on a utility's costs of service. As a result, electric utilities are subject to certain accounting standards that apply only to regulated businesses. Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"), allows 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. The Company currently complies with the provisions of SFAS No. 71 for its regulated Vermont service territory and FERC-regulated wholesale businesses. If we determine the Company no longer meets the criteria under SFAS No. 71, the accounting impact would be an extraordinary charge to operations of about $36.1 million on a pre-tax basis as of December 31, 2005, assuming no stranded cost recovery would be allowed through a rate mechanism. We would also be required to determine any impairment to the carrying costs of deregulated plant.
Although not currently under consideration, if retail competition were implemented in our Vermont service territory, we are unable to predict the impact on our revenues, our ability to retain existing customers with respect to their power supply purchases and attract new customers or the margins realized on retail sales of electricity, if any such sales were sought.
Power supply and wholesale power market prices: Our material power supply contracts are principally with Hydro-Quebec and VYNPC. These relatively low-priced contracts comprise the majority of our total annual energy (mWh) purchases. If one or both of these sources becomes unavailable for a period of time, there could be exposure to high wholesale power prices and that amount could be material.
We sometimes experience energy delivery deficiencies under the power contract with Hydro-Quebec as a result of outages or other problems with the transmission interconnection facilities over which we schedule deliveries. We are also responsible for procuring replacement energy during periods of scheduled or unscheduled outages at the Vermont Yankee plant. In both cases, we purchase replacement energy, if needed, from third parties in New England or through ISO-New England. Although our retail rates include a provision for estimated replacement power costs, average market prices at the times when we purchase replacement energy might be significantly higher than amounts included for recovery in our retail rates.
Our contract for power purchases from VYNPC ends in 2012, but there is a risk that the plant could be shut down earlier than expected if Entergy determines that it is not economical to continue operating the plant under the current regulatory environment. Our contract for power purchases from Hydro-Quebec ends in 2016, although the level of deliveries will be reduced significantly in 2012. There is a risk that future sources available to replace these contracts may not be as reliable and the price of such replacement power could be significantly higher than what we have in place today.
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CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our financial statements are prepared in accordance with generally accepted accounting principles in the United States ("GAAP"), requiring us to make estimates and judgments that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements. Our most critical accounting policies are described below.
Regulation We prepare our financial statements in accordance with SFAS No. 71 for our regulated Vermont service territory and FERC-regulated wholesale business. Under SFAS No. 71, we account for certain transactions in accordance with permitted regulatory treatment. Regulators may permit incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when recovered in future revenues. In order for a company to report under SFAS No. 71, the company's rates must be designed to recover its costs of providing service and the company must be able to collect those rates from customers. If rate recovery of these costs becomes unlikely or uncertain, whether due to competition or regulatory action, this accounting standard would no longer apply to our regulated operations. Criteria that could give rise to the discontinuance of SFAS No. 71 include: 1) increasing competition that restricts the 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.
Although the Rate Order had a significant unfavorable effect on the Company's financial position and results of operations for 2005, our regulated business continues to meet the criteria for accounting under SFAS No. 71. Based on a current evaluation of the factors and conditions expected to impact future cost recovery, we believe future recovery of our regulatory assets in the State of Vermont for our retail and wholesale businesses is probable.
In the event that the Company no longer meets the criteria under SFAS No. 71 and there is not a rate mechanism to recover these costs, the accounting impact would be an extraordinary charge to operations of about $36.1 million pre-tax as of December 31, 2005. The Company would also be required to determine any impairment to the carrying costs of deregulated plant.
Discontinued Operations Catamount's results of operations are reported as discontinued operations for all periods presented, in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"). Certain corporate costs previously allocated to Catamount that were not eliminated by the sale have been reallocated back to continuing operations. These pre-tax costs amounted to about $0.5 million in 2005, $0.5 million in 2004 and $0.8 million in 2003. The assets and liabilities of Catamount are classified as assets and liabilities of discontinued operations in the 2004 Consolidated Balance Sheet. We began to present Catamount as discontinued operations in the fourth quarter of 2005 based on our decision to sell all of our interest in Catamount to Diamond Castle, and consummation of the sale on December 20, 2005.
The results of operations of Connecticut Valley are reported as discontinued operations for 2004 and 2003, and common corporate costs of about $1.3 million, pre-tax, in 2003 were reallocated back to continuing operations because they were not eliminated by the sale. We began to present Connecticut Valley as discontinued operations in the second quarter of 2003 based on the New Hampshire Public Utility Commission's ("NHPUC") approval of the sale of Connecticut Valley's plant assets and franchise to PSNH. The sale to PSNH was completed on January 1, 2004.
Revenues Electricity sales to customers are based on monthly meter readings. Estimated unbilled revenues are recorded at the end of each monthly accounting period. In order to determine unbilled revenues, we make various estimates including: 1) energy generated, purchased and resold; 2) losses of energy over transmission and distribution lines; 3) kilowatt-hour usage by retail customer mix - residential, commercial and industrial; and 4) average retail customer pricing rates. We use these estimated amounts to calculate the amount of revenue that has been earned, but not billed, due to the timing of billing cycles used for retail customers.
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Pension and Postretirement Benefits We record pension and other postretirement benefit costs in accordance with SFAS No. 87, Employers' Accounting for Pensions, and SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. Assumptions are made regarding the valuation of benefit obligations and performance of plan assets. Delayed recognition of differences between actual results and those assumed is a required principle of these standards. This approach allows for systematic recognition of changes in benefit obligations and plan performance over the working lives of the employees who benefit under the plans. The following assumptions are reviewed annually, for a September 30 measurement date:
Pension costs were $4.4 million in 2005, $3.2 million in 2004 and $2.5 million in 2003. Of these amounts, $3.7 million is reflected in results of operations in 2005, $2.7 million in 2004 and $2.1 million in 2003, with the remaining amounts capitalized.
Postretirement costs were $2.8 million in 2005, $3.3 million in 2004 and $2.5 million in 2003. Of these amounts, $2.4 million is reflected in results of operations in 2005, $2.8 million in 2004 and $2.1 million in 2003, with the remaining amounts capitalized.
Pension costs and cash funding requirements are expected to increase in future years. As of December 31, 2005, the market value of pension plan trust assets was $66.4 million, including $45.7 million in marketable equity securities and $20.7 million in debt securities. Pension plan trust assets were $64.2 million at December 31, 2004, including $44.3 million in marketable equity securities and $19.9 million in debt securities. The fair value of Postretirement Plan trust assets was $6.2 million at December 31, 2005, compared to $5.0 million at December 31, 2004.
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Pension and Postretirement Assumption Sensitivity Analysis Fluctuations in market returns may result in increased or decreased pension costs in future periods. The table below shows how a 25-basis-point change in discount rate and expected return on assets would affect pension costs. Any additional decreases in the discount rate would increase the charge to equity by the same amount as the Accumulated Benefit Obligation.
|
|
|
|
25 Basis-point |
25 Basis-point |
|
Pension Plan as of October 1, 2005 Effect on 2005 net period benefit cost Other Postretirement Benefit Plans Effect on accumulated postretirement benefit obligation as of October 1, 2005 Effect on 2005 net periodic benefit cost |
|
|
|
|
Derivative Financial Instruments
We account for various power contracts as derivatives under the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted and SFAS No. 149, Amendment of Statement 133 Derivative Instruments and Hedging Activities, (collectively "SFAS No. 133"). These statements require that derivatives be recorded on the balance sheets at fair value.
We have a long-term purchased power contract that allows the seller to repurchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative under SFAS No. 133. The derivative's estimated fair value was an unrealized loss of $5.0 million at December 31, 2005 and $5.7 million at December 31, 2004. The estimated fair value of this derivative is valued using a binomial tree model, and quoted market data when available along with appropriate valuation methodologies.
We have a long-term forward sale contract for the sale of about 15 MW per hour, or a total of 522,544 mWh, beginning November 17, 2004 through December 31, 2008. As of December 31, 2005 about 141,800 mWh have been delivered under the contract. This contract has been determined to be a derivative under SFAS No. 133. We utilize over-the-counter quotations or broker quotes at the end of the reporting period for determining the fair value of this contract. The derivative's estimated fair value was an unrealized loss of $12.9 million at December 31, 2005 and a $0.4 million unrealized gain at December 31, 2004.
The fair value of the forward sale contract at December 31, 2005 reflects a combination of rising spot and futures prices for natural gas and oil due to increased global demand and production and refining cutbacks resulting from the 2005 hurricane season that are now reflected in the current and projected price of electric energy, especially in New England.
Based on a PSB-approved Accounting Order, we record the change in fair value of these derivatives as deferred charges or deferred credits on the balance sheet, depending on whether the fair value is an unrealized loss or gain. The corresponding offsets are recorded as current and long-term assets or liabilities depending on the duration.
Decommissioning Cost Estimates Accounting for decommissioning costs of nuclear power plants involves significant estimates related to decommissioning costs to be incurred many years in the future. Primary drivers of changes to these estimates include, but are not limited to, increases in projected costs of spent fuel storage, security and liability and property insurance. We own, through equity investments, 2 percent of Maine Yankee, 2 percent of Connecticut Yankee and 3.5 percent of Yankee Atomic. All three plants are completely shut down and are conducting decommissioning activities. We are responsible for paying our equity ownership percentage of decommissioning costs and all other costs for these plants.
As of December 31, 2005, based on the most recent estimates provided, our share of remaining costs to decommission these nuclear units is about $4.8 million for Maine Yankee, $10.3 million for Connecticut Yankee and $5.2 million for Yankee Atomic. In addition, we paid about $0.7 million to Yankee Atomic for incremental
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decommissioning costs that are now being recovered in retail rates pursuant to the Rate Order. These amounts are recorded in the accompanying Consolidated Balance Sheet as nuclear decommissioning liabilities (current and non-current) with a corresponding regulatory asset. We will adjust associated regulatory assets and nuclear decommissioning liabilities when revised estimates are provided. Pursuant to the Rate Order, beginning April 1, 2006, we will defer any differences between actual decommissioning cost payments and amounts included for rate recovery, until our next rate proceeding.
Historically, our share of these costs has been recovered from retail customers through PSB-approved rates. Based on the regulatory process, we believe our share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process. There is a risk, however, that FERC may not allow full recovery of Connecticut Yankee's increased costs in wholesale rates. See Power Supply Matters - Nuclear Generating Companies below for more information.
We are also responsible for our 1.7303 joint-ownership percentage of Millstone Unit #3 decommissioning costs, and we have an external trust to fund our share of decommissioning costs. Contributions to the Trust Fund have been suspended based on the lead owner's representation to various regulatory bodies that the Trust Fund, for its share of the plant, exceeded the Nuclear Regulatory Commission's ("NRC") minimum calculation required. We could choose to renew funding at our discretion as long as the minimum requirement is met or exceeded. We were recovering these costs in retail rates prior to April 1, 2004 and, pursuant to the Rate Order, the costs are being returned to ratepayers through amortization of the regulatory liability that we had established for the over-collections.
Reserve for Loss on Power Contract In accordance with the requirements of SFAS No. 5, Accounting for Contingencies, ("SFAS No. 5") in the first quarter of 2004, we recorded a $14.4 million pre-tax loss accrual related to termination of our long-term power contract with Connecticut Valley. The contract was terminated in the first quarter of 2004, as a condition of the January 1, 2004 sale of Connecticut Valley's plant assets and franchise. The loss accrual represented Management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the cost of purchased power obligations. The estimated life of the power contracts that were in place to supply power to Connecticut Valley extends through 2015.
The loss accrual was estimated based on assumptions about future power prices, the reallocation of power from the state-appointed purchasing agent ("VEPPI") and future load growth. Management reviews this estimate at the end of each reporting period and will increase the reserve if the revised estimate exceeds the recorded loss accrual. The loss accrual is being amortized on a straight-line basis through 2015.
Income Taxes In accordance with SFAS No. 109, Accounting for Income Taxes ("SFAS No. 109"), we recognize tax assets and liabilities for the cumulative effect of all temporary differences between financial statement carrying amounts and the tax basis of assets and liabilities. Investment tax credits associated with utility plant are deferred and amortized ratably to income over the lives of the related properties. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets if management determines it is more likely than not such tax assets will not be realized.
RESULTS OF OPERATIONS
The following is a discussion of the Company's results of operations for the past three years. This should be read in conjunction with the consolidated financial statements and accompanying notes included in this report.
Consolidated Summary:
Consolidated 2005 earnings were $6.3 million, or 49 cents per basic and 48 cents per diluted share of common stock. Consolidated 2004 earnings were $23.8 million, or $1.93 per basic and $1.90 per diluted share of common stock, while consolidated 2003 earnings were $19.8 million, or $1.57 per basic and $1.53 per diluted share of common stock.
In 2005 earnings from continuing operations were $1.4 million, or 9 cents per basic and 8 cents per diluted share of common stock. This reflects a $21.8 million pre-tax charge to earnings in the first quarter of 2005 related to the Rate Order. In 2004 earnings from continuing operations were $7.5 million, or 59 cents per basic and 58 cents per diluted share of common stock, and in 2003 $17.1 million, or $1.35 per basic and $1.32 per diluted share of common stock.
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In 2005 earnings from discontinued operations were $4.9 million, or 40 cents per basic and diluted share of common stock. This reflects a $5.6 million after-tax gain on the December 20, 2005 sale of Catamount. In 2004 earnings from discontinued operations were $16.3 million, or $1.34 per basic and $1.32 per diluted share of common stock. This reflects a $12.3 million after-tax gain on the January 1, 2004 sale of Connecticut Valley's assets and franchise. In 2003 earnings from discontinued operations were $2.7 million, or 22 cents per basic and 21 cents per diluted share of common stock.
For accounting purposes, components of the 2004 Connecticut Valley transaction were recorded in both continuing and discontinued operations. Although, the after-tax gain on the asset sale totaled $12.3 million, continuing operations recorded an after-tax loss on power costs of $8.4 million relating to termination of a power contract with Connecticut Valley. When the two accounting transactions are combined to assess the total impact of the transaction, the result was a gain of $3.9 million, or $.31 per diluted share of common stock, in 2004.
The following table provides a reconciliation of the year-over-year effects on 2005 versus 2004 diluted earnings per share.
|
2004 Earnings per diluted share SFAS No. 5 loss accrual - termination of power contract in 2004 Vermont utility 11 percent allowed rate of return in 2004 Higher retail and firm sales (excluding Rate Order refund) IRS tax settlement received in 2004 Higher transmission and distribution costs Higher purchased power costs (excluding Rate Order charge) Higher other costs (excluding Rate Order charges and 2004 SFAS No. 5 loss accrual) Sub-total Net impact of March 29, 2005 Rate Order recorded in the first quarter of 2005 Discontinued Operations: Gain on December 20, 2005 Catamount sale Gain on January 1, 2004 CVEC sale Results of discontinued operations Sub-total 2005 Earnings per diluted share |
|
$1.90 |
The following table provides a reconciliation of the year-over-year effects on 2004 versus 2003 diluted earnings per share.
|
2003 Earnings per diluted share |
$1.53 |
|
|
Continuing operations: |
||
|
Higher retail and firm sales |
.18 |
|
|
IRS tax settlement received in the second quarter of 2004 |
.09 |
|
|
Higher resale sales |
.09 |
|
|
Lower purchased power costs - excluding SFAS No. 5 loss accrual |
.08 |
|
|
Higher other operating revenue |
.05 |
|
|
Other |
.02 |
|
|
Vermont utility allowed rate of return at 11 percent |
(.06) |
|
|
Power contract termination related to Connecticut Valley SFAS No. 5 loss accrual - termination of power contract in 2004 (a) |
(.50) |
|
|
Subtotal |
(.74) |
|
|
Discontinued Operations: |
||
|
Gain on January 1, 2004 CVEC sale (a) |
1.00 |
|
|
Subtotal |
1.11 |
|
|
2004 Earnings per diluted share |
$1.90 |
|
|
(a) Combining the two CVEC transactions results in a $.31 per share gain. |
||
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Consolidated Income Statement Discussion
The following includes a more detailed discussion of the components of our Consolidated Statements of Income and related year-over-year variances.
Operating Revenues The majority of our operating revenues are generated through retail sales from the regulated Vermont utility business. Other resale sales are related to the sale of excess power from our owned and purchased power supply portfolio. Operating revenues and related mWh sales are summarized below:
|
mWh Sales |
Revenues (in thousands) |
|||||
|
2005 |
2004 |
2003 |
2005 |
2004 |
2003 |
|
|
Retail sales: |
|
|
|
|
|
|
The average number of retail customers is summarized below:
|
2005 |
2004 |
2003 |
|
|
Residential |
129,943 |
128,665 |
127,881 |
Comparative changes in Operating revenues are summarized below (in thousands):
|
2005 vs. 2004 |
2004 vs. 2003 |
|
|
Retail revenues: |
|
|
2005 vs. 2004
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2004 vs. 2003
Operating revenues decreased $3.8 million, or 1.3 percent, in 2004 compared to the same period in 2003 due to the following factors:
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Purchased Power Our purchases of power constituted about 57 percent of total operating expenses in 2005 and 2004, and about 54 percent in 2003. Most of our power purchases are made under long-term contracts. These contracts and other power supply matters are discussed in more detail in Power Supply Matters below. Purchased power expense and related mWh purchases are summarized below:
|
mWh Purchases |
Purchases (in thousands) |
|||||
|
2005 |
2004 |
2003 |
2005 |
2004 |
2003 |
|
|
VYNPC (a) (b) |
1,430,155 |
1,343,629 |
1,547,771 |
$57,266 |
$58,704 |
$65,581 |
|
(a) Purchased power transactions with affiliates. Amounts shown in the table above are adjusted for regulatory amortizations and |
||||||
Comparative changes in Purchased Power are summarized below (in thousands):
|
2005 vs. 2004 |
2004 vs. 2003 |
|
|
VYNPC |
$(1,438) |
$(6,877) |
2005 vs. 2004
Purchased power expense increased $6.0 million, or 3.6 percent, in 2005 compared to 2004 due to the following factors:
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rate recovery of net replacement power costs not currently included for recovery in our retail rates. See Power Supply Matters below. Additionally, replacement energy deferrals for Millstone Unit #3 refueling outages were about $0.4 million higher than 2004 and we deferred about $0.8 million in 2004 related to a Vermont Yankee plant outage with no comparable deferral in 2005. The net increase of about $0.5 million is included in Other in the detailed table above.
2004 vs. 2003
Purchased power expense increased $12.7 million, or 8.3 percent, in 2004 compared to 2003 as a result of the following factors:
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Operating Expenses Operating expenses represent costs incurred to support our core business. The variances in income statement line items for Operating Expenses on the Consolidated Statements of Income for the past two years are shown in the table below (in thousands). First quarter 2005 effects of the Rate Order are shown separately and are discussed in more detail under the caption 2005 Rate Order below.
|
2005 over/(under) 2004 |
2004 over/(under) 2003 |
|||||
|
Related to |
Related to |
Total |
|
Total |
|
|
|
Operation |
|
|
|
|
|
|
Production: These expenses are associated with generating electricity from our wholly and jointly owned units. The increase in 2005 was primarily related to higher fuel costs at two of our jointly owned generating units. There was no significant variance for 2004 versus 2003.
Transmission - affiliates and other: These expenses are associated with transmission of electricity. The increase in 2005 is primarily related to higher ISO-New England transmission costs due to higher rates under the NEPOOL open access transmission tariff, higher VELCO demand-based charges, and other costs, partially offset by lower Hydro-Quebec Phase I and Phase II support charges and our share of Highgate savings. There was no significant variance for 2004 versus 2003. See Transmission Matters below.
Other operation: These expenses are related to operating activity such as customer accounting, customer service, administrative and general, regulatory deferrals and amortizations, and other operating costs incurred to support our core business. The decrease in 2005, excluding the Rate Order charge, was primarily related to $3.8 million of deferred earnings in 2004 to achieve an 11 percent return on equity, and lower employee-related costs including incentive compensation, medical costs and long-term disability. Additionally, 2004 included consulting expenses related to an IRS tax settlement. These favorable items were partly offset by higher pension costs, and a favorable environmental settlement in 2004 with no comparable item in 2005. The $10.7 million Rate Order charge primarily resulted from the calculation of overearnings for 2001 - 2003 as described below.
The increase for 2004 included a net deferral of earnings related to reducing the Vermont utility's earnings to achieve an 11 percent return on equity. In 2004, based on a PSB-approved Accounting Order, this amounted to a $3.8 million pre-tax expense. In 2003, per the July 2001 PSB-approved rate order, this amounted to a $2.5 million pre-tax expense. In both years, we recorded related regulatory liabilities for these amounts. Other items included increased costs associated with pension and medical, higher pole attachment expenses that are offset in operating revenue above, higher professional services costs related to Sarbanes-Oxley project readiness, the rate case and general legal expenses, and higher bad debt expense related to a second quarter 2004 customer bankruptcy. These increased costs were partially offset by the favorable impact of an insurance settlement received in the second quarter of 2004 and the favorable impact of conservation and load management amortizations that ended in 2003.
Maintenance: These expenses are related to costs associated with maintaining our electric distribution system and include costs from our jointly owned generating and transmission facilities. The increase is primarily related to higher storm restoration costs due to a major storm in October 2005, and higher contractor costs for an annual maintenance outage at McNeil, one of our jointly owned generating units. There was no significant variance for 2004 versus 2003.
Depreciation: We use the straight-line remaining-life method of depreciation. There was no significant variance for 2005 versus 2004 or for 2004 versus 2003.
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Other taxes, principally property taxes: This is primarily related to property taxes and payroll taxes. There was no significant variance for 2005 versus 2004 or for 2004 versus 2003.
Taxes on Income: Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences, tax credits, tax settlements and changes in valuation allowances for the periods. The effective combined federal and state income tax rate was 309.8 percent for 2005, 21.6 percent for 2004 and 37.1 percent for 2003. The effective tax rate increased significantly in 2005 because we had a pre-tax loss of $0.7 million on continuing operations. When the tax benefits of permanent differences and income tax credits are combined with the tax benefit based on the pre-tax loss, the result is an effective tax rate of 309.8 percent. The effective tax rate for 2004 decreased when compared to 2003 primarily due to a decrease in the estimate for tax contingencies and an increase in income tax refunds.
The American Jobs Creation Act of 2004 ("Act") amended Section 45 of the IRS Code to allow a renewable electricity production credit for the production of electricity by certain closed-loop facilities. Our McNeil wood chip plant qualifies for this tax credit, which amounted to $0.2 million in 2005. This tax credit, which is based upon the megawatt hours of electricity produced, is expected to be about the same amount for each of the next four years.
On June 7, 2004, the State of Vermont enacted legislation that reduced the state income tax rate from 9.75 percent to 8.9 percent effective January 1, 2006, and from 8.9 percent to 8.5 percent effective January 1, 2007.
See Note 11 to the Consolidated Financial Statements for additional information related to Income Taxes.
Other Income and Deductions These items are related to the non-operating activities of the utility business and the operating and non-operating activities of our non-regulated businesses. The variances in income statement line items for Other Income and Other Deductions on the Consolidated Statements of Income for the past two years are shown in the table below (in thousands). First quarter 2005 effects of the Rate Order are shown separately and are discussed in more detail under the caption 2005 Rate Order below.
|
2005 over/(under) 2004 |
2004 over/(under) 2003 |
|||||
|
Related to |
Related to |
Total |
|
Total |
|
|
|
Equity in earnings of affiliates |
$644 |
- |
$644 |
52.6% |
$(576) |
(32.0)% |
Equity in earnings of affiliates: These are related to our equity investments, VELCO and VYNPC. The increase in 2005 is mostly related to our share of higher VELCO earnings associated with the additional equity investment that we made in the fourth quarter of 2004. For 2004 the decrease was primarily related to higher VYNPC interest income in 2003, because the Vermont Yankee sale proceeds were not distributed to stockholders until the fourth quarter of 2003.
Allowance for equity funds during construction: This is the cost of equity financing during construction projects. It is capitalized as part of major utility plant projects when costs applicable to such construction work in progress have not been included in rate base through ratemaking proceedings. There was no significant variance for 2005 versus 2004 or for 2004 versus 2003.
Other income: These income items include non-operating rental income mostly from Eversant's rental water heater business, interest and dividend income, interest on temporary investments, regulatory asset carrying costs, amortization of contributions in aid of construction and various miscellaneous other income items. The decrease in 2005, excluding the Rate Order charge, was primarily related to regulatory carrying charges in 2004 that were eliminated as a result of the Rate Order and about $1.0 million related to favorable IRS tax settlements received in 2004. The $0.8 million decrease related to the Rate Order resulted from required adjustments to carrying charges for deferred Vermont Yankee sale costs and Vermont Yankee fuel rod costs as described below.
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The increase in 2004 was primarily due to higher interest income on temporary investments and available-for-sale securities, resulting from investment of cash proceeds from the Connecticut Valley sale and other cash on hand in early 2004. Other factors include higher interest and dividend income primarily related to IRS tax settlements in 2004, offset by lower miscellaneous other income.
Other Deductions: These deductions include supplemental retirement benefits and insurance, including changes in the cash surrender value of life insurance policies, non-utility expenses relating to our water heating business, and miscellaneous other deductions. The increase in 2005, excluding the Rate Order charge, includes about $0.6 million related to impairment and realized losses associated with certain available-for-sale debt securities that were sold earlier than planned, and higher insurance expense due to about $0.5 million of death benefit proceeds received in 2004. The $0.4 million related to the Rate Order was due to disallowance of a portion of Vermont Yankee fuel rod costs as described below. There was no significant variance for 2004 versus 2003.
Benefit (provision) for income taxes: Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences, tax credits, tax settlements and changes in valuation allowances for the periods.
Interest Expense
Interest expense includes interest on long-term debt, dividends associated with mandatory redeemable preferred stock and other interest. The variances in income statement line items for Interest Expense on the Consolidated Statements of Income for the past two years are shown in the table below (in thousands). First quarter 2005 effects of the Rate Order are shown separately and are discussed in more detail under the caption 2005 Rate Order below.|
2005 over/(under) 2004 |
2004 over/(under) 2003 |
|||||
|
Related to |
Related to |
Total |
|
Total |
|
|
|
Interest on long-term debt |
$(1,454) |
- |
$(1,454) |
(16.8)% |
$(1,935) |
(18.3)% |
Interest on long-term debt: The decreases for 2005 versus 2004 and 2004 versus 2003 resulted from lower interest rates due to the August 2004 bond refinancing. On July 30, 2004, we issued $20 million of 5 percent First Mortgage Bonds, due in 2011, and $55 million of 5.72 percent First Mortgage Bonds, due in 2019. The proceeds were used to repay in full our $75 million Second Mortgage Bonds, at a rate of 8.125 percent that matured on August 1, 2004. The refinancing and lower interest rates will reduce annual interest expense by about $2 million on a pre-tax basis.
Other interest expense: The increase in 2005 was related to recovery of interest from a favorable IRS tax settlement in 2004, partially offset by dividends on mandatorily redeemable preferred stock described below. The Rate Order increase is primarily related to carrying costs associated with the recalculation of overearnings for 2001 - 2003 as described below. The increase for 2004 versus 2003 was primarily related to the reclassification of dividends on mandatorily redeemable preferred stock to interest expense as described in Dividends on preferred stock below, and increased carrying costs on regulatory liabilities. This was partially offset by interest related to a 2004 IRS tax settlement.
Allowance for borrowed funds during construction: This is the cost of debt financing during construction projects that we capitalize as part of the cost of major utility plant projects when costs applicable to such construction work in progress have not been included in rate base through the ratemaking process. There was no significant variance in these expenses for 2005 versus 2004 or 2004 versus 2003.
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Discontinued Operations Includes Catamount and Connecticut Valley as described in Discontinued Operations above. The components of the year-over-year variances are shown below (in thousands).
2005 over/(under) 2004 |
2004 over/(under) 2003 |
|
Gain on Dec. 20, 2005 Catamount sale |
$5,607 |
$- |
Catamount:
The sale resulted in a $5.6 million after-tax gain. Catamount's 2005 results of operations were lower than 2004 primarily due to 2004 gains and related tax benefits totaling $4.4 million from sale of certain of its investments. The increase for 2004 versus 2003 was due in part to the sales of certain of Catamount's investments in 2004.|
Income Statement Line Item Purchased Power (#4 below) Other Operation (#1, 2, 3 and 4 below) Other Income (#4 below) Other Deductions (#4 below) Other Interest (#1, 3 and 4 below) Total Rate Order Impact |
|
The primary components of the charge to earnings includes: 1) a revised calculation of overearnings for the period 2001 - 2003; 2) application of the gain resulting from termination of the power contract with Connecticut Valley to reduce costs; 3) a customer refund for the period April 7, 2004 through March 31, 2005; and 4) amortization of costs and other adjustments required in the Rate Order. These are described in more detail below (all on a pre-tax basis).
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we amortize the resulting $15.3 million regulatory liability, which includes amounts previously deferred, over a four-year period ($3.8 million annually) beginning April 1, 2004. In the first quarter of 2005, we recorded a net $8.3 million charge to earnings. This included a $10.8 million charge to operating expense and $1.3 million to interest expense, offset by amortization of $3.8 million.
POWER SUPPLY MATTERS
Sources of Energy Our power supply portfolio includes a mix of base load, dispatchable and energy-constrained schedulable resources. A breakdown of energy sources is shown below:
|
2005 |
2004 |
2003 |
|
|
Nuclear generating companies |
46% |
46% |
50% |
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Our joint-ownership interests include 1.73 percent in Unit #3 of the Millstone Nuclear Power Station, 20 percent in Joseph C. McNeil, a 53-MW wood-, gas- and oil-fired unit, and 1.78 percent joint-ownership in Wyman #4, a 619-MW oil-fired unit. Our wholly owned units include 20 hydroelectric generating units, two oil-fired gas turbines and one diesel peaking unit with a combined nameplate capability of 73.6 MW. We also have equity ownership interests in three nuclear power plants that have all been permanently shut down. Our obligations related to nuclear plant decommissioning is described in Nuclear Generating Companies below.
We have a long-term power contract with Hydro-Quebec and a long-term power contract for purchase of about 35 percent of Vermont Yankee plant output. Combined, these two contracts contributed about 84 percent of our total energy (mWh) purchases in 2005, compared to 84 percent in 2004 and 90 percent in 2003. We are also required to purchase power from various Independent Power Producers under long-term contracts. These contracts are discussed in more detail below.
Power Contract Commitments
Hydro-Quebec We purchase a significant part of our power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract and related contracts negotiated between us and Hydro-Quebec, which extend through 2016. There are specific contractual provisions that provide that in the event any VJO member fails to meet its obligation under the contract with Hydro-Quebec, the remaining VJO participants, including us, must "step-up" to the defaulting party's share on a pro rata basis. The VJO contract runs through 2020, but our purchases related to the contract end in 2016. As of December 31, 2005, our obligation is about 47 percent of the total VJO Power Contract through 2016, which translates to about $606 million, on a nominal basis. The average annual amount of capacity that we will purchase from January 1, 2006 through October 31, 2012 is about 144.7 MW, with lesser amounts purchased through October 31, 2016.
In the early phase of the VJO Power Contract, two sellback contracts were negotiated, the first delaying the purchase of 25 MW of capacity and associated energy, the second reducing the net purchase of Hydro-Quebec power through 1996. In 1994, we negotiated a third sellback arrangement whereby we received a reduction in capacity costs from 1995 to 1999. In exchange for this sellback, Hydro-Quebec obtained two options. The first gives Hydro-Quebec the right upon four years written notice, to reduce capacity deliveries by 50 MW beginning as early as 2010, including the use of a like amount of the Company's Phase I/II transmission facility rights. The second gives Hydro-Quebec the right, upon one years written notice, to curtail energy deliveries in a contract year (12 months beginning November 1) from an annual load factor of 75 to 50 percent due to adverse hydraulic conditions in Quebec. This second option can be exercised five times through October 2015.
Under the VJO Power Contract, the VJO can elect to change the annual load factor from 75 percent to between 70 and 80 percent five times through 2020, while Hydro-Quebec can elect to reduce the load factor to not less than 65 percent three times during the same period of time. Hydro-Quebec has used all of its elections, resulting in a 65 percent load factor obligation from November 1, 2002 to October 31, 2005. The VJO recently elected to purchase at an 80 percent load factor for the current contract year beginning November 1, 2005 and ending October 31, 2006. The VJO now have one load factor election remaining.
VYNPC We have a 35 percent entitlement to Vermont Yankee plant output sold by Entergy Nuclear Vermont Yankee, LLC ("ENVY") to VYNPC, through a long-term power purchase contract ("PPA") with VYNPC. One remaining secondary purchaser continues to receive a small percentage of our entitlement, reducing our entitlement to about 34.83 percent. ENVY has no obligation to supply energy to VYNPC over the amount the plant is producing, so entitlement holders receive reduced amounts when the plant is operating at a reduced level, and no energy when the plant is not operating. The plant normally shuts down for about one month every 18 months for maintenance and to insert new fuel into the reactor.
The plant's last scheduled refueling outage began on October 22, 2005 and was originally expected to end about November 20 but it resumed production on November 10, 2005 followed by a three day ramp-up to full power. Prior to the outage, we purchased forward supplies of replacement energy at a fixed price of about $115 per mWh for the expected outage duration to minimize exposure to spot market energy price volatility. The price for replacement power was significantly higher than what is currently being recovered in retail rates. Ultimately, the net replacement power costs related to the refueling outage amounted to about $5.4 million.
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On December 23, 2005, we filed a request for an Accounting Order from the PSB to defer $4.7 million of the net incremental replacement power costs for recovery in our next rate proceeding, representing the incremental amount above those already embedded in current retail rates. Our request also included approval to apply the $1.1 million credit we received through VYNPC power bills in 2005 to reduce the deferral. If the PSB approves our request, the result would be a net deferral of $3.6 million for recovery in our next rate proceeding. On March 6, 2006, the DPS asked the PSB to deny our request, and recommended that the $1.1 million credit and unrelated savings from the increased VJO load factor be recorded as regulatory liabilities for return to ratepayers. Due to settlement discussions with the DPS and other timing issues, the PSB has deferred ruling on our request or on the DPS recommendations. Absent an approved Accounting Order, recovery of these costs is uncertain, so we were not able to defer the $4.7 million of net costs or offset them with the $1.1 million credit that is currently recorded as a deferred credit on the Consolidated Balance Sheet. Therefore, the purchases of replacement power are included in purchased power expense and related resale sales are included in operating revenue on the Consolidated Statement of Income.
VYNPC's power billings to us include our share of distributions from Nuclear Electric Insurance Limited ("NEIL") and similar insurance providers. Pursuant to PSB approval of the Vermont Yankee sale, the credits must benefit ratepayers through programs to promote renewable resources. As such, these items are recorded as regulatory liabilities, including the $1.1 million credit, or reduction, in our June 2005 power billing from VYNPC, representing our share of the settlement of a tax dispute payment received by VYNPC from the IRS.
In March 2004, the PSB approved ENVY's request to increase generation at the Vermont Yankee plant by 110 megawatts. The PSB's approval included a condition that ENVY provide outage protection indemnification ("Ratepayer Protection Proposal" or "RPP") for times the uprate causes reductions in output that reduce the value of the PPA. Our maximum right to indemnification under the RPP is about $2.8 million for the three-year period beginning in May 2004 and ending after completion of the uprate (or a maximum of three years).
Plant output has been reduced since the April 2004 scheduled refueling outage, and will continue until ENVY receives NRC approval for the uprate. Our entitlement was reduced by an average of about 4 MW during this period. The financial effect of such a reduction will be covered under the terms of the RPP. Additionally, we have sought recovery from ENVY, under the RPP, for incremental replacement energy costs incurred when the plant was shut down for 19 days beginning in mid-June 2004. We believe the plant went off line due to problems associated with uprate-related improvements made by ENVY, and sought about $0.8 million from ENVY. ENVY contends that the problem would have occurred regardless of the uprate. Having failed to reach a settlement with ENVY, we petitioned the PSB for resolution.
There are risks that may not be covered under the RPP. After the Vermont Yankee plant uprating is complete, our percentage of energy output under the PPA would decline proportionately such that we would receive the same quantity of energy from the plant. Four other nuclear plants with steam dryers similar to Vermont Yankee's have experienced problems, and all were required to return to their pre-uprate power level until the problems were corrected. If such a problem were to occur with the Vermont Yankee plant's uprate, it is possible that under the PPA, our entitlement to plant output could be reduced proportionately to the derating until operation is permitted at the post-uprate MW level. While this risk is mitigated in part by additional, controlled testing, during the process of increasing power output, under the supervision of the NRC and DPS, we estimate that this could have a material adverse effect on net power costs.
The NRC gave final approval to the uprate on March 2, 2006. If the uprate were to be ultimately unsuccessful, it is also possible that the plant could be shut down earlier than its current licensed life. Any material reduction in output that is not compensated under the terms of the RPP or otherwise by ENVY could have a material impact on the Company's financial position and results of operations, if those increased costs are not recovered in retail rates in a timely fashion.
On March 16, 2006, we, Green Mountain Power, ENVY and the DPS filed a settlement with the PSB resolving all issues raised in the petition before the PSB, plus the related derate issue described above. The settlement would resolve all issues through February 28, 2006. Our share of the settlement is estimated to be about $1.6 million including $0.7 million related to the June 2004 outage described above and the remaining for uprate-related costs. Pursuant to the Rate Order, any partial or full reimbursement received by us from ENVY under the RPP shall be
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recorded as a regulatory liability for return to ratepayers in our next rate proceeding. The settlement is not effective until the PSB issues a final order. We cannot predict the timing or outcome of this matter at this time.
In April 2004, ENVY reported that two short spent fuel rod segments were not in what ENVY believed to be their documented location in the spent fuel pool. Subsequently, ENVY's continuing documentation review led to the discovery of the fuel rod segments in a container in the spent fuel pool. During that time, ENVY notified VYNPC that based on the terms of the Purchase and Sale Agreement dated August 1, 2001, and facts at the time, it was their view that costs associated with the spent fuel rod segment inspection effort were the responsibility of VYNPC. VYNPC responded that based on the information at the time there was no basis for ENVY's claim. While this has not been fully resolved with ENVY, we do not believe that we have any potential liability related to this matter.
ENVY has announced that, under current operating parameters, it will exhaust the capacity of its nuclear waste (spent fuel) storage pool in 2007 or 2008 and will need to store nuclear waste in so-called 'dry cask storage' facilities to be constructed on the site. Construction and use of such dry cask storage facilities requires approval from the Vermont State Legislature, in addition to PSB approval. In early June 2005, the Vermont State Legislature passed a law authorizing ENVY to construct and use dry cask storage facilities on the site through its current license. In late June 2005, ENVY filed an application with the PSB for permission to install dry cask storage facilities at the site. At this time the PSB has not ruled on ENVY's application.
If the PSB does not approve dry cask storage, ENVY has announced that it could be required to shut down the Vermont Yankee plant in 2007 or 2008, instead of its current license life of 2012. If the Vermont Yankee plant is shut down, we would lose about 50 percent of its committed energy supply and would have to acquire replacement power resources comprising about 40 percent of its estimated power supply needs. Based on projected market prices, the value of the lost output is estimated to be about $55 million on an annual basis. Based on this estimate, we would require a retail rate increase of about 20 percent for full cost recovery. We are not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB will allow timely and full recovery of increased costs related to any such shutdown. The implications of an early shut down of the Vermont Yankee plant could have a material effect on the Company's financial position and future results of operations, if those costs are not recovered in retail rates in a timely fashion.
In January 2006, ENVY submitted a renewal application with the NRC for a 20-extension of the Vermont Yankee plant operating license. If approved it would allow the plant to operate until 2032. ENVY will also need approval from the PSB to keep operating beyond 2012. Our purchases under the PPA will end in 2012. The Vermont Legislature is considering legislation that would require its approval for any license extension at the plant.
Independent Power Producers ("IPPs") We purchase power from a number of IPPs that own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy primarily using hydroelectric and biomass generation. Most of the power comes through a state-appointed purchasing agent, VEPP Inc. ("VEPPI"), which assigns power to all Vermont utilities under PSB rules. Estimated purchases from IPPs are expected to be $18.5 million in 2006, $18.8 million in 2007, $19.1 million in 2008, $17.9 million in 2009 and $17.8 in 2010. These amounts reflect annual savings of about $0.4 million related to an IPP settlement in 2003.
Wholly Owned Generating Units We own and operate 20 hydroelectric generating units, two oil-fired gas turbines and one diesel peaking unit with a combined nameplate capability of about 74.2 MW.
In January 2003, we, the Vermont Agency of Natural Resources ("VANR"), Vermont Natural Resources Council and other parties reached an agreement to allow us to relicense the four dams we own and operate on the Lamoille River. According to the agreement, we were to receive a water quality certificate from the State, which is needed for FERC to relicense the facilities for 30 years. The agreement also stipulates that subject to various conditions, we must begin decommissioning Peterson Dam in about 20 years. The agreement requires PSB approval of full rate recovery related to decommissioning the Peterson Dam, including recovery of replacement power costs when the dam is out of service. In July 2003, the VANR published its draft water quality certificate. In October 2003, pursuant to the schedule set forth in the agreement, we filed a petition with the PSB for approval of the rate recovery mechanisms, and the case has continued to progress through the regulatory process.
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In June 2005, FERC issued a 30-year license for the four dams including Peterson Dam. While FERC determined that the VANR waived its rights to issue a water quality certificate, the license includes conditions, previously agreed upon by us, the DPS, VANR and other parties, relating to project operations, fish and wildlife, recreation, land use, and historic properties. The license does not include conditions relating to decommissioning of Peterson Dam in 20 years, or cost recovery. These issues are under review by the PSB, and we expect that the PSB's draft decision will be issued for comment in the first half of 2006.
We and the VANR asked for rehearing of the June 2005 FERC order, and in November 2005, FERC issued a decision upholding its order and denying rehearing requests. The decision also clarified certain terms of the license. In January 2006, we and the VANR filed timely appeals in federal court. In response to a motion by VANR, which was unopposed by the FERC Staff and us, the federal court has stayed all action on the appeals until completion of the proceedings before the PSB and further filings by the parties to determine the future proceedings in the appeals. The 30 year license remains in effect during such appeals. We cannot predict the outcome of these matters at this time.
Millstone Unit #3 We have a 1.7303 percent joint-ownership interest in Millstone Unit #3, in which Dominion Nuclear Corporation ("DNC") is the lead owner with about 93.47 percent of the plant joint-ownership. We have an external trust dedicated to funding our joint-ownership share of future decommissioning costs.
In January 2004, DNC filed, on behalf of itself and the two minority owners, including the Company, a lawsuit against the DOE seeking recovery of costs related to storage of spent nuclear fuel arising from the failure of the DOE to comply with its obligations to commence accepting such fuel in 1998. The schedule for further proceedings in the lawsuit is not known at this time. Millstone Unit #3 spent fuel from the beginning of commercial operations in 1986 resides in the spent fuel pool. We continue to pay our share of the DOE Spent Fuel assessment expenses levied on actual generation and will share in recovery from the lawsuit, if any, in proportion to our ownership interest. On November 28, 2005, the NRC renewed the operating license for Millstone Unit #3 for an additional 20 years. This extends the licensed life from November 2025 to November 2045.
In the fourth quarter of 2005, Millstone Unit #3 performed its scheduled refueling outage that extended from September 29 until October 27. Based on approved regulatory accounting treatment, we defer the cost of incremental replacement energy and incremental maintenance costs of the scheduled refueling outage, and are allowed to amortize those costs through the next scheduled refueling outage, which typically spans over an 18-month period. We purchased replacement power through ISO-New England during the outage period. We deferred about $1.4 million for incremental replacement power costs and $0.5 million for incremental maintenance costs related to the scheduled refueling outage.
Power Supply Management Our long-term power forecast shows energy purchase and production amounts in excess of our load requirements in most periods through 2011. In order to balance our power resources and power requirements, we engage in short-term purchases and sales in the wholesale markets administered by ISO-New England and with other third parties, primarily in New England. Because of our general surplus, we enter into forward sale transactions from time to time to reduce price volatility of our forecasted net power costs. At times, such as when Vermont Yankee is not operating, we may also enter into forward purchase transactions. In 2005, we entered into an agreement to purchase firm power during Vermont Yankee's scheduled refueling outage in October and early November. The costs associated with the Vermont Yankee refueling outage are described in more detail above.
In November 2004, we entered two separate forward sale transactions, one through October 2006 for an average of about 37 MW per hour and another through December 2008 for an average of about 15 MW, in order to stabilize the net cost of power to serve customer load. Delivery under the first contract is contingent on Vermont Yankee output, eliminating the risks of sourcing the sale when Vermont Yankee is not operating. We expect that future forward sales will also be contingent on Vermont Yankee output, or will be for relatively small volumes.
In addition to forward sale and purchase transactions, on an hourly basis, power is sold or bought through ISO-New England to balance our resource output and load requirements, through the normal settlement process. On a monthly basis, we aggregate the hourly sales and purchases through ISO-New England and record them as Operating Revenue or Purchased Power, respectively.
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We manage our power supply portfolio on a net basis, which is comprised of purchased power, production from our wholly and jointly units, less resale sales because resale sales help to mitigate our overall power costs. Based on existing commitments and contracts, we expect that net purchased power and production fuel costs will average $124 million per year for the years 2006 through 2010. These projections are dependent, in part, on wholesale power market prices. Because of our excess supply, increases in the wholesale price should generally reduce our net power costs, while decreases should generally increase costs.
We constantly monitor, and adapt to, changes to New England wholesale power markets. Related to these markets, in March 2003, ISO-New England implemented Standard Market Design ("SMD"), a significant step to restructuring the wholesale energy markets in the Northeast. Under SMD, there are day-ahead and real-time energy markets, and pricing for energy is location specific, depending in part on the existence of transmission constraints as well as on the concept of location-specific marginal losses. We have responded to SMD by generally using the day-ahead market to clear the majority of our load and generation, including generation resources that we self-schedule, with any remaining resources and residual load settling in the real-time market. The day-ahead energy market has generally seen slightly higher energy prices and lower price volatility than the real-time energy market. Operating reserve prices and their volatility have also generally been lower in the day-ahead market.
In the second quarter of 2005, FERC issued an initial decision on ISO-New England's proposal for a new system of capacity payments to generators that New England's state regulators fear will increase future power costs to the region's load-serving entities and thus consumers. Since we expect to have adequate capacity to serve our load through 2012 we do not expect that, if implemented, this mechanism would materially increase our costs through 2012, but we are not able to determine whether or not any such new mechanism will ultimately increase costs for consumers due to unknown future dynamics of a number of market factors.
Beginning May 1, 2004, we began to settle our power accounts with ISO-New England on a stand-alone (direct) basis. Prior to that, all Vermont utilities were settled at ISO-New England, and VELCO then performed the settlement within Vermont. With changes in power markets and NEPOOL/ISO rules and procedures, many of the benefits of a single Vermont settlement have disappeared, and direct settlement now provides advantages to us in terms of efficiency and cost savings.
Also see Item 7A. Quantitative and Qualitative Disclosures About Market Risk for a discussion of Wholesale Power Market Price Risk.
TRANSMISSION MATTERS
We operate our transmission system under an open-access tariff, pursuant to FERC Order No. 888. On March 24, 2004, FERC conditionally approved the filing made by ISO-New England and the New England transmission owners to create a Regional Transmission Organization ("RTO") for New England. The RTO parties submitted a compliance filing to FERC in December 2004, and the RTO began operating on February 1, 2005.
Currently, about one-third of the cost of New England's existing and new high-voltage transmission system (115 kV looped facilities) Pool Transmission Facility ("PTF"), is shared by all New England utilities, and by 2008 all of the PTF costs will be shared. At this time we are not able to predict the impact of other transmission costs related to the RTO. Apart from the new RTO, we expect other transmission costs will increase due to growth in new transmission facilities in New England. However, better reliability and economic power transfers elsewhere in the region benefits Vermont's reliability because of the highly integrated nature of New England's high-voltage network.
Under the RTO, Highgate and related facilities, owned by a number of Vermont utilities and VELCO, are classified as Highgate Transmission Facility ("HTF") with a five-year phase-in of Regional Network Service ("RNS") reimbursement treatment. At the end of the phase-in period, our net cost for Highgate will be based on our NEPOOL load ratio (about 2 percent) rather than our 46 percent ownership share of the facilities. Our share of savings related to reimbursements for our ownership share of the Highgate facilities are expected to be about $1.0 million in 2006, $1.4 million in 2007, $1.8 million in 2008 and $2.2 million in 2009. We received about $0.5 million of Highgate-related savings in 2005, which offset other transmission expenses.
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At this time, VELCO is planning several significant upgrades, portions of which have been approved by NEPOOL for shared cost treatment in New England-wide rates for transmission services, including the so-called Northwest Reliability Project ("NRP"). The estimated cost of the NRP is about $228 million, including a 15 percent contingency, which represents a $78 million increase from the original estimate that was completed in early 2003. Citing the cost increase, certain interveners asked the PSB to reopen the proceeding in which VELCO received the overall Certificate of Public Good for the NRP. The PSB declined to reopen the proceeding, and the Vermont Supreme Court subsequently denied certain interveners request for an appeal.
Although the RTO cost-sharing approach will limit our costs related to Vermont transmission upgrades, we will also be required to pay a share of projects undertaken to support region-wide reliability elsewhere in New England. The net economic effect on us is expected to be beneficial, as the sharing approach provides cost and reliability benefits in providing service to our customers, because our load share is a small fraction of New England's load, and the facilities upgrades VELCO is planning improve the reliability and efficiency of the transmission network. Certain future transmission facilities will not qualify for cost sharing, and those costs will be charged locally rather than regionally; our share of such costs will be affected by the FERC-approved cost-allocation process contained in VELCO's and our tariffs and agreements.
In addition to the NRP, VELCO is working with us on a project to solve load serving and reliability issues related to a 46-kV transmission line extending from Bennington to Brattleboro, Vermont, which we refer to as the Southern Loop. It serves about 25 percent of our load. We are evaluating alternatives to resolve the Southern Loop issues, including significant upgrades to the transmission system as well as non-transmission alternatives. Certain alternatives would provide regional reliability benefits and therefore some of the upgrades could be eligible for cost sharing on a New England-wide basis under the current regional tariff. The estimated total cost of these system upgrades ranges from $70 million to $110 million with construction likely to begin on some components of the project in 2007 or 2008. In October 2005, we initiated a public involvement process to gain input on how best to improve and ensure reliable electric service in southern Vermont. A Utility Search Conference was held in southern Vermont at the end of January 2006. The participants identified public preferences for solutions and processes to solve the Southern Loop problems. We and VELCO accepted the public recommendations and agreed to work with a smaller community working group to develop ideas and implement solutions.
NUCLEAR GENERATING COMPANIES
We are one of several sponsor companies with ownership interests in Maine Yankee, Connecticut Yankee and Yankee Atomic, and are responsible for paying our ownership percentage of decommissioning and all other costs for each plant. We also have a joint-ownership interest in Millstone Unit #3, which is described above. Our obligations related to Maine Yankee, Connecticut Yankee and Yankee Atomic are described in detail in Note 2 - Investments in Affiliates. The following is a summary of the status of activities at each of the plants, all of which have been permanently shut down and are completing various stages of decommissioning.
Department of Energy ("DOE") Litigation: Maine Yankee, Connecticut Yankee and Yankee Atomic are seeking recovery of fuel storage-related costs stemming from the default of the DOE under the 1983 fuel disposal contracts that were mandated by the United States Congress under the Nuclear Waste Policy Act of 1982. On September 9, 2005, the United States Court of Appeals for the Federal Circuit issued a decision involving another nuclear utility's spent fuel that, among other things, found plaintiffs in "partial breach" cases, such as Maine Yankee, Connecticut Yankee and Yankee Atomic, were not entitled to future damages. The date or event beyond which damages were to be considered "future damages" was not clarified by the Court. The ruling does not bar a plaintiff from seeking future damages in subsequent proceedings after the damages have been incurred. In response to the trial judge's request for supplemental briefing on the impact of the future-damages ruling, Maine Yankee, Connecticut Yankee and Yankee Atomic contended that the Court should award damages through 2002 initially and direct the parties to promptly pursue additional proceedings for recovery of post-2002 incurred damages. The DOE contended that all three companies could recover damages in the ongoing proceeding only through the date when they filed suit in June 1998. On February 28, 2006, all three companies asked the Court to allow amended damage claim filings to cover the period ending December 31, 2002. The proposed amended damage claims are about $79 million for Maine Yankee, $82.8 million for Connecticut Yankee and $101.8 million for Yankee Atomic. This compares to original claims of $160 million for Maine Yankee, $197.1 million for Connecticut Yankee and $191 million for Yankee Atomic. Due to the complexity of the issues and the possibility of appeals, the three companies cannot predict the amount of damages to be received or the timing of the final determination of such damages. None of the companies have included any allowance for potential recovery of these claims in their FERC-filed cost estimates.
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Maine Yankee: We have a 2 percent ownership interest in Maine Yankee. Beginning November 1, 2004, Maine Yankee's billings to sponsor companies have been based on its September 16, 2004 FERC-approved settlement, which provides for recovery of Maine Yankee's forecasted costs of providing service through a formula rate contained in its power contracts through October 31, 2008 and replenishment of the DOE Spent Fuel Obligation through collections from November 2008 through October 2010. On October 3, 2005, Maine Yankee completed its decommissioning efforts and the Nuclear Regulatory Commission ("NRC") amended its operating license for operation of the Independent Spent Fuel Storage Installation.
In October 2005, Maine Yankee provided an updated forecast for ongoing costs, which reflects an estimated increase of about $10.1 million. The increase is primarily related to higher-than-expected interest expense. Our share of these estimated increased costs is about $0.2 million.
Connecticut Yankee: We have a 2 percent ownership interest in Connecticut Yankee. Costs billed by Connecticut Yankee are based on FERC-filed rates effective February 1, 2005 for collection through 2010. Before February 1, 2005 costs were based on FERC-approved rates that became effective September 1, 2000 for collection through 2007. Connecticut Yankee is involved in a contract dispute and a FERC rate case filing as described below.
Bechtel Litigation: On February 27, 2006, Connecticut Yankee and Bechtel participated in a mediation process related to a contract dispute that resulted in default termination of the decommissioning services contract between Connecticut Yankee and Bechtel effective July 2003. On March 7, 2006, Connecticut Yankee and Bechtel entered a settlement, the material terms of which are: the litigation shall be terminated by dismissals with prejudice of all claims and counterclaims, with each party bearing its own costs; Bechtel shall release all liens, garnishments and attachments that it has obtained against Connecticut Yankee assets; Bechtel shall petition FERC to withdraw its intervention in the Connecticut Yankee rate case; the parties shall exchange mutual general releases including releases of Connecticut Yankee shareholders and their affiliates; Bechtel shall pay Connecticut Yankee the sum of $15.0 million; and Connecticut Yankee shall withdraw its termination of the decommissioning contract for default, and the contract shall be deemed terminated by agreement. At this time, we cannot predict the effect, if any, this settlement will have related to the FERC litigation described below. To the extent any amounts of the settlement payment are ultimately returned to us, these amounts will be credited for the future benefit of retail ratepayers.
FERC Rate Case Filing: In December 2003, Connecticut Yankee established an updated estimate of decommissioning and plant closure costs for the period 2000 through 2023 ("2003 Estimate"). The 2003 Estimate of about $831 million represents an aggregate increase of about $395 million compared to the cost estimate in Connecticut Yankee's 2000 FERC rate case settlement (stated in 2003 dollars). In the Filing, Connecticut Yankee sought to increase its annual decommissioning collections from $16.7 million to $93 million through 2010 beginning January 1, 2005. The CT DPUC and Bechtel intervened in this rate case, and both filed testimony in the FERC proceeding claiming that Connecticut Yankee was imprudent in its management of the decommissioning project.
On November 22, 2005, the ALJ issued an Initial Decision that found: there was no evidence of Connecticut Yankee imprudence. The only adjustment to Connecticut Yankee's decommissioning charges required by the Initial Decision relates to the escalation rate, which is the factor used to translate the 2003 Estimate (stated in 2003 dollars) into spending projections and decommissioning charges. The Initial Decision found that Connecticut Yankee should recalculate its decommissioning charges to reflect a lower escalation rate. The Initial Decision is subject to review by FERC.
We continue to believe that FERC will approve recovery of Connecticut Yankee's increased costs in wholesale rates based on the nature of costs and previous rulings at other nuclear companies. Once approved by FERC, we believe it is unlikely that the PSB would not allow these FERC-approved costs to be recovered in retail rates. However, there is a risk, notwithstanding the ALJ Initial Decision, that some portion of the increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings. If FERC disallows cost recovery in wholesale rates, we anticipate that the PSB would disallow these costs for recovery in retail rates as well. The timing, amount and outcome of the FERC rate case filing cannot be predicted at this time.
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Yankee Atomic: We have a 3.5 percent ownership interest in Yankee Atomic. Costs billed by Yankee Atomic are based on a November 23, 2005 FERC filing primarily to recover increased costs associated with remediation of non-hazardous and hazardous waste volumes in excess of estimates in the previously concluded rate case. Prior to this filing, costs billed by Yankee Atomic were based on its April 4, 2003 FERC-approved rate filing. The decommissioning effort is largely complete and final site-work is expected to conclude in 2006. Following the completion of decommissioning, the remaining on-site function will be to operate the Independent Spent Fuel Storage Installation.
On November 23, 2005, Yankee Atomic submitted an application to FERC for increased decommissioning charges based on its updated estimate of costs of completing the decommissioning effort. Yankee Atomic proposed to collect decommissioning charges of about $54.9 million in 2006 and $23.5 million annually for 2007 through 2010. This compares to previously-scheduled annual charges of about $12.8 million for 2006 through 2010. Hearings on the FERC rate case began in December 2005, and several parties including the DPS filed motions to intervene and protest. On January 1, 2006, FERC issued an Order: 1) accepting Yankee Atomic's rate filing; 2) permitting the proposed rates to go into effect, subject to refund, as of February 1, 2006; and 3) referring the parties to a settlement judge to facilitate a possible settlement. Our share of the rate increase amounts to about $1.5 million for 2006 and $0.4 million annually for 2007 through 2010.
DIVERSIFICATION
Eversant's wholly owned subsidiary, SmartEnergy Water Heating Services, Inc. ("SEWHS"), engages in the sale or rental of electric water heaters in Vermont and New Hampshire. SEWHS had earnings of $0.4 million in 2005, $0.4 million in 2004 and $0.5 million in 2003.
In the fourth quarter of 2005, Eversant recorded an impairment to write off its remaining $1.4 million investment in The Home Service Store, Inc. ("HSS"). Eversant initially determined that its investment, comprised of shares of HSS junior convertible preferred stock and common stock, was impaired as of December 31, 2005 based on HSS's current financial information and slower-than-expected growth experience. However, based on further review and analysis it was determined that the impairment occurred in 2002, since Eversant's shares of HSS junior convertible preferred stock became subordinate to HSS senior series preferred stock in December 2002. The impairment analysis as of December 31, 2002 did not take this fact into account. Consequently, Eversant should have recorded the impairment, $0.8 million after-tax, in December 2002. See Note 16 - Restatement.
RECENT ENERGY POLICY INITIATIVES
Energy initiatives in Vermont The State of Vermont continues to examine changes to the provision of electric service absent introduction of retail choice. The Vermont Legislature passed, in the concluded 2005 session, Act 61, "Renewable Energy, Efficiency, Transmission, and Vermont's Energy Future" ("Act 61"), a new law that includes two major provisions of interest to us:
Power Supply Requirements The new law establishes a Sustainably Priced Energy Enterprise Development ("SPEED") Program with a collective requirement of all Vermont retail electricity providers to, in aggregate, supply all of their incremental load growth between January 1, 2005 and January 1, 2012 from new renewable supplies, new Renewable Energy Certificates, or a combination of the two, capped at a total of 10 percent of the statewide kWh sales during calendar year 2005. Under SPEED the PSB may: 1) offer the contracts secured by a PSB-named statewide entity or entities to utilities on a pro rata basis; 2) establish a process by which utilities may demonstrate that their power supply portfolio is sufficiently renewable so as to relieve them of having to accept a pro-rata share of additional SPEED renewable power; 3) encourage utilities to secure long-term contracts for renewable energy; and 4) encourage utility sponsorship and partnerships in the development of renewable energy projects. The SPEED program begins on January 1, 2007.
By July 1, 2013, the PSB must determine whether Vermont's retail electricity providers have met the SPEED program's requirements. If the requirements have been met, no other PSB action is required. If not met, the law states that the SPEED program's collective requirement reverts to a utility-specific renewable portfolio standard ("RPS"). Under the RPS, each retail electricity provider would have to supply an amount of energy equal to its total incremental energy growth between January 1, 2005 and January 1, 2012 through the use of electricity generated by new renewable resources, capped at a total of 10 percent of its sales during calendar year 2005. As with the SPEED program, this requirement can be met from new renewable supplies, new Renewable Energy Certificates, or a combination of the two.
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Under either program, we could be required to purchase certain amounts of our energy supply requirement from new renewable sources while maintaining existing renewable power resources. Alternatively, if the utility-specific RPS takes effect, we may choose to pay an as-yet-undetermined charge per kWh, set by the PSB. The PSB is currently developing a rule to implement the SPEED program. The rule is expected to be finalized and adopted in September 2006.
In the first quarter of 2006, we agreed in principle to purchase all of the output (about 47.5 MW of power) from a proposed wind project on Glebe Mountain in Londonderry, Vermont. The project has not been approved for development, and if construction is ultimately completed, the terms of the agreement provide that the price we will pay for the power will be 95 percent of the New England market price for power. The wind project developer Glebe Mountain Wind Energy LLC, is 50 percent owned by Catamount. This agreement was negotiated independent of the Catamount sale and is subject to PSB approval.
Alternative Forms of Regulation Act 61 also allows the DPS and PSB to initiate proceedings to adopt alternative forms of regulation for electric utilities that, besides other criteria, establish a reasonably balanced system of risks and rewards to encourage utilities to operate as efficiently as possible. Prior to the law's passage, only an electric utility could initiate an alternative regulation plan proposal. The PSB may only approve an alternative regulation plan if it finds that the plan will not adversely affect our eligibility for rate-regulated accounting in accordance with GAAP and reasonably preserves the availability of equity and debt capital resources to us on favorable terms and conditions. To date, neither we nor the regulators have sought to implement an alternate form of regulation for our operations.
Future issues and other matters In August 2005, the Federal Energy Policy Act of 2005 ("the Act") was enacted. The Act includes numerous provisions meant to increase domestic gas and oil supplies, improve energy system reliability, build new nuclear power plants, and expand renewable energy sources. The Act also repeals the Public Utility Holding Company Act of 1935, effective February 2006. We are monitoring proposed changes resulting from the Act and are unable to predict at this time whether such changes will impact us.
RECENT ACCOUNTING PRONOUNCEMENTS
See Note 1 - Summary of Significant Accounting Policies to the accompanying Consolidated Financial Statements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We consider our most significant market-related risks to be associated with wholesale power markets, equity markets and interest rates. Fair and adequate rate relief through cost-based-rate regulation can limit our exposure to market volatility. Below is a discussion of the primary market-related risks associated with our business.
Wholesale Power Market Price Risk: Our most significant power supply contracts are with Hydro-Quebec and Vermont Yankee Nuclear Power Corporation ("VYNPC"). Combined, these contracts amounted to about 84 percent of our total energy (mWh) purchases in 2005 and 2004, and 90 percent in 2003. The contracts are described in more detail in Item 7, Power Supply Matters. Summarized information regarding these contracts follows.
|
2005 |
2004 |
2003 |
|||||
|
Expires |
mWh |
$/mWh |
mWh |
$/mWh |
mWh |
$/mWh |
|
|
Hydro-Quebec (a) |
2016 |
832,357 |
$70.16 |
790,017 |
$72.08 |
826,104 |
$69.63 |
|
VYNPC (b) |
2012 |
1,430,155 |
$40.05 |
1,343,629 |
$43.69 |
1,547,771 |
$42.37 |
We sometimes experience energy delivery deficiencies under the power contract with Hydro-Quebec as a result of outages or other problems with the transmission interconnection facilities over which we schedule deliveries. We are also responsible for procuring replacement energy during periods of scheduled or unscheduled outages at the Vermont Yankee plant. In both cases, we purchase replacement energy, if needed, from third parties in New England or through ISO-New England. Although our retail rates include a provision for estimated replacement
Page 61 of 153
power costs, average market prices at the times when we purchase replacement energy might be significantly higher than amounts included for recovery in our retail rates. Summarized information regarding short-term purchases and average unit prices, including those to balance our resource output and load requirements in ISO-New England, follows:
|
2005 |
2004 |
2003 |
||||
|
mWh |
$/mWh |
mWh |
$/mWh |
mWh |
$/mWh |
|
|
Short-term purchases |
261,180 |
$119.65 |
226,782 |
$68.70 |
108,228 |
$68.89 |
Our long-term power forecast shows energy purchase and production amounts in excess of our load requirements in most periods through 2011. Because of our general surplus, we enter into forward sale transactions from time to time to reduce price volatility of our forecasted net power costs. Summarized information regarding resale sales and average unit prices, including those to balance our resource output and load requirements in ISO-New England, follows:
|
2005 |
2004 |
2003 |
||||
|
mWh |
$/mWh |
mWh |
$/mWh |
mWh |
$/mWh |
|
|
Resale sales |
658,122 |
$62.61 |
548,325 |
$48.37 |
567,921 |
$43.29 |
The effect of increases or decreases in average wholesale power market prices is highly dependent on whether our net power resources at the time are sufficient to meet load requirements or not. If they are not sufficient to meet load requirements, such as the case when power from Hydro-Quebec and Vermont Yankee is not available as expected, we are typically in a purchase position. In that case, increased wholesale power market prices would increase our net power costs. If our net power resources are sufficient to meet load requirements, we are typically in a sale position. In that case, increased wholesale power market prices should decrease our net power costs.
We account for some of our power contracts as derivatives under the guidance of SFAS No. 133. These derivatives are described in more detail in Item 7, Critical Accounting Policies and Estimates. Summarized information related to the fair value of energy-related derivatives is shown in the table below (in thousands):
|
Forward Sale Contract |
Hydro-Quebec Sellback #3 |
|
|
Fair value at January 1, 2005 - unrealized gain (loss) |
$385 |
$(5,735) |
|
Source |
Over-the-counter-quotations |
Quoted market data & valuation |
|
Estimated fair value for changes in projected market price: |
|
|
The fair value of these derivatives at December 31, 2005 reflects the combination of rising spot market and futures prices for natural gas and oil due to increased global demand and production and refining cutbacks resulting from the 2005 hurricane season, which are now reflected in the current and projected price of electric energy, especially in New England.
Per a PSB-approved Accounting Order, changes in fair value of these derivatives are recorded as deferred charges or deferred credits on the Consolidated Balance Sheets depending on whether the fair value is an unrealized loss or unrealized gain, with an offsetting amount recorded as a decrease or increase in the related derivative asset or liability.
Investment Price Risk: We are subject to investment price risk due to marketable securities held as available-for-sale investments in decommissioning trust funds. These marketable securities are reported on our Consolidated Balance Sheets at fair value.
Page 62 of 153
Pension: Interest rate changes could also impact calculations related to estimated pension and other benefit liabilities, affecting pension and other benefit expenses and potentially affecting contributions to the trusts. See Item 7, Critical Accounting Policies and estimates, and Note 10 to the Consolidated Financial Statements for additional information related to Pension and Postretirement Benefits.
Equity Market Risk: As of December 31, 2005, our pension trust held marketable equity securities in the amount of $45.7 million and our Millstone Unit #3 decommissioning trust held marketable equity securities of $3.6 million. We also maintain a variety of insurance policies in a Rabbi Trust with a current value of $6.3 million to support various supplemental retirement and deferred compensation plans. The current values of certain policies are affected by changes in the equity market.
Credit Risk: Our non-investment grade credit rating could hamper our operational flexibility by restricting or increasing the cost of future access to capital and imposing additional requirements to provide performance assurance associated with certain existing or new power purchase and sale transactions.
We have $16.9 million of letters of credit expiring on November 30, 2006 that we will need to renew. These letters of credit support three series of Industrial Development Revenue Bonds, totaling $16.3 million, of which $10.8 million is included in Notes Payable on the Consolidated Balance Sheets and $5.5 million is included in Long-term debt.
Our $25.0 million unsecured revolving credit facility contains a Material Adverse Effect ("MAE") clause that is a higher standard than a material adverse change clause; however, this clause is in effect only when our credit rating is below investment grade. The MAE clause could allow the credit facility bank to deny a borrowing or issuance of a letter of credit under the credit facility upon request.
Interest Rate Risk: As of December 31, 2005, we had $16.3 million of Industrial Development Revenue bonds outstanding, of which $10.8 million have an interest rate that floats monthly with the short-term credit markets and $5.5 million that floats every five years with comparable credit markets. All other utility debt has a fixed rate. There are no interest lock or swap agreements in place.
The table below provides information about interest rates on our long-term debt and Industrial Development Revenue bonds (in millions).
|
Expected Maturity Date |
|||||||
|
2006 |
2007 |
2008 |
2009 |
2010 |
Thereafter |
Total |
|
|
Fixed Rate ($) |
$6.9 |
$6.9 |
$6.9 |
$6.7 |
$6.7 |
$70.6 |
$104.7 |
|
Average Fixed Interest Rate (%) |
6.22% |
6.22% |
6.22% |
6.22% |
6.22% |
6.96% |
|
|
Variable Rate ($) |
$0.5 |
$0.5 |
$0.5 |
$0.5 |
$0.3 |
$1.5 |
$3.8 |
|
Average Variable Rate (%) |
3.34% |
3.34% |
3.34% |
3.33% |
3.13% |
3.12% |
|
We also have temporary cash investments, available-for-sale securities and marketable securities held as available-for-sale investments in a decommissioning trust fund that are subject to interest rate volatility. These are described in more detail in Note 5 - Financial Instruments and Investment Securities.
Page 63 of 153
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements and Supplementary Data
|
Page |
||
|
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . |
65 |
|
|
Financial Statements: |
|
|
Page 64 of 153
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Central Vermont Public Service Corporation:
We have audited the accompanying consolidated balance sheets of Central Vermont Public Service Corporation and subsidiaries (the "Company") as of December 31, 2005 and 2004, and the related consolidated statements of income, comprehensive income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Central Vermont Public Service Corporation and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3, the Company sold its interest in Catamount Energy Corporation. The gain on sale and results of Catamount Energy Corporation's operations prior to the sale are included in income from discontinued operations in the accompanying consolidated financial statements.
As discussed in Note 16, the accompanying 2004 and 2003 consolidated financial statements have been restated.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 30, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an adverse opinion on the effectiveness of the Company's internal control over financial reporting because of a material weakness.
/s/ Deloitte & Touche LLP
Boston, Massachusetts
March 30, 2006
Page 65 of 153
|
CONSOLIDATED STATEMENTS OF INCOME |
|||
|
2005 |
2004 |
2003 |
|
|
Operating Revenues |
$311,359 |
$302,286 |
$306,098 |
|
Operating Expenses Operation Purchased Power - affiliates Purchased Power - other sources Production Transmission - affiliates Transmission - other Other Operation Maintenance Depreciation Other taxes, principally property Income tax (benefit) expense Total Operating Expenses |
|
|
|
|
Operating Income |
8,568 |
12,649 |
23,631 |
|
Other Income and (Deductions) Allowance for equity funds during construction Other income Other deductions Provision for income taxes Total Other Income and (Deductions) |
|
|
|
|
Total Operating and Other Income |
10,903 |
17,175 |
28,231 |
|
Interest Expense Other interest Allowance for borrowed funds during construction Total Interest Expense |
|
|
|
|
Income from continuing operations |
1,410 |
7,493 |
17,148 |
|
Earnings available for common stock |
$5,978 |
$23,387 |
$18,603 |
|
Per Common Share Data: Basic: Earnings from continuing operations Earnings from discontinued operations Earnings per share Diluted: Earnings from continuing operations Earnings from discontinued operations Earnings per share |
|
|
|
|
Average shares of common stock outstanding - basic |
12,258,508 |
12,118,048 |
11,878,255 |
The accompanying notes are an integral part of these consolidated financial statements.
Page 66 of 153
|
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
|||
|
2005 |
2004 |
2003 |
|
|
Net Income |
$6,346 |
$23,755 |
$19,801 |
|
Other comprehensive income, net of tax: Unrealized holding loss net of income taxes of $(43) in 2005, $(155) in 2004 and $(30) in 2003 Realized loss net of income taxes of $215 in 2005, $0 in 2004 and $0 in 2003 Non-qualified benefit obligations net of income taxes of $(50) in 2005, $40 in 2004 and $(54) in 2003 Foreign currency Other comprehensive (loss) income from discontinued operations net of income taxes of $(178) in 2005, $(178) in 2004 and $96 in 2003 |
|
|
|
|
Comprehensive Income |
$6,062 |
$23,140 |
$20,136 |
The accompanying notes are an integral part of these consolidated financial statements.
Page 67 of 153
|
CONSOLIDATED STATEMENTS OF CASH FLOWS |
|||
|
(in thousands) |
2005 |
2004 |
2003 |
|
(As Restated - |
(As Restated - |
||
|
Cash flows provided (used) by: Net income Deduct: Income from discontinued operations, net of income taxes Income from continuing operations Adjustments to reconcile net income to net cash provided by operating activities: Equity in earnings of affiliates Dividends received from affiliates Depreciation Amortization of capital leases Deferred income taxes and investment tax credits Net amortization of purchased power and related costs Regulatory amortizations Charge related to Rate Order (net of $6.5 million customer refund) Reserve for loss on power contract (SFAS No. 5 loss accrual) Vermont Utility 11% allowed rate of return adjustment Losses and amortization of premiums on available-for-sale securities Miscellaneous amortizations, non-utility depreciation and other Changes in assets and liabilities: Decrease (increase) in accounts receivable and unbilled revenues Decrease (increase) in accounts receivable - affiliates Decrease in accounts payable Increase in accounts payable - affiliates Decrease in accrued income taxes Decrease (increase) in other current assets Increase in special deposits Increase in other current liabilities (Increase) decrease in other long-term assets Increase in other long-term liabilities and other Net cash provided by operating activities of continuing operations |
|
|
|
|
INVESTING ACTIVITIES Construction and plant expenditures Investments in available-for-sale securities Proceeds from sale of available-for-sale securities Investment in affiliates Investment in discontinued operations Note receivable repayment from (advanced to) discontinued operations Proceeds from sales of discontinued operations, net of transaction costs Increase in restricted cash Proceeds from sale of utility assets Return of capital from investments in affiliates Other investments Net cash provided by investing activities of continuing operations |
|
|
|
|
FINANCING ACTIVITIES Proceeds from dividend reinvestment program Proceeds from issuance of long-term debt Retirement of long-term debt Debt issuance costs Retirement of preferred stock Common and preferred dividends paid Proceeds from borrowings under revolving credit facility Repayments under revolving credit facility Reduction in capital lease obligations Other Net cash used for financing activities of continuing operations |
|
|
|
|
DISCONTINUED OPERATIONS Net cash provided by (used for) operating activities Net cash used for investing activities Net cash provided by (used for) financing activities Effect of exchange rate changes on cash Net cash provided by (used for) discontinued operations |
|
|
|
|
Net (decrease) increase in cash and cash equivalents |
(5,146) |
675 |
(15,557) |
*At the end of the periods, Assets of discontinued operations included cash of $2.5 million in 2004, $3.3 million in 2003 and $12.6 million in 2002.
Page 68 of 153
|
CONSOLIDATED BALANCE SHEETS |
|||
|
December 31 December 312005 2004 |
|||
|
(As Restated - |
|||
|
ASSETS Less accumulated depreciation Net utility plant Construction work-in-progress Nuclear fuel, net Total utility plant |
|
|
|
|
Investments and other assets Investment in affiliates Non-utility property, less accumulated depreciation ($4,063 in 2005 and $4,367 in 2004) Millstone decommissioning trust fund Available-for-sale securities Other Total investments and other assets |
|
|
|
|
Current assets Cash and cash equivalents Available-for-sale securities Restricted cash Special deposits Notes receivable Accounts receivable, less allowance for uncollectible accounts ($2,614 in 2005 and $1,949 in 2004) Accounts receivable - affiliates, less allowance for uncollectible accounts ($48 in 2005 and $0 in 2004) Unbilled revenues Materials and supplies, at average cost Prepayments Deferred income taxes Other current assets Assets of discontinued operations Total current assets |
|
|
|
|
Deferred charges and other assets Regulatory assets Other deferred charges - regulatory Other Total deferred charges and other assets TOTAL ASSETS |
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Page 69 of 153 |
|||
|
CONSOLIDATED BALANCE SHEETS |
|||
|
December 31 December 312005 2004 |
|||
|
(As Restated - |
|||
|
CAPITALIZATION AND LIABILITIES Common stock, $6 par value, authorized 19,000,000 shares (issued and outstanding 12,283,405 and 12,193,093 shares at December 31, 2005 and 2004, respectively) Other paid-in capital Accumulated other comprehensive loss Deferred compensation - employee stock ownership plans Retained earnings Total common stock equity Preferred and preference stock Preferred stock with sinking fund requirements Long-term debt Capital lease obligations Total capitalization |
|
|
|
|
Current liabilities Accounts payable Accounts payable - affiliates Notes payable Accrued income taxes Accrued interest Dividends declared Nuclear decommissioning costs Power contract derivatives Other current liabilities Liabilities of discontinued operations Total current liabilities |
|
|
|
|
Deferred credits and other liabilities Deferred income taxes Deferred investment tax credits Nuclear decommissioning costs Asset retirement obligations Accrued pension and benefit obligations Power contract derivatives Other deferred credits - regulatory Other Total deferred credits and other liabilities Commitments and contingencies TOTAL CAPITALIZATION AND LIABILITIES |
134,277 $551,433 |
|
|
|
.
The accompanying notes are an integral part of these consolidated financial statements
Page 70 of 153 |
|||
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
|
|
|
Deferred |
Accumulated |
|
|
|
||
|
Balance, December 31, 2002 (As Originally Reported) |
|
|
|
|
|
|
|
|
|
Common stock issuance: |
|
|
|
|
|
|
|
|
|
|
12,283,405 |
$73,695 |
|
$(5) |
$(414) |
$- |
$91,581 |
|
The accompanying notes are an integral part of these consolidated financial statements.
Page 71 of 153
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
About Central Vermont Public Service Corporation Central Vermont Public Service Corporation (the "Company") is a Vermont-based electric utility that transmits, distributes and sells electricity. The Company's non-regulated wholly owned subsidiary Catamount Resources Corporation ("CRC") owns Eversant Corporation ("Eversant"), which operates a rental water heater business through its wholly owned subsidiary, SmartEnergy Water Heating Services, Inc. Other wholly owned subsidiaries include Custom Investment Corporation ("Custom") a passive investment subsidiary that holds the Company's investment in Vermont Yankee Nuclear Power Corporation ("VYNPC"), and Connecticut Valley Electric Company ("Connecticut Valley"), which completed the sale of substantially all of its plant assets and franchise on January 1, 2004.
On October 31, 2005, CRC's wholly owned subsidiary, Catamount Energy Corporation ("Catamount"), which invested primarily in wind energy projects in the United States and the United Kingdom, issued shares of its common stock to CEC Wind Acquisition, LLC, a Delaware limited liability company established by Diamond Castle Holdings, a New York-based private equity investment firm ("Diamond Castle"). The stock issuance was based on Diamond Castle's firm commitment to invest $62.5 million in Catamount over a three-year period, including its initial investment of $16.0 million made on October 31, 2005. The transaction diluted CRC's ownership interest in Catamount to 79 percent and its voting rights to 49 percent. On December 20, 2005, CRC sold all of its interest in Catamount to Diamond Castle.
The consolidated financial statements present Catamount and Connecticut Valley as discontinued operations, in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"). See Note 3 - Discontinued Operations.
As discussed in Note 16 - Restatement the 2004 and 2003 Consolidated Financial Statements presented herein have been restated.
Consolidation Policy and Use of Estimates The consolidated financial statements include the accounts of the Company and its subsidiaries in which it has a controlling interest. Inter-company transactions have been eliminated in consolidation.
Investments in entities over which the Company does not maintain a controlling financial interest are accounted for using the equity method when the Company has the ability to exercise significant influence over their operations. Under this method, the Company records its ownership share of the net income or loss of each investment in the accompanying consolidated financial statements. The Company has concluded that consolidation of these investments is not required under the provisions of Financial Accounting Standards Board ("FASB") Interpretation No. 46, Consolidation of Variable Interest Entities, as revised ("FIN 46R"). See Note 2 - Investments in Affiliates.
The Company's interests in joint owned generating and transmission facilities are accounted for on a proportionate consolidated basis using the Company's ownership percentages and are recorded in the Company's Consolidated Balance Sheets. The Company's share of operating expenses for these facilities is included in the corresponding operating accounts on the Consolidated Statements of Income.
Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP") requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities, and revenues and expenses. Actual results could differ from those estimates. In Management's opinion, the areas of the Company where significant judgment is exercised is in the valuation of unbilled revenue, pension plan assumptions, nuclear plant decommissioning liabilities, regulatory assets and liabilities, and derivative valuations.
Regulatory Accounting The Company is regulated by the Vermont Public Service Board ("PSB"), the Connecticut Department of Public Utility and Control and the Federal Energy Regulatory Commission ("FERC"), with respect to rates charged for service, accounting, financing and other matters pertaining to regulated operations. The Company prepares its financial statements in accordance with Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS No. 71"), for its regulated Vermont service territory and FERC-regulated wholesale business. In order for a company to report under SFAS No. 71, the
Page 72 of 153
company's rates must be designed to recover its costs of providing service, and the company must be able to collect those rates from customers. If rate recovery of these costs becomes unlikely or uncertain, whether due to competition or regulatory action, this accounting standard would no longer apply to the Company's regulated operations. In the event the Company determines that it no longer meets the criteria for applying SFAS No. 71, the accounting impact would be an extraordinary non-cash charge to operations of an amount that would be material unless stranded cost recovery is allowed through a rate mechanism. Criteria that could give rise to the discontinuance of SFAS No. 71 include: 1) increasing competition that restricts a 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.
Based on a current evaluation of the factors and conditions expected to impact future cost recovery, Management believes future recovery of its regulatory assets in the State of Vermont for its retail and wholesale businesses is probable. In the event that the Company no longer meets the criteria under SFAS No. 71 and there is not a rate mechanism to recover these costs, the accounting impact would be an extraordinary charge to operations of about $36.1 million pre-tax as of December 31, 2005. The Company would also be required to determine any impairment to the carrying costs of deregulated plant. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits.
Discontinued Operations Catamount's results of operations are reported as discontinued operations for all periods presented, in accordance with SFAS No. 144. Certain corporate costs previously allocated to Catamount that were not eliminated by the sale have been reallocated back to continuing operations. These pre-tax costs amounted to about $0.5 million in 2005, $0.5 million in 2004 and $0.8 million in 2003. The assets and liabilities of Catamount are classified as assets and liabilities of discontinued operations in the 2004 Consolidated Balance Sheet. The Company began to present Catamount as discontinued operations in the fourth quarter of 2005 based on its November 2005 decision to sell all of its interest in Catamount to Diamond Castle, and consummation of the sale on December 20, 2005.
The results of operations of Connecticut Valley are reported as discontinued operations for 2004 and 2003, and common corporate costs of about $1.3 million, pre-tax, in 2003 were reallocated back to continuing operations because they were not eliminated by the sale. The Company began to present Connecticut Valley as discontinued operations in the second quarter of 2003 based on the New Hampshire Public Utility Commission's ("NHPUC") approval of the sale of Connecticut Valley's plant assets and franchise to Public Service Company of New Hampshire ("PSNH"). The sale to PSNH was completed on January 1, 2004. See Note 3 - Discontinued Operations for additional information.
Subsidiary Stock Transactions In accordance with the SEC's Staff Accounting Bulletin ("SAB") 51, Accounting for Sales of Stock by a Subsidiary, the Company has elected to record gains on the sale of stock by a subsidiary to the consolidated statement of income. SAB 51 requires that the difference between the carrying amount of the parent's investment in a subsidiary and the underlying net book value of the subsidiary after the issuance of stock by the subsidiary be reflected as a gain in the statement of income or as an equity transaction. The application of this policy to Catamount's issuance of common stock to Diamond Castle on October 31, 2005, represents the Company's initial adoption of this accounting policy. The resulting $1.0 million pre-tax gain is included in Income from discontinued operations as a component of gain on disposal on the Consolidated Statement of Income. The October 31, 2005 transaction is described in more detail in Note 3 - Discontinued Operations.
Unregulated Business Eversant's primary business activity is the rental of water heaters in portions of Vermont and New Hampshire. Results of operations of Eversant are included in Other Income and Deductions on the Consolidated Statements of Income.
Revenues Revenues that are related to the sale of electricity are generally recorded when service is rendered or electricity is distributed to customers. Electricity sales to customers are based on monthly meter readings. Estimated unbilled revenues are recorded at the end of each monthly accounting period. In order to determine unbilled revenues, the Company makes various estimates including: 1) energy generated, purchased and resold; 2) losses of energy over transmission and distribution lines; 3) kilowatt-hour usage by retail customer mix - residential, commercial and industrial; and 4) average retail customer pricing rates. Accrued unbilled revenues at year end were $16.9 million in 2005 and $17.7 million in 2004.
Page 73 of 153
The Company records contractual or firm wholesale sales in the month that power is delivered; these resale sales are based on long-term and short-term contracts with parties in New England. The Company also engages in short-term hourly sales in the wholesale markets administered by the New England Independent System Operator ("ISO-New England"). Such sales are transacted with ISO-New England through the normal settlement process. On a monthly basis, the Company aggregates the hourly sales and purchases and records net sales as Operating Revenue.
Purchased Power The Company records the annual cost of power obtained under long-term contracts as operating expenses. These contracts are considered executory in nature, since they do not convey to the Company the right to use the related property, plant or equipment. The Company engages in short-term purchases with other third parties, primarily in New England, and records those purchases as operating expenses in the month the power is delivered. The Company also engages in short-term hourly purchases in the wholesale markets administered by ISO-New England. Such purchases are transacted with ISO-New England through the normal settlement process. On a monthly basis, the Company aggregates the hourly purchases and sales and records net purchases as Purchased Power.
Capital Lease The Company records its commitments with respect to the Hydro-Quebec Phase I and II transmission facilities as capital leases. See Note 13 - Commitments and Contingencies.
Income Taxes In accordance with SFAS No. 109, Accounting for Income Taxes ("SFAS No. 109"), the Company recognizes deferred tax assets and liabilities for the cumulative effect of all temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the tax rate expected to be in effect when the differences are expected to reverse. Investment tax credits associated with utility plant are deferred and amortized ratably to income over the lives of the related properties. The Company records a valuation allowance for deferred tax assets if management determines that it is more likely than not such tax assets will not be realized. See Note 11 - Income Taxes.
Net Utility Plant Utility plant is recorded at original cost. Replacements of retirement units of property are charged to utility plant. Maintenance and repairs, including replacements not qualifying as retirement units of property, are charged to maintenance expense. The costs of renewals and improvements of property units are capitalized. The original cost of units retired, net of salvage value, are charged to accumulated provision for depreciation. The primary components of utility plant include (in thousands):
|
December 31 |
||
|
Electric - transmission and distribution |
$393,528 |
$381,825 |
Depreciation
The Company uses the straight-line remaining life method of depreciation. The total composite depreciation rate was 3.18 percent of the cost of depreciable utility plant in 2005, 3.23 percent in 2004 and 3.28 percent in 2003.
Page 74 of 153
Other Current Liabilities The components of other current liabilities are as follows (in thousands):
|
December 31, |
||
|
Deferred compensation plans |
$2,569 |
$2,689 |
Other Deferred Credits and Other Liabilities The components of other deferred credits and other liabilities are as follows (in thousands):
|
December 31, |
||
|
Environmental Reserve |
$5,016 |
$5,045 |
Other Income The components of other income are as follows (in thousands):
|
For the years ended December 31, |
|||
|
Interest on temporary investments |
$1,311 |
$1,436 |
$457 |
|
* First quarter 2005 Rate Order adjustments primarily related to amortization of Vermont Yankee sale costs |
|||
Other Deductions The components of other deductions are as follows (in thousands):
|
For the years ended December 31, |
|||
|
Supplemental retirement benefits and insurance |
$709 |
$247 |
$274 |
|
* First quarter 2005 Rate Order disallowance of a portion of deferred costs related to a Vermont |
|||
Page 75 of 153
Valuation of Long-Lived Assets The Company periodically evaluates the carrying value of long-lived assets and long-lived assets to be disposed of, including its investments in nuclear generating companies, its unregulated investments, and its interests in jointly owned generating facilities, when events and circumstances warrant such a review. The carrying value of such assets is considered impaired when the anticipated undiscounted cash flow from such an asset is separately identifiable and is less than its carrying value. In that event, a loss is recognized based on the amount by which the carrying value exceeds the fair value of the long-lived asset.
Asset Retirement Obligations SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143") provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of long-lived assets. It also requires entities to record the fair value of a liability for an asset retirement obligation ("ARO") in the period in which it is incurred.
Legal Asset Retirement Obligations The Company has legal retirement obligations associated with decommissioning related to its joint-owned nuclear plant, Millstone Unit #3, and conditional asset retirement obligations described below. The revisions in estimated cash flows in the table below are related to changes in Millstone Unit #3 license renewal probability from 85 percent to 100 percent. Changes to Asset retirement obligations, included on the Consolidated Balance Sheets are as follows (in millions):
|
2005 2004(actual) (pro forma) |
||
|
Asset retirement obligations at January 1 |
$3.6 |
$3.8 |
The Company has an external trust fund dedicated to funding its share of future decommissioning for Millstone Unit #3. The year-end aggregate fair value of the trust fund, consisting primarily of debt and equity securities, totaled $4.9 million in 2005 and $4.7 million in 2004, and is included in Investments and Other Assets on the Consolidated Balance Sheets. The year-end difference between the balance in the external trust fund and the asset retirement obligation that is recorded in Other deferred credits - regulatory on the Consolidated Balance Sheets amounted to about $1.3 million for 2005 and $1.1 million for 2004.
FASB Interpretation No. 47 ("FIN 47"): FIN 47, Accounting for Conditional Asset Retirement Obligations, clarifies the scope and timing of liability recognition for conditional asset retirement obligations. The interpretation requires that a liability be recorded for the fair value of an ARO, if the fair value is estimable, even when the obligation is dependent on a future event. FIN 47 further clarified that uncertainty surrounding the timing and method of settlement of the obligation should be factored into the measurement of a conditional ARO rather than affect whether a liability should be recognized. Under FIN 47, AROs are recorded at fair value in the period in which they are incurred by increasing the carrying amount of the related long-lived asset. The liability is accreted to its fair value and the capitalized costs are depreciated over the useful life of the related asset.
The Company adopted FIN 47 at December 31, 2005, as required. As a result, the Company recorded an asset retirement obligation of $0.5 million, recognized asset retirement costs of $0.1 million as an increase in net utility plant and a regulatory asset of $0.4 million. The recognition of an ARO related to the Company's regulated utility business had no impact on the Company's earnings. In accordance with SFAS No. 71, the Company established a regulatory asset to recognize future recoveries through depreciation rates for the recorded ARO.
The Company considered its past practices, industry practices, management's intent and the estimated economic lives of the assets in determining whether conditional AROs could be reasonably estimated. AROs were recognized for items that could be reasonably estimated such as asbestos removal, disposal of polychlorinated biphenyls in certain transformers and breakers, and mercury in batteries and certain meters. In accordance with FIN 47, the Company has not recorded an ARO associated with asbestos abatement at certain of its sites because the range of time over which the Company may settle these obligations is unknown and cannot be reasonably estimated.
For comparative purposes, the pro forma ARO that would have been recognized in accordance with FIN 47 as of December 31, 2004 and January 1, 2004 would have amounted to $0.5 million and $0.4 million, respectively.
Page 76 of 153
Non-legal Removal Costs: The Company's regulated operations collect removal costs in rates for certain utility plant assets that do not have associated legal asset retirement obligations. Non-legal removal costs of about $7.6 million in 2005 and $6.7 million in 2004 are included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.
Reserve for Loss on Power Contract In accordance with the requirements of SFAS No. 5, Accounting for Contingencies ("SFAS No. 5"), the Company recorded a $14.4 million pre-tax loss accrual in the first quarter of 2004 related to termination of its long-term power contract with Connecticut Valley. The contract was terminated as a condition of the Connecticut Valley sale. The loss accrual represented management's best estimate of the difference between expected future sales revenue, in the wholesale market, for the purchased power that was formerly sold to Connecticut Valley and the net cost of purchased power obligations. The estimated life of the Company's power contracts that were in place to supply power to Connecticut Valley extends through 2015. The $14.4 million loss accrual is included in Purchased Power on the 2004 Consolidated Statement of Income.
The loss accrual was estimated based on assumptions about future power prices, the reallocation of power from the state-appointed purchasing agent ("VEPPI") and future load growth. Management reviews this estimate at the end of each reporting period and will increase the reserve if the revised estimate exceeds the recorded loss accrual. Additionally, the loss accrual is being amortized on a straight-line basis, as required by GAAP, through 2015. The Company recorded $1.2 million of amortization in 2005 and in 2004. These amounts are included in Purchased Power on the Consolidated Statements of Income. The loss accrual amounted to $12.0 million at December 31, 2005 and $13.2 million at December 31, 2004 and is reflected as a liability (current and non-current) on the Consolidated Balance Sheets.
Environmental Liabilities The Company is engaged in various operations and activities that subject it to inspection and supervision by both federal and state regulatory authorities including the United States Environmental Protection Agency. 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. See Note 13 - Commitments and Contingencies.
Accumulated Other Comprehensive Income (Loss) Changes in components of accumulated other comprehensive income (loss), net of income taxes, as of December 31 are as follows (in thousands):
|
2003 |
|
2004 |
|
2005 |
|
|
(Loss) gain on investments |
$(44) |
$(228) |
$(272) |
$252 |
$(20) |
Page 77 of 153
Stock-Based Compensation The Company applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25"), and related Interpretations in accounting for its stock-based compensation plans and follows the disclosure requirements of SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No. 123. Also see Recent Accounting Pronouncements below for changes in accounting for Share-Based Payments effective January 1, 2006. The table below illustrates the effect on net income and earnings per share as if the fair value method had been applied to all stock-based compensation in each period. The fair value of options at date of grant was estimated using the Black Scholes option-pricing model.
|
(in thousands, except per share amounts) |
|||
|
For the years ended December 31, |
|||
|
Earnings available for common stock, as reported |
$5,978 |
$23,387 |
$18,603 |
|
* Fair value based methods for all awards, net of related tax effects. |
|||
Earnings Per Share ("EPS") The Consolidated Statements of Income includes basic and diluted per share information. Basic EPS is calculated by dividing net income, after preferred dividends, by the weighted-average common shares outstanding for the period. Diluted EPS follows a similar calculation except that the weighted-average common shares are increased by the number of potentially dilutive common shares. See Note 17 - Subsequent Events for discussion of the Company's tender offer to purchase up to 2,250,000 shares of outstanding common stock in 2006. The table below provides a reconciliation of earnings available for common stock and average basic and diluted common shares (in thousands, except share information):
|
For the years ended December 31 |
|||
|
Earnings from continuing operations |
$1,410 |
$7,493 |
$17,148 |
Antidilutive Shares:
Page 78 of 153
Dividends Declared Per Share of Common Stock In 2005, the Company paid cash dividends of 92 cents per share of common stock. In December 2005, the Company declared a cash dividend of 23 cents per share for payment to common shareholders in February 2006. The December 2005 dividend declared amounted to $2.8 million and is included as a current liability on the Consolidated Balance Sheets. There was no common dividend payable at December 31, 2004.
Derivative Financial Instruments The Company accounts for various power contracts as derivatives under the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted and SFAS No. 149, Amendment of Statement 133 Derivative Instruments and Hedging Activities, (collectively "SFAS No. 133"). These statements require that derivatives be recorded on the balance sheets at fair value.
The Company's long-term contracts for the purchase of power from VYNPC and Independent Power Producers do not meet the definition of a derivative under the requirements of SFAS No. 133 because delivery of power under these contracts is contingent on plant output. Additionally, the Company's long-term power contract with Hydro-Quebec does not meet the definition of a derivative because there is no defined notional amount.
The Company has a long-term purchased power contract that allows the seller to repurchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative under SFAS No. 133. The derivative's estimated fair value was an unrealized loss of $5.0 million at December 31, 2005 and $5.7 million at December 31, 2004. The estimated fair value of this derivative is valued using a binomial tree model, and quoted market data when available along with appropriate valuation methodologies.
The Company has a long-term forward sale contract for the sale of about 15 MW per hour, or a total of 522,544 mWh, beginning November 17, 2004 through December 31, 2008. As of December 31, 2005 about 141,800 mWh have been delivered under the contract. This contract has been determined to be a derivative under SFAS No. 133. The Company utilizes over-the-counter quotations or broker quotes at the end of the reporting period for determining the fair value of this contract. The derivative's estimated fair value was an unrealized loss of $12.9 million at December 31, 2005 and a $0.4 million unrealized gain at December 31, 2004.
The Company records derivative contracts on the Consolidated Balance Sheets at fair value. At December 31, 2005, the total fair value was an unrealized loss of $17.9 million, the long-term portion of $13.4 million is included Deferred Credits and Other Liabilities and the short-term portion of $4.5 million is included in Current Liabilities. At December 31, 2004, the net total fair value was an unrealized loss of $5.3 million, the long-term portion of $5.8 million is included in Deferred Credits and Other Liabilities and the short-term portion of $0.5 million is included in Other current assets. Based on a PSB-approved Accounting Order, the Company records the change in fair value of these derivatives as deferred charges or deferred credits, depending on whether the fair value is an unrealized loss or gain. See Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits.
Investments in Marketable Securities The Company accounts for investments in marketable equity and debt securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities ("SFAS No. 115"). At December 31, 2005, all of the Company's marketable securities, except money market funds included in cash and cash equivalents, were classified as available-for-sale and reported at fair value. Unrealized gains and losses are reported as a component of accumulated other comprehensive income, net of tax, in common stock equity. The carrying cost of debt securities is adjusted for amortization of premiums and accretion of discounts from the date of purchase to maturity.
The Company evaluates the carrying value of its investments on a quarterly basis, or when events and circumstances warrant, determining whether a decline in fair value should be considered other-than-temporary. The carrying value is considered impaired when the anticipated fair value, based on cash flow forecasts, is less than the carrying value of each investment. In that event, a realized loss is recognized based on the amount by which the carrying value exceeds the fair value of the investment. The Company uses the amortized cost basis in computing realized gains and losses on the sale of its available-for-sale securities. These realized gains and losses are included in other income or deductions. See Note 5 - Financial Instruments and Investment Securities for additional information.
Cash and Cash Equivalents The Company considers all liquid investments with an original maturity of three months or less when acquired to be cash and cash equivalents.
Page 79 of 153
Restricted Cash At December 31, 2005, the Company held $0.9 million of restricted cash related to property release requirements under the first mortgage indenture. At December 31, 2004, the Company held no restricted cash.
Special Deposits At December 31, 2005, the Company had special deposits of $21.1 million including $19.1 million for collateral payments and $2.0 million for mandatory redeemable preferred stock. At December 31, 2004, the Company had special deposits of $2.0 million for mandatory redeemable preferred stock. The collateral payments relate to performance assurance requirements for certain of the Company's power contracts. These are described in Note 13 - Commitments and Contingencies - Performance Assurance. The mandatory redeemable preferred stock payments included $1.0 million for mandatory sinking fund payments and $1.0 million for optional sinking fund payments. The Company made these payments to Preferred Shareholders at the beginning of 2006 and 2005.
Supplemental Cash Flow Information Supplemental Cash Flow information is as follows (in thousands):
|
For the years ended December 31, |
|||
|
Cash paid during the year for: |
|
|
|
Auction rate securities Investments in auction rate securities and proceeds from sale of auction rate securities are included in the Investing Activities on the Consolidated Statements of Cash Flows.
Non-cash Operating, Investing and Financing Activities Construction and plant expenditures on the Consolidated Statements of Cash Flows reflect actual payments made during the periods. The Company accrues for construction and plant-related expenditures at the end of each reporting period and records the accruals to Accounts payable or Other current liabilities on the Consolidated Balance Sheets. Construction and plant-related cost accruals included in Accounts payable were $1.0 million at December 31, 2005 and $0.3 million at December 31, 2004, and amounts included in Other current liabilities were $0.5 million at December 31, 2005 and $0.2 million at December 31, 2004. In addition to these non-cash transactions also see Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits, Note 9 - Stock Award Plans and Note 13 - Commitments and Contingencies.
Cash Concentration Account The Company maintains a cash concentration account for payments related to its routine business activities. At the end of each reporting period, the Company records the amount of outstanding checks as a current liability, which represents a book overdraft position with a positive bank account balance.
Concentration Risk Financial instruments that potentially expose the Company to concentrations of credit risk consist primarily of cash, cash equivalents, available-for-sale securities, special deposits, accounts receivable and investments in affiliates.
The Company maintains a significant portion of its invested cash with numerous creditworthy issuers placed through major financial institutions. The Company's available-for-sale securities of $77.9 million (current and non-current) are invested in auction rate securities and in a bond portfolio managed by one investment manager. Auction rate securities generally have a credit quality of AAA and individual issues do not exceed $5.0 million. The bond portfolio is comprised of U.S. government agency obligations and high-quality corporate bonds. At December 31, 2005, the average credit quality of the bond portfolio was AA and individual issues do not exceed $3.0 million. The bond portfolio is subject to gains and losses primarily in response to interest rate changes. The remaining invested cash consists of high-quality money market funds.
The Company's accounts receivables are not collateralized. As of December 31, 2005, about 10 percent of total accounts receivable are with wholesale entities engaged in the energy industry. The Company's special deposits primarily represent collateral deposits held by counterparties engaged in the energy industry. In addition, all of the Company's investments in affiliates are companies engaged in the energy industry. This industry concentration could affect the Company's overall exposure to credit risk, positively or negatively, since customers may be similarly affected by changes in economic, industry or other conditions. The Company believes the credit risk posed by industry concentration is offset by 1) diversification and creditworthiness of its retail electric customer base, and 2) its investments in affiliates, which are subject to cost recovery through FERC rates.
Page 80 of 153
The Company's recent practice to mitigate credit risk from its energy industry concentration with wholesale entities is to deal with creditworthy power and transmission counterparties or obtain deposits or guarantees from their affiliates. The Company may also enter into third-party power purchase and sales contracts that require collateral based on credit rating or contain master netting arrangements in the event of nonpayment. Currently, the Company holds parental guarantees from two transmission customers and from two forward power sale counterparties.
Our material power supply contracts and arrangements are principally with Hydro-Quebec and VYNPC. These contracts supported about 84 percent of our total energy (mWh) purchases in 2005. These supplier concentrations could have a material impact on the Company's power costs, if one or both of these sources were unavailable over an extended period of time. The Company does not have the ability to seek collateral under these two contracts, but the contracts provide the ability to seek damages for non-performance.
Allowance for Doubtful Accounts The Company estimates the amount of accounts receivable that will not be collected and records these amounts as a reduction to accounts receivable. Included in the total allowance of $2.6 million at December 31, 2005 is a reserve of $1.4 million for uncollectibles related to a billing dispute and tariff settlement associated with pole attachments. The remaining $1.2 million is primarily related to retail customers.
At December 31, 2004, the total allowance of $1.9 million included a $1.0 million reserve for uncollectibles related to a billing dispute and tariff settlement and $0.9 million was primarily related to retail customers.
Reclassifications The Company will record reclassifications to prior year financial statements when considered necessary or to conform to current-year presentation.
Recent Accounting Pronouncements
SFAS No. 123R: In December 2004, the Financial Accounting Standards Board ("FASB") issued SFAS No. 123R, Share-Based Payments ("SFAS No. 123R"), which replaces SFAS No. 123 and supersedes APB 25. SFAS No. 123R requires that compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. SFAS No. 123R is effective for the Company in the first quarter of 2006.
In March 2005, the SEC issued Staff Accounting Bulletin ("SAB") No. 107, which expressed the views of the SEC regarding the interaction between SFAS No. 123R and certain SEC rules and regulations. SAB No. 107 provides guidance related to valuation of share-based payment arrangements for public companies, including assumptions such as expected volatility and expected term.
In December 2005, the Company made certain changes to its incentive compensation plans and Board of Directors compensation plan, including discontinuance of stock option grants as a component of compensation. These changes became effective January 1, 2006. Since stock option grants have been discontinued and all outstanding stock options were fully vested at December 31, 2005, adoption of SFAS No. 123R will not have a material impact on the Company's financial position or results of operations.
FASB Interpretation No. 47 ("FIN 47"): In March 2005, FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations. The Company adopted FIN 47 at December 31, 2005, as required. The adoption of FIN 47 did not have a material impact on the Company's financial position or results of operations. See discussion of Asset Retirement Obligations above for additional information.
Accounting for Uncertain Tax Positions: Since July 2004, FASB has been discussing potential changes or clarifications in the criteria for recognition of tax benefits that may result in raising the threshold for recognizing tax benefits, which have some degree of uncertainty. On July 14, 2005, the FASB issued an Exposure Draft on accounting for uncertain tax positions under SFAS No. 109, Accounting for Income Taxes. In November 2005, FASB redeliberated the scope and accounting model for accounting for uncertain tax positions and decided on a benefit recognition model with a two-step approach including a more-likely-than-not recognition criterion and a best estimate measurement attribute. Additionally, initial de-recognition amounts would be reported as a cumulative effect of a change in accounting principle.
Page 81 of 153
A final interpretation is expected to be issued by FASB in the first half of 2006. If adopted as proposed, only tax benefits that meet the probable recognition threshold may be recognized or continue to be recognized on the effective date. The Company has not yet evaluated the impact the proposed interpretation.
SFAS No. 154: In May 2005, FASB issued SFAS No. 154, Accounting Changes and Error Corrections, ("SFAS No. 154"), which replaces Accounting Principals Board Opinion No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to do so. SFAS No. 154 also provides that (1) a change in the method of depreciating or amortizing a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) correction of errors in previously issued financial statements should be termed a "restatement." The new standard is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The Company adopted SFAS No. 154 as of December 31, 2005. See Note 16 - Restatement.
Other-Than-Temporary Impairment: In November 2005, FASB issued Staff Position FSP FAS 115-1 and 124-1, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments ("FSP"). The FSP addresses the determination as to when an investment is considered impaired, whether the impairment is other-than-temporary, and the measurement of an impairment loss. The guidance in this FSP nullifies certain previous accounting requirements of Emerging Issues Task Force Issue No. 03-01, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments and is effective for reporting periods beginning after December 15, 2005, with early adoption permitted. The Company adopted the FSP at December 31, 2005. The application of this FSP did not have a significant impact on its consolidated financial position or results of operations.
SFAS No. 155:
Page 82 of 153
NOTE 2 - INVESTMENTS IN AFFILIATES
The Company's equity method investments are as follows (in thousands):
|
|
December 31, |
||
|
Vermont Yankee Nuclear Power Corporation ("VYNPC") |
58.85% |
$2,802 |
$2,822 |
Purchased Power - Affiliates
Related-party transactions with VYNPC, Maine Yankee, Connecticut Yankee and Yankee Atomic are included in Purchased Power - affiliates on the Consolidated Statements of Income. The nature of these transactions is described in more detail below and the components of Purchased Power - affiliates are summarized as follows (in thousands):
|
For the years ended December 31, |
|||
|
VYNPC |
$55,686 |
$58,300 |
$65,169 |
Vermont Yankee Nuclear Power Corporation ("VYNPC")
VYNPC sold its nuclear plant to Entergy Nuclear Vermont Yankee, LLC ("ENVY") in July 2002. The sale agreement included a purchased power contract ("PPA"), which VYNPC administers among the former plant owners, including the Company, and ENVY. Under the PPA between ENVY and VYNPC, VYNPC pays ENVY for generation at fixed rates. VYNPC, in turn, bills the PPA charges from ENVY with certain residual costs of service through a FERC tariff to the Company and the other VYNPC sponsors. See Note 13 - Commitments and Contingencies for additional information.
The Company has a 58.85 percent ownership interest in VYNPC. Although the Company owns a majority of the shares of VYNPC, the Power Contracts, Sponsor Agreement and composition of the Board of Directors, under which it operates, effectively restrict the Company's ability to exercise control over VYNPC. The Company assessed its ownership interest in VYNPC under the provisions of FIN 46R and concluded that VYNPC is not a VIE. Therefore, VYNPC's financial statements have not been consolidated into the Company's financial statements.
The Company received $0.4 million of cash dividends from VYNPC in 2005 and $0.3 million in 2004. VYNPC's revenues shown in the table below include sales to the Company of $55.7 million in 2005, $58.3 million in 2004 and $65.2 million in 2003. Accounts payable to VYNPC amounted to $5.4 million at December 31, 2005 and $5.8 million at December 31, 2004.
Page 83 of 153
Summarized financial information for VYNPC follows (in thousands):
|
For the years ended December 31, |
||||
|
Operating revenues |
$160,613 |
$167,399 |
$187,123 |
|
|
|
|
|||
|
Current assets |
$26,767 |
$24,600 |
||
Vermont Electric Power Company, Inc ("VELCO")
VELCO and its wholly owned subsidiary, Vermont Electric Transmission Company, Inc., own and operate an integrated transmission system in Vermont over which bulk power is delivered to all electric utilities in the State. VELCO has entered into transmission agreements with the State of Vermont and all of the Vermont electric utilities. Under these agreements, it bills all costs, including interest on debt and a fixed return on equity, to the State, utilities and others that use the system. These contracts enable VELCO to finance its facilities primarily through the sale of first mortgage bonds. VELCO is also a participant with all of the major electric utilities in New England in the New England Power Pool ("NEPOOL"), acting for itself and as agent for electric utilities in Vermont, including the Company. The generating and transmission facilities of all of the participants are coordinated on a New England-wide basis through a central dispatching agency to assure their operation and maintenance in accordance with proper standards of reliability, and to attain the maximum practicable economy for all participants through the interchange of economy and emergency power.
VELCO operated pursuant to the terms of the 1985 Four-Party Agreement (as amended) with the Company and two other major distribution companies in Vermont, which provided that although the Company owned the majority of voting stock of VELCO, it would not exercise its voting rights to assert control, and also provided the utilities with an option to purchase VELCO assets. The Company no longer owns a majority of the voting stock of VELCO and the 1985 Four-Party Agreement, including the option to purchase assets, has been allowed to terminate without renewal. The Company assessed its ownership interest in VELCO under the provisions of FIN 46R and concluded that VELCO is not a VIE. Therefore, VELCO's financial statements have not been consolidated into the Company's financial statements.
In August 2004, FERC approved a joint filing by the Company and Green Mountain Power ("GMP") for authorization to purchase stock to be issued by VELCO in 2004 and 2005 in connection with financing its planned transmission upgrades. In December 2004, the Company invested about $7 million in VELCO's voting Class B common stock, changing its common stock ownership (voting and non-voting) to 47.02 percent from 50.49 percent. The decrease reflected acquisitions of voting common stock issued by VELCO in amounts below the Company's pro-rata ownership at the time of purchase. The Company made no additional equity investments in VELCO in 2005; however, on December 9, 2005, a stock dividend of 2,436 shares of VELCO's voting Class B common stock was distributed to the Company, changing its total common stock ownership (voting and non-voting) to 47.05 percent.
Page 84 of 153
The Company is entitled to about 47 percent of the dividends distributed by VELCO and is required to pay its share of VELCO's operating costs including debt service costs. The Company received about $1.5 million of cash dividends from VELCO in 2005, which included about $0.1 million related to return of capital from VELCO's Class C preferred stock. In 2004, the Company received about $0.9 million in cash dividends from VELCO. Of that amount, about $0.1 million was related to return of capital from VELCO's Class C preferred stock and $0.1 million was related to dividends declared in December 2004 for payment in January 2005.
VELCO bills the Company on a monthly basis for transmission and administrative costs associated with power and transmission services, including various credits such as those from ISO-New England under the NEPOOL Open Access Transmission Tariff ("NOATT"). Prior to May 2004, VELCO also billed the Company for its share of NOATT charges, which are now billed directly to the Company by ISO-New England. Included in VELCO's revenues below are billings to the Company of $2.7 million in 2005, $2.7 million in 2004 and $2.8 million in 2003. These amounts are reflected in Transmission - affiliates on the Company's Consolidated Statements of Income. Other transmission-related billings to the Company from VELCO that are not included in VELCO's revenues are included in Transmission - others on the Company's Consolidated Statements of Income. Accounts payable to VELCO amounted to $5.9 million at December 31, 2005 and $4.8 million at December 31, 2004.
Summarized financial information for VELCO follows (in thousands):
|
|
For the years ended December 31, |
||||
|
Operating revenues |
$28,586 |
$25,351 |
$23,107 |
||
|
|
December 31, |
||||
|
Current assets |
$26,044 |
$23,585 |
|||
Page 85 of 153
Maine Yankee, Connecticut Yankee and Yankee Atomic
The Company is responsible for paying its ownership percentage of decommissioning and all other costs for Maine Yankee, Connecticut Yankee and Yankee Atomic. All three companies collect decommissioning and closure costs through FERC-approved wholesale rates charged under power agreements with several New England utilities, including the Company. Information related to decommissioning and closure costs, including the Company's share of estimated future payments for each plant, follows (dollars in millions):
|
Date of Study |
Total |
Remaining Obligation (b) |
Revenue Requirements (c) |
Company Share (d) |
|
|
Maine Yankee |
2003 |
$522.8 |
$144.0 |
$241.3 |
$4.8 |
|
(a) Total cumulative decommissioning expenditures incurred through 2005, net of proceeds received from |
|||||
|
(b) Estimated remaining decommissioning costs in 2005 dollars for the period 2006 through 2023 for |
|||||
|
(c) Estimated future payments required by Sponsor companies to recover estimated decommissioning and |
|||||
|
(d) The Company's share of revenue requirements based on its ownership percentage of each plant. |
|||||
The Company's share of Maine Yankee, Connecticut Yankee and Yankee Atomic estimated costs are reflected on the Consolidated Balance Sheets as regulatory assets and nuclear decommissioning liabilities (current and non-current). These amounts are adjusted when revised estimates are provided by the companies. At December 31, 2005, the Company had regulatory assets of about $4.8 million related to Maine Yankee, $10.3 million related to Connecticut Yankee and $5.9 million related to Yankee Atomic (including about $0.7 million for incremental decommissioning costs already paid by the Company that are now being recovered in retail rates pursuant to the Rate Order). These estimated costs are being collected from the Company's customers through existing retail rate tariffs. Also see Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits related to regulatory accounting treatment of these costs.
Historically, the Company's share of these costs has been recovered from its retail customers through PSB-approved rates. Based on the regulatory process, Management believes its share of decommissioning and closure costs for each plant will continue to be recovered through the regulatory process. There is a risk, however, that FERC may not allow full recovery of Connecticut Yankee's increased costs in wholesale rates as described below.
Department of Energy ("DOE") Litigation: Maine Yankee, Connecticut Yankee and Yankee Atomic are seeking recovery of fuel storage-related costs stemming from the default of the DOE under the 1983 fuel disposal contracts that were mandated by the United States Congress under the Nuclear Waste Policy Act of 1982. Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants no later than January 1, 1998 in return for payments by each company into the nuclear waste fund. No fuel has been collected by the DOE, and spent nuclear fuel is being stored at each of the plants. Maine Yankee, Connecticut Yankee and Yankee Atomic collected the funds from wholesale utility customers, including the Company, under FERC-approved contract rates, and these payments were collected from the Company's retail customers. All three are parties to a lawsuit against the DOE seeking damages based on the DOE's default. The damage claims are specific to each plant and include incremental storage, security, construction and other costs through 2010. On September 9, 2005, the United States Court of Appeals for the Federal Circuit issued a decision involving another nuclear utility's spent fuel that, among other things, found plaintiffs in "partial breach" cases, such as Maine Yankee, Connecticut Yankee and Yankee Atomic, were not entitled to future damages. The date or event beyond which damages were to be considered "future damages" was not clarified by the Court. The ruling does not bar a plaintiff from seeking future damages in subsequent proceedings after the damages have been incurred. In response to the trial judge's request for supplemental briefing on the impact of the future-damages ruling, Maine Yankee, Connecticut Yankee and Yankee Atomic contended that the Court should award damages through 2002 initially and direct the parties to promptly pursue additional proceedings for recovery of post-2002 incurred damages. The DOE contended that all three
Page 86 of 153
companies could recover damages in the ongoing proceeding only through the date when they filed suit in June 1998. On February 28, 2006, all three companies asked the Court to allow amended damage claim filings to cover the period ending December 31, 2002. The proposed amended damage claims are about $79 million for Maine Yankee, $82.8 million for Connecticut Yankee and $101.8 million for Yankee Atomic. This compares to original claims of $160 million for Maine Yankee, $197.1 million for Connecticut Yankee and $191 million for Yankee Atomic. Due to the complexity of the issues and the possibility of appeals, the three companies cannot predict the amount of damages to be received or the timing of the final determination of such damages. None of the companies have included any allowance for potential recovery of these claims in their FERC-filed cost estimates.
Maine Yankee: The Company has a 2 percent ownership interest in Maine Yankee. In 2005, the Company received less than $0.1 million in dividends and $0.1 million in return of capital in the form of stock redemption from its investment in Maine Yankee. In 2004, the Company received about $0.1 million in dividends. Beginning November 1, 2004, Maine Yankee's billings to sponsor companies have been based on its September 16, 2004 FERC-approved settlement, which provides for recovery of Maine Yankee's forecasted costs of providing service through a formula rate contained in its power contracts through October 31, 2008 and replenishment of the DOE Spent Fuel Obligation through collections from November 2008 through October 2010. On October 3, 2005, Maine Yankee completed its decommissioning efforts and the Nuclear Regulatory Commission ("NRC") amended its operating license for operation of the Independent Spent Fuel Storage Installation.
In October 2005, Maine Yankee provided an updated forecast for ongoing costs, which reflects an estimated increase of about $10.1 million. The increase is primarily related to higher-than-expected interest expense. The Company's share of these estimated increased costs is about $0.2 million.
Connecticut Yankee: The Company has a 2 percent ownership interest in Connecticut Yankee. The Company received about $0.1 million of dividends from its investment in Connecticut Yankee in 2004 and none in 2005. Costs billed by Connecticut Yankee are based on FERC-filed rates effective February 1, 2005 for collection through 2010. Before February 1, 2005 costs were based on FERC-approved rates that became effective September 1, 2000 for collection through 2007. Connecticut Yankee is involved in a contract dispute and a FERC rate case filing. These matters are described in more detail below.
Bechtel Litigation: Connecticut Yankee is involved in a contract dispute with Bechtel Power Corporation ("Bechtel"), which resulted in default termination of the decommissioning services contract between Connecticut Yankee and Bechtel effective July 2003. Connecticut Yankee continues to prosecute its counterclaims for excess completion costs and other damages against Bechtel in Connecticut Superior Court ("Court"). Discovery is under way and a trial has been scheduled for May 2006. Connecticut Yankee has filed for a continuance of the lawsuit until FERC makes a final ruling on the Administrative Law Judge ("ALJ") order in the rate case described below. Connecticut Yankee filed for continuance based on its determination that FERC's final decision may preclude Bechtel from relitigating fundamental factual issues already decided in the FERC case which could substantially shorten the trial.
On June 18, 2004, Bechtel filed an Application for Prejudgment Remedy ("PJR") requesting a $93 million garnishment of the Decommissioning Trust ("Trust"), Connecticut Yankee shareholder payments to the Trust and any proceeds from the fuel disposal contract litigation pending between Connecticut Yankee and the DOE, as well as attachment of any Connecticut Yankee assets, including the Haddam Neck real property. On July 16, 2004, Connecticut Yankee filed its Objection to the PJR, including challenging the legal availability of the remedies requested by Bechtel. On July 20, 2004, the Court allowed the Connecticut Department of Public Utility Control ("CT DPUC") to intervene in the PJR proceeding for the limited purpose of objecting to Bechtel's requested garnishment of the Trust and related payments. The Court held an August 26, 2004 oral argument on the legal availability of the remedies requested by Bechtel but has not issued a decision, and an evidentiary hearing on the other PJR issues began on October 19, 2004.
On October 24, 2004, before conclusion of the hearing, Bechtel and Connecticut Yankee entered into a Stipulation Regarding Prejudgment Remedy whereby Bechtel waived and relinquished its right to seek prejudgment attachment or garnishment of the Trust and any future payments into the Trust, including proceeds from pending DOE litigation. Bechtel amended its Application for PJR to seek only attachment of all real property owned by Connecticut Yankee in Connecticut up to $7.9 million and to garnish only to the extent of $41.7 million (plus earned interest) that Connecticut Yankee's sponsors are scheduled to pay related to recovery
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of net unamortized assets through June 30, 2007. The agreement does not materially change the legal positions in this litigation. The CT DPUC did not object to the agreement.
On September 6, 2005, Connecticut Yankee submitted a summary judgment motion for dismissal of Bechtel's negligent misrepresentation claim. On October 7, 2005, Bechtel filed a motion withdrawing its negligent misrepresentation claim. On January 27, 2006, the ALJ issued a decision on Bechtel's June 18, 2004 Application for PJR that grants Bechtel an amount not to exceed $49.6 million, which includes attachment of Connecticut Yankee's real property up to $7.9 million and garnishment of sponsor payments of $41.7 million to be placed in an escrow account. Connecticut Yankee is currently taking action to implement the requirements of the October 24, 2004 Stipulation Regarding Prejudgment Remedy and evaluating other legal actions including the possibility of an appeal of the ALJ decision. The January 27, 2006 ALJ decision has no impact on the amount billed to sponsor companies.
See Note 17 - Subsequent Events for a February 2006 agreement reached between Connecticut Yankee and Bechtel related to this matter.
FERC Rate Case Filing: In December 2003, Connecticut Yankee established an updated estimate of decommissioning and plant closure costs for the period 2000 through 2023 ("2003 Estimate"). The 2003 Estimate reflects increased costs including the fact that Connecticut Yankee is now directly managing the work (self-performing) to complete decommissioning of the plant following the default termination of Bechtel. The 2003 Estimate does not include any allowance for cost recovery related to the Bechtel litigation. The 2003 Estimate of about $831 million represents an aggregate increase of about $395 million compared to the cost estimate in Connecticut Yankee's 2000 FERC rate case settlement (stated in 2003 dollars). On July 1, 2004, Connecticut Yankee filed the 2003 Estimate with FERC as part of its rate application ("Filing") seeking additional funding to complete the decommissioning project and for storage of spent fuel through 2023. The Filing was required to be filed as part of the terms of the 2000 FERC rate case settlement agreement. In the Filing, Connecticut Yankee sought to increase its annual decommissioning collections from $16.7 million to $93 million through 2010 beginning January 1, 2005. The CT DPUC and Bechtel intervened in this rate case.
On August 30, 2004, FERC issued an order: 1) accepting for filing the new charges proposed by Connecticut Yankee in its rate application; 2) suspending these revised charges until February 1, 2005; 3) establishing ALJ hearing procedures and schedules; 4) denying the CT DPUC and Connecticut Office of Consumer Counsel ("OCC") request for an accelerated hearing schedule and for a bond or other security for potential refunds; 5) denying the declaratory ruling sought by the CT DPUC and OCC; and 6) granting Bechtel's motion to intervene as well as allowing interventions by other applying parties. On September 7, 2004, a FERC ALJ was appointed to the case and the evidentiary hearing commenced on June 1, 2005 and concluded on June 22, 2005.
Both the CT DPUC and Bechtel filed testimony in the FERC proceeding claiming that Connecticut Yankee was imprudent in its management of the decommissioning project. In the CT DPUC's February 22, 2005 filed testimony, it recommended a disallowance of $225 million to $234 million out of Connecticut Yankee's $395 million requested increase.
On November 22, 2005, the ALJ issued an Initial Decision that found: there was no evidence of Connecticut Yankee imprudence, and the record established that Connecticut Yankee's actions were in fact prudent and consistent with those of prudent utility management made in good faith; because Connecticut Yankee is a FERC-jurisdictional utility, it should continue filing relevant FERC reports for the remainder of the decommissioning period. The only adjustment to Connecticut Yankee's decommissioning charges required by the Initial Decision relates to the escalation rate, which is the factor used to translate the 2003 Estimate (stated in 2003 dollars) into spending projections and decommissioning charges. The Initial Decision found that Connecticut Yankee should recalculate its decommissioning charges to reflect a lower escalation rate. The Initial Decision is subject to review by FERC.
The Company continues to believe that FERC will approve recovery of Connecticut Yankee's increased costs in wholesale rates based on the nature of costs and previous rulings at other nuclear companies. Once approved by FERC, the Company believes it is unlikely that the PSB would not allow these FERC-approved costs to be recovered in retail rates. However, there is a risk, notwithstanding the ALJ Initial Decision, that some portion of the increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.
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If FERC disallows cost recovery in wholesale rates, the Company anticipates that the PSB would disallow these costs for recovery in retail rates as well. The timing, amount and outcome of the Bechtel litigation and FERC rate case filing cannot be predicted at this time.
Yankee Atomic: The Company has a 3.5 percent ownership interest in Yankee Atomic. Costs billed by Yankee Atomic are based on a November 23, 2005 FERC filing primarily to recover increased costs associated with remediation of non-hazardous and hazardous waste volumes in excess of estimates in the previously concluded rate case. Prior to this filing, costs billed by Yankee Atomic were based on its April 4, 2003 FERC-approved rate filing. The decommissioning effort is largely complete and final site-work is expected to conclude in 2006. Following the completion of decommissioning, the remaining on-site function will be to operate the Independent Spent Fuel Storage Installation.
In November 2005, Yankee Atomic established an updated estimate ("2005 Estimate") of the cost of completing the decommissioning effort. The 2005 Estimate reflects the costs of completing site closure activities from October 2005 forward and storing spent nuclear fuel and other high-level waste on site until 2020, the date at which the DOE is expected to remove the waste. The 2005 Estimate projects a cost of $192.1 million (in 2006 dollars) for completion of decommissioning and long-term fuel storage, or about $240.8 million based on estimated inflation.
On November 23, 2005, Yankee Atomic submitted an application to FERC for increased decommissioning charges based on its 2005 Estimate. Yankee Atomic proposed to collect decommissioning charges of about $54.9 million in 2006 and $23.5 million annually for 2007 through 2010. This compares to previously scheduled annual charges of about $12.8 million for 2006 through 2010. Hearings on the FERC rate case began in December 2005, and several parties including the DPS filed motions to intervene and protest. On January 1, 2006, FERC issued an Order: 1) accepting Yankee Atomic's rate filing; 2) permitting the proposed rates to go into effect, subject to refund, as of February 1, 2006; and 3) referring the parties to a settlement judge to facilitate a possible settlement. The Company's share of the rate increase amounts to about $1.5 million for 2006 and $0.4 million annually for 2007 through 2010.
NOTE 3 - DISCONTINUED OPERATIONS
The Company's discontinued operations include 1) Catamount based on the Company's November 2005 decision to sell all of its interest in Catamount, and consummation of the sale on December 20, 2005; and 2) Connecticut Valley due to the January 1, 2004 sale of its plant assets and franchise. These sales are described in more detail below. The components of Income from discontinued operations (net of income tax) on the Consolidated Statements of Income follow (in thousands):
|
For the years ended December 31, |
|||
|
Catamount's results of operations |
$(671) |
$3,922 |
$1,207 |
|
4,936 |
3,922 |
1,207 |
|
|
Connecticut Valley's results of operations |
- |
(14) |
1,446 |
|
Gain on Connecticut Valley sale |
- |
12,354 |
- |
|
- |
12,340 |
1,446 |
|
|
Income from discontinued operations |
$4,936 |
$16,262 |
$2,653 |
Catamount Energy Sale On October 12, 2005, the Company entered into a Stock Subscription Agreement with CRC, Catamount and Diamond Castle. The Stock Subscription Agreement provided that, upon certain terms and conditions, Diamond Castle would invest $62.5 million in Catamount over the next three years for an ultimate 51 percent ownership interest in Catamount.
Concurrent with the Stock Subscription Agreement, the parties also entered into a Stockholders' Agreement to govern CRC's and the Company's ongoing relationship with Diamond Castle as stockholders of Catamount and a Put Option Purchase and Sale Agreement ("Put Option"). The Put Option provided, among other things, CRC with the option to sell to Diamond Castle its entire interest in Catamount. The option, exercisable by CRC on or before March 31, 2006, was subject to certain terms and conditions, and provided for an aggregate consideration of $60.0 million less certain transaction expenses.
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At the initial closing that occurred on October 31, 2005, Diamond Castle invested $16.0 million in Catamount for 160,000 shares of Class A common stock, par value $0.01 per share, (representing about 21 percent of the outstanding common equity of Catamount) and one share of Class B common stock, par value $0.01 per share, of Catamount. The share of Class B common stock, together with Diamond Castle's Class A common stock, provided Diamond Castle a 51 percent voting interest in Catamount, while CRC retained the remaining 49 percent voting interest. Under certain circumstances, including default by Diamond Castle in its funding obligations, the Class B share would have converted to a single share of Class A Common stock.
On November 21, 2005, the Company announced its decision to sell all of its interest in Catamount to Diamond Castle. On the same day, Diamond Castle waived certain conditions of the Put Option and CRC exercised it. The sale was consummated on December 20, 2005. Cash proceeds from the sale amounted to $59.25 million, resulting in an after-tax gain of $5.6 million. Components of the gain are as follows (in thousands):
|
Cash proceeds |
$59,250 |
Under the terms of the Stock Subscription Agreement, the Company agreed to indemnify Catamount and Diamond Castle, and certain of their respective affiliates, in respect of a breach of certain representations and warranties and covenants, most of which survive until June 30, 2007, except certain items that customarily survive indefinitely. The Company indemnified all losses related to taxes for periods prior to the initial closing, subject to a "true up" post-closing. Indemnification is net of insurance and taxes, and materiality is disregarded from all representations and warranties. Indemnification is subject to a $1.5 million deductible and a $15.0 million cap, excluding certain customary items. Environmental representations are subject to the deductible and the cap, and such environmental representations for only two of Catamount's underlying energy projects survive beyond June 30, 2007.
In the fourth quarter of 2005, the Company recorded a $0.3 million contingent liability related to one of Catamount's projects. This amount represents the Company's estimate of the fair value of the indemnification which is not subject to the deductible. The Company's estimated "maximum potential" amount of future payments related to these indemnifications is limited to $15.0 million. The Company has not recorded any additional liability related to these indemnifications.
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Catamount's results of operations included in discontinued operations reflect the reallocation of certain corporate costs back to continuing operations since they were not eliminated by the sale. These pre-tax costs amounted to about $0.5 million in 2005, $0.5 million in 2004 and $0.8 million in 2003 and are included in Catamount's operating expenses, net of tax. Catamount's results of operations are summarized in the table below (in thousands).
|
For the years ended December 31, |
|||
|
Operating revenues |
$- |
$- (315) 315 4,220 2,518 1,895 (6,674) 1,928 3,887 4,202 280 3,922 - $3,922 |
$- (471) 471 6,362 - 1,046 (7,823) 1,808 1,393 1,864 657 1,207 - $1,207 |
|
December 31, |
||
|
2005 2004 |
||
|
Assets |
|
2,495 1,725 29,182 2,301 946 $60,957 $18 11,000 4,999 2,613 $18,630 |
|
(a) Represents note payable to the Company that was paid in full in the first quarter of 2005. |
||
Connecticut Valley Sale On January 1, 2004, Connecticut Valley completed the sale of substantially all of its plant assets and its franchise to PSNH. The sale, including termination of the power contract between the Company and Connecticut Valley, resolved all Connecticut Valley restructuring litigation in New Hampshire and the Company's stranded cost litigation at FERC.
For accounting purposes, components of the sale transaction were recorded in both continuing and discontinued operations on the 2004 Consolidated Statement of Income. Income from discontinued operations included a gain on disposal of about $21 million pre-tax, or $12.3 million after-tax. In addition to the gain on disposal, the Company recorded a loss on power costs of $14.4 million pre-tax, or $8.4 million after-tax relating to termination of the power
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contract with Connecticut Valley. The loss is included in Purchased Power on the 2004 Consolidated Statement of Income. When the two accounting transactions are combined to assess the total impact of the sale, the result was a first-quarter 2004 after-tax gain of $3.9 million.
There are no remaining significant business activities related to Connecticut Valley. Its results of operations included in discontinued operations are as follows (in thousands):
|
For the years ended December 31, |
|||
|
Operating revenues |
$- |
$23 |
$19,728 |
NOTE 4 - REGULATORY ASSETS, DEFERRED CHARGES AND DEFERRED CREDITS
Under SFAS No. 71, the Company accounts for certain transactions in accordance with permitted regulatory treatment such that regulators may permit incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when recovered in future revenues. Regulatory assets represent probable future revenue associated with certain costs that will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Other deferred charges - regulatory represent amounts for which the Company has PSB-approved accounting orders for treatment as deferred charges.
In the Rate Order, the PSB determined the annual revenue requirement for the period April 1, 2004 through March 31, 2005, and established that rates during that period included recovery of certain deferred charges and regulatory liabilities. As a result, in the first quarter of 2005, the Company adjusted certain deferred charges and credits, and recorded amortizations of certain regulatory assets and regulatory liabilities as if they had begun on April 1, 2004. Additionally, certain deferred charges were reclassified to regulatory assets to reflect rate recovery. These Rate Order-related adjustments resulted in a net $15.3 million decrease in Net regulatory assets, deferred charges and deferred credits in the first quarter of 2005 with an offsetting $15.3 million pre-tax charge to earnings. See Note 12 - Retail Rates for additional information.
Regulatory assets and certain other deferred credits are being amortized in accordance with the Rate Order. In the Rate Order, the PSB ordered that when a regulatory asset or liability is fully amortized, the corresponding rate revenue shall be booked as a reverse amortization in an opposing regulatory liability or asset account. These items, including other deferred credits, are also adjusted upward or downward in accordance with permitted regulatory treatment. The table below provides a summary of net regulatory assets, deferred charges and deferred credits. The bulleted items a) - n) following the table provide information regarding these regulatory items.
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|
(in thousands) |
||
|
December 31, |
||
|
Regulatory assets *Nuclear plant dismantling costs (a) Nuclear refueling outage costs - Millstone Income taxes Vermont Yankee sale costs (non-tax) (b) |
|
|
|
Other deferred charges - regulatory Nuclear plant incremental dismantling costs (a) Vermont Yankee sale costs (tax) Vermont Yankee sale costs (non-tax) (b) Vermont Yankee fuel rod maintenance deferral (c) Vermont Yankee replacement energy deferral (f) Pole treating expense (g) Unrealized loss on power contract derivatives (h) Subtotal Other deferred charges - regulatory |
|
|
|
Other deferred credits - regulatory Vermont utility overearnings 2001 - 2003 (i) Connecticut Valley gain on termination of power contract (j) Asset retirement obligation - Millstone Unit #3 (e) Vermont Yankee IRS settlement (k) Emission allowances and renewable energy credits (l) IPP settlement reimbursement and VEPPI cost mitigation (m) Millstone Unit #3 decommissioning (n) Tree trimming expense (g) Unrealized gain on power contract derivatives (h) Other Subtotal Other deferred credits - regulatory |
|
|
|
Net regulatory assets, deferred charges and deferred credits |
$36,065 |
$38,931 |
|
* Regulatory assets are being recovered in retail rates, except for the asset retirement obligations. All regulatory assets are earning a return, expect for income taxes, asset retirement obligations, and nuclear dismantling costs that have not yet been incurred by the Company. |
||
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The Company recorded a $2.5 million pre-tax charge to earnings in the first quarter of 2005 to reflect Rate Order-required adjustments, including a $2.0 million charge to operating expense and a $0.5 million reduction of interest income. Deferred charges were also reclassified to regulatory assets, to reflect rate recovery. First-quarter 2005 carrying cost adjustments and amortizations beginning April 1, 2005 have also reduced the balance by $1.4 million.
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Company established a regulatory liability in the amount of $6.6 million pre-tax, offset by amortization of $2.2 million, resulting in net $4.4 million pre-tax charge to earnings in the first quarter of 2005. Amortizations beginning April 1, 2005 have further reduced the balance by about $1.7 million. Also see Note 12 - Retail Rates.
NOTE 5 - FINANCIAL INSTRUMENTS AND INVESTMENT SECURITIES
The estimated fair values of the Company's financial instruments are as follows (in thousands):
|
2005 |
2004 |
|||
|
Carrying |
Fair |
Carrying |
Fair |
|
|
Preferred stock not subject to |
|
|
|
|
|
* Fair values are reported to meet disclosure requirements and do not necessarily represent the amounts at |
||||
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Cash, Receivables and Payables The carrying amounts of cash and cash equivalents, restricted cash, special deposits, receivables and payables approximate fair value because of the short maturity of those instruments.
Preferred stock, notes payable and long-term debt The fair value of the Company's fixed rate securities is estimated based on quoted market prices for the same or similar issues with similar remaining time to maturity or on current rates offered to the Company. Monthly adjustable-rate securities are assumed to have a fair value equal to their carrying value.
Derivatives The estimated fair value of derivatives related to power contracts is based on over-the-counter quotations or broker quotes at the end of the reporting period, with the exception of one long-term power contract that is valued using a binomial tree model, and quoted market data when available, along with appropriate valuation methodologies. These derivative instruments are recorded at fair value in the Consolidated Balance Sheets.
Life Insurance Investments Life insurance investments are held in a Rabbi Trust for the benefit of executive retirement plans. These life insurance policies are recorded at the net cash surrender value or fair value on the Consolidated Balance Sheets. At December 31, 2005 and 2004, these life insurance investments had a fair value of $6.3 million and $6.0 million, respectively, equal to their carrying value.
Available-for-sale securities The Company's available-for-sale securities are invested in auction rate securities and in a bond portfolio managed by one investment manager. The auction rate securities generally have a credit quality of AAA, and the underlying securities are equity and debt instruments with maturity dates in excess of 20 years. The Company can sell these auction rate securities on the rate reset dates which occur every 7, 14 or 28 days. Because of the frequency of the rate reset, these auction rate securities generally trade at par and the cost is equivalent to fair value. The Company's bond portfolio is comprised of U.S. government agency obligations and high-quality corporate bonds. At December 31, 2005, the average credit quality of the bond portfolio was AA. The bond portfolio is subject to gains and losses primarily in response to interest rate changes, and is recorded at fair value.
The Company evaluates the carrying value of the bond portfolio on a quarterly basis, or when events and circumstances warrant evaluation to determine whether a decline in fair value is considered temporary or other-than-temporary. The Company considers several criteria in evaluating other-than-temporary declines including: 1) length of time and extent to which market value has been less than cost; 2) financial condition and near-term prospects of the issuer; and 3) intent and ability of the Company to retain its investment in the issuer for a period of time sufficient to allow for any anticipated recovery in market value. In the first quarter of 2005, the Company recorded a $0.3 million other-than-temporary impairment of certain available-for-sale investments based on its intent to liquidate those securities prior to their original maturity dates. Based upon forecasted cash flow needs at that time, those securities closest to maturity were impaired. Generally, a security close to its maturity date should have less pricing volatility due to interest rate movements than one further from its maturity date. There was no further impairment in 2005 related to these investment securities.
In 2005, the Company recorded $0.4 million of debt security premium amortizations to interest income as a deduction from the coupon interest earned on available-for-sale securities. The Company also recorded $0.1 million of realized losses offset by minimal realized gains during 2005; these amounts were related to specific securities.
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The unrealized losses on available-for-sale securities shown below, both on an individual and aggregate basis, are minor when compared to the original costs and are related to securities the Company expects to hold, based on forecasted cash needs. Therefore, such unrealized losses are considered temporary. Information regarding available-for-sale securities at December 31, 2005 and 2004 follows (in thousands):
|
For the years ended December 31, |
||||||||
|
|
Amortized |
Fair |
Unrealized |
Unrealized |
Amortized |
Fair |
Unrealized |
Unrealized |
|
Current Assets: US Government Obligations US Government Agencies Corporate Bonds Auction Rate Securities Subtotal Equity Securities: Auction Rate Securities Subtotal Investments and Other Assets: Debt Securities: US Government Obligations US Government Agencies Corporate Bonds Subtotal Total |
|
|
4 $115 |
|
|
|
|
|
Information related to the fair value of debt securities at December 31, 2005 follows (in thousands):
|
Fair value of debt securities at contractual maturity dates |
|||||
|
|
Less than 1 year |
1 to 5 years |
5 to 10 years |
After 10 years |
Total |
The following table presents the gross unrealized losses and fair value of certain available-for-sale securities, aggregated by investment category and the length of time the securities have been in a continuous loss position, at December 31, 2005 (in thousands):
|
Debt Securities |
||
|
Fair Value |
Unrealized Losses |
|
|
Less than 12 months (2 securities) |
$4,913 |
$32 |
Millstone Decommissioning Trust Fund The Company has decommissioning trust fund investments related to its joint-ownership interest in Millstone Unit #3. The decommissioning trust fund was established pursuant to various federal and state guidelines. Among other requirements, the fund is required to be managed by an independent and prudent fund manager. Any gains or losses, realized and unrealized, are expected to be refunded to or collected from ratepayers, respectively. For that reason, the fair value is adjusted by realized and unrealized gains and losses, with a corresponding decommissioning liability recorded as Asset Retirement Obligations on the Consolidated Balance Sheets.
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These investments are subject to the requirements of SFAS No. 115, and are recorded at fair value in Investments and Other Assets on the Consolidated Balance Sheets. The unrealized losses on the decommissioning trust fund are minor when compared to their original cost; therefore, they are considered temporary. The fair value of these investments is summarized below (in thousands):
|
For the years ended December 31, |
||||||||
|
|
Amortized |
|
Unrealized |
Unrealized |
Amortized |
|
Unrealized |
Unrealized |
|
Equity Securities |
$2,415 |
$3,551 |
$1,151 |
$15 |
$2,464 |
$3,537 |
$1,093 |
$20 |
Information related to the fair value of debt securities at December 31, 2005 follows (in thousands):
|
Fair value of debt securities at contractual maturity dates |
|||||
|
|
Less than 1 year |
1 to 5 years |
5 to 10 years |
After 10 years |
Total |
The following table presents the gross unrealized losses and fair value of certain investments, aggregated by investment category and the length of time these numerous securities have been in a continuous loss position, at December 31, 2005 (in thousands):
|
Equity Securities |
Debt Securities |
|||
|
Fair Value |
Unrealized Losses |
Fair Value |
Unrealized Losses |
|
|
Less than 12 months |
$4 |
- |
$597 |
$9 |
NOTE 6 - NOTES PAYABLE
The Company's notes payable consisted of the following (in thousands):
|
2005 |
2004 |
|
|
Vermont Industrial Development Authority Bonds Variable, due 2013 (3.16% at December 31, 2005) Connecticut Development Authority Bonds Variable, due 2015 (3.10% at December 31, 2005) Total Notes Payable |
|
|
These bonds are floating rate, monthly demand, pollution-control, revenue bonds. There are no interim sinking fund payments due prior to the maturity dates shown in the table above. The interest rate resets monthly. Both series are callable at par as follows: 1) at the option of the Company or bondholders on each monthly interest payment date; or 2) at the option of the bondholders on any business day. There is a remarketing feature if the bonds are put for redemption. Historically, these bonds have been remarketed in the secondary bond market. The Company has outstanding unsecured short-term letters of credit that support these bonds, as described in Note 7 below.
NOTE 7 - LONG-TERM DEBT AND CREDIT FACILITY
The Company's long-term debt consisted of the following (in thousands):
|
2005 |
2004 |
|
|
First Mortgage Bonds 6.27%, Series NN, due 2008 5.00%, Series SS, due 2011 5.72%, Series TT, due 2019 6.90%, Series OO, due 2023 8.91%, Series JJ, due 2031 New Hampshire Industrial Development Authority Bonds Variable 3.75%, due 2009 Total long-term debt |
$3,000 |
$3,000 |
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Long-Term Debt: Substantially all of the Company's utility property and plant is subject to liens under the Company's First Mortgage Bonds. The First Mortgage Bonds are callable at the Company's option at any time upon payment of a make-whole premium, calculated as the excess of the present value of the remaining scheduled payments to bondholders, discounted at a rate that is 0.5 percent higher than the comparable U. S. Treasury Bond yield, over the early redemption amount. Scheduled sinking fund payments for the next five years are $0 in 2006, $0 in 2007, $3.0 million in 2008, $5.5 million in 2009, and $0 in 2010.
The Company's New Hampshire Industrial Development Authority Bonds are pollution control bonds and the interest rate resets every five years. These bonds are callable at the option of the Company or the bondholders every five years on the rate reset date. The last rate reset date occurred on December 1, 2004. As of December 31, 2005, the bonds are only callable at the option of the Company in special circumstances involving unenforceability of the indenture or a change in the usability of the project.
The Company's debt financing documents do not contain cross-default provisions to affiliates outside of the consolidated entity. Certain of the Company's debt financing documents contain cross-default provisions to its wholly owned subsidiaries, East Barnet, CV Realty and Custom Investment Corporation. These cross-default provisions generally relate to an inability to pay debt or debt acceleration, inappropriate affiliate transactions or the levy of significant judgments or attachments against our property. Currently, the Company is not in default under any of its debt financing documents.
Credit Facility: On October 27, 2005, the Company closed on a three-year, $25.0 million unsecured revolving credit facility with a lending institution pursuant to a Credit Agreement dated October 21, 2005. On September 30, 2005, the PSB approved the Company's plans to enter into a credit facility and on November 15, 2005 the PSB approved all of its terms. The purpose of the facility is to provide liquidity for general corporate purposes, including working capital needs and power contract performance assurance requirements, in the form of borrowings and letters of credit. Financing terms and costs include an annual commitment fee on the unused balance, plus interest on the outstanding balance of borrowings and letters of credit that is based on our unsecured long-term debt rating. Terms also include the requirement to collateralize any outstanding letters of credit in the event of a default under the credit facility. This facility also contains a Material Adverse Effect ("MAE") clause (a standard that requires greater adversity than a Material Adverse Change clause); this clause is in effect only when the Company's credit rating is below investment grade. The MAE clause could allow the lending institution to deny a transaction under the credit facility at the point of request. Once any borrowing is advanced, its maturity cannot be accelerated for reasons other than an event of default. At December 31, 2005 there were no borrowings or letters of credit outstanding under this facility.
Letters of Credit: The Company has three outstanding unsecured letters of credit, issued by one bank, totaling $16.9 million in support of three separate issues of industrial development revenue bonds totaling $16.3 million, of which $10.8 million is included in Notes Payable and $5.5 million is included in Long-Term Debt. These letters of credit, which expired on November 30, 2005, were extended by the bank to November 30, 2006. The bank required that these letters of credit now be secured under the Company's first mortgage indenture due to the Company's non-investment grade credit rating. At December 31, 2005, there were no amounts outstanding under these letters of credit.
Covenants: The Company's long-term debt indentures, letters of credit, and credit facility contain financial and non-financial covenants. Most restrictive financial covenants include maximum debt to total capitalization of 50 percent, and minimum interest coverage of 1.75 times. In the second quarter of 2005, we paid a consent fee of about $0.2 million to our bondholders in exchange for waiver of any interest coverage default that could result from the first quarter 2005 Rate Order charge. At December 31, 2005, the Company was in compliance with all covenants.
Dividend and Optional Stock Redemption Restrictions: The Company's $25.0 million revolving credit facility restricts optional redemptions of capital stock. On November 28, 2005, the Company received a waiver of terms under the credit facility allowing it to optionally redeem $1.0 million of its 8.3 percent preferred stock at par on January 1, 2006 and to proceed with the buyback of up to $50.0 million of common stock. The First Mortgage Bond indenture and the Company's Articles of Association also contain certain restrictions on the payment of cash dividends on and optional redemptions of all capital stock. Under the most restrictive of these provisions, about $90.0 million of retained earnings was not subject to such restriction at December 31, 2005. The Articles also restrict the payment of common dividends or purchase of any common shares if the common equity level falls below
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25 percent of total capital, applicable only as long as Preferred Stock is outstanding. The Company's Articles of Association also contains a covenant that requires the Company to maintain a minimum common equity level of about $3.3 million as long as any Preferred Stock is outstanding.
NOTE 8 - PREFERRED STOCK
The Company's preferred and preference stock consisted of the following (in thousands):
|
200 5 |
2004 |
|
|
Cumulative Preferred and Preference Stock Non-redeemable 4.15% Series; 37,856 shares 4.65% Series; 10,000 shares 4.75% Series; 17,682 shares 5.375% Series; 15,000 shares Redeemable 8.30% Series; 60,000 shares Preferred stock, $25 par value, authorized 1,000,000 shares, none outstanding Preference stock, $1 par value, authorized 1,000,000 shares, none outstanding Less current portion of redeemable preferred Total cumulative preferred and preference stock |
|
|
The Company's non-redeemable and mandatorily redeemable preferred stock are part of one class of Preferred Stock, $100 Par Value, and are of equal rank. Each series is entitled to a liquidation preference, over the holders of common stock, equal to Par Value, plus accrued and unpaid dividends, and a premium if liquidation is voluntary. In general, there are no "deemed" liquidation events. Holders of the Preferred Stock have no voting rights, except as required by Vermont law, and except that if accrued dividends on any shares of Preferred Stock have not been paid for more than two full quarters, each share will have the same voting power as Common Stock, and if accrued dividends have not been paid for four or more full quarters, the holders of the Preferred Stock have the right to elect a majority of the Company's Board of Directors.
All series of Preferred Stock are currently subject to redemption and retirement at the option of the Company upon vote of at least three-quarters of its Board of Directors in accordance with the specific terms for each series and upon payment of the Par Value, accrued dividends and a premium to which each would be entitled in the event of voluntary liquidation, dissolution or winding up of the affairs of the Company. There are no preferred stock dividend arrearages. At December 31, 2005, premiums payable on each series of preferred stock if such an event were to occur are as follows:
|
Cumulative Preferred and Preference Stock |
Premiums Per Share |
|
4.150% Series |
$5.500 |
The 8.30 percent Series Preferred Stock is redeemable at par through a mandatory sinking fund in the amount of $1.0 million per annum. The Company, at its option, may also redeem at par an additional non-cumulative $1.0 million per annum. In the fourth quarters of 2005 and 2004, the Company paid its Transfer Agent $2.0 million for the mandatory and optional sinking fund payments, and the payments were effective January 1, 2006, and January 1, 2005, respectively. These payments are included in Special Deposits on the Consolidated Balance Sheets. Also see Note 7 - Long-Term Debt for discussion of dividend and optional stock redemption restrictions.
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NOTE 9 - STOCK AWARD PLANS
The Company has awarded stock options to key employees and non-employee directors under the plans shown in the table below. The 2002 Long-Term Incentive Plan also authorizes the granting of stock appreciation rights, restricted shares and performance shares. Options are granted at the fair market value of the common shares on the date of grant. The maximum term of an option may not exceed five years for non-employee directors and 10 years for key employees. Summarized information regarding stock award plans at December 31, 2005 follows:
|
|
Authorized |
Stock options outstanding |
Shares |
|
1988 Stock Option Plan - Key Employees |
334,375 |
12,000 - 176,249 |
- |
Stock option activity during the past three years was as follows:
|
|
Weighted Average Exercise Price |
|
Weighted Average Exercise Price |
|
Weighted Average Exercise Price |
|
|
Options outstanding at January 1 |
596,650 652,321 |
$16.4006 |
498,750 |
$15.0370 |
571,285 |
$14.5424 |
|
Weighted Average |
|||
|
Range of |
|
Remaining Contractual Life (Years) |
|
|
$10.4495 - $12.2579 |
122,660 |
3.1 |
$10.7619 |
The stock options granted during 2005 had a weighted-average grant date fair value of $3.55, compared to $2.82 in 2004 and $2.25 in 2003. The fair value was estimated using the Black-Scholes model, with the weighted-average assumptions shown in the table below.
|
December 31, |
|||
|
2005 |
2004 |
2003 |
|
|
Volatility |
.2582 |
.2551 |
.2204 |
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Restricted Stock Plans The Company has restricted stock plans in which common stock is granted to its directors and certain executive officers, key employees and non-employee directors. Recipients are not required to provide consideration to the Company under these plans, other than rendering service, and have the right to vote the shares and to receive dividends under the plans. The Company accounts for these stock plans under APB 25 in 2005.
Under the 1997 Restricted Stock Plan and 2002 Long-Term Incentive Plan, the total market value of the shares, at grant date, is treated as deferred compensation and charged to expense over the applicable vesting period. Interim estimates of compensation expense are recorded at the end of each reporting period based on a combination of the then-fair market value of the stock and the extent or degree of compliance with the performance criteria. Restricted stock issued for the board of director's retainers vests immediately. Restricted stock expense was $230,046 in 2005, $135,382 in 2004 and $136,538 in 2003. Restricted shares issued during the past three years, excluding shares issued for the performance plans described below, were as follows:
|
December 31, |
|||
|
2005 |
2004 |
2003 |
|
|
Granted |
11,170 |
4,987 |
5,017 |
As part of the Company's Long-Term Incentive Plan, restricted performance shares of common stock have been awarded to executive officers at the start of each year under the Performance Share Plans ("Performance Plans") beginning with the 1999 three-year performance cycle. These awards vary from zero to two times the number of conditionally granted shares based on the Company achieving certain financial goals over three-year performance cycles. Beginning with the 2005 cycle, certain operational performance measures were also added to the performance measures. The total market value of the shares is treated as deferred compensation and charged to expense on a quarterly basis over the respective performance cycles based on changes in market value, achievement of financial goals and changes in employment. Performance Plan stock compensation charged to expense in 2005 was a credit of $123,168 reflecting the reversal of amounts previously expensed because targeted financial goals were not achieved. Performance stock compensation charged to expense in 2004 was $164,832 and $834,469 in 2003. Performance Plan activity during the past three years was as follows:
|
December 31, |
|||
|
2005 |
2004 |
2003 |
|
|
Performance awards allocated at January 1 (a) |
33,601 |
118,055 |
153,969 |
|
(a) Represents all awards eligible for future payout on active three-year performance |
|||
|
(b) Represents shares issued at end of three-year performance cycle, net of shares withheld |
|||
NOTE 10 - PENSION AND POSTRETIREMENT BENEFITS
The Company has a qualified, non-contributory, defined-benefit, trusteed pension plan ("Pension Plan") covering all employees (union and non-union). Under the terms of the Pension Plan, employees are vested after completing five years of service, and can retire when they are at least age 55 with a minimum of 10 years of service. They are
Page 102 of 153
eligible to receive monthly benefits or a lump sum amount. The Company's funding policy is to contribute at least a statutory minimum to a trust. The Company is not required by its union contract to contribute to multi-employer plans. At the end of 2005, the Company adopted the RP-2000 mortality table that replaced the GAM 94 table.
The Company also sponsors a defined-benefit postretirement medical plan that covers all employees who retire with 10 or more years of service after age 45 and are at least age 55. The Company funds this obligation through a Voluntary Employees' Benefit Association and 401(h) Subaccount in its Pension Plan. Pre-65 retirees participate in plan options similar to active employees. Post-65 retirees receive limited coverage with a $10,000 annual individual maximum. Retiree contributions for Post-1995 retirees are 100 percent of the increase in the cost over 1995 levels and there are no retiree contributions for Pre-1996 retirees.
The Company records pension and other postretirement benefit costs in accordance with SFAS No. 87, Employers' Accounting for Pensions, and SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. Also, the Company follows SFAS No. 132, Employers' Disclosures about Pensions and other Postretirement Benefits. The Company's pension and postretirement benefit obligations and plan assets are valued annually as of a September 30 measurement date.
Benefit Obligation and Plan Assets
The changes in benefit obligation and Plan assets were as follows
|
At December 31 |
||||
|
Pension Benefits |
Postretirement Benefits |
|||
|
Change in Benefit Obligation Service cost Interest cost Plan participants' contributions Amendments Actuarial loss (gain) Benefits paid Projected obligation as of measurement date (September 30) Accumulated obligation as of measurement date (September 30) |
2005 3,227 5,856 - - 4,713 (5,896) $104,250 $84,415 |
2004 3,021 5,551 - 89 1,824 (5,640) $96,350 $78,708 |
2005 512 1,444 504 - 5,829 (2,480) $30,300 - |
2004 539 1,554 376 - (1,947) (2,296) $24,491 - |
|
The reduction in the Company's accumulated postretirement benefit obligation due to the impact of the Medicare |
||||
The present value of future Postretirement Plan participants' contributions was $30.7 million for 2005 and $26.3 million for 2004.
Benefit Obligation Assumptions Weighted-average assumptions used to determine benefit obligations at measurement date (September 30) are shown in the table that follows. The selection methodology used in determining discount rates includes portfolios of "Aa" bonds; all are United States issues and non-callable (or callable with make-whole features) and are at least $50 million. As of September 30, 2005, the discount rate was changed from 6 percent to 5.65 percent. The 2005 weighted-average assumptions for pension and postretirement benefits were used in determining the Company's related liabilities at December 31, 2005. Similarly, the 2004 weighted-average assumptions were used in determining liabilities at December 31, 2004.
|
Pension Benefits |
Postretirement Benefits |
|||
|
2005 |
2004 |
2005 |
2004 |
|
|
Discount rates |
5.65% |
6.00% |
5.65% |
6.00% |
For measurement purposes, an 11.5 percent annual rate of increase in the per capita cost of covered health care benefits was assumed for fiscal 2006, for pre-65 and post-65 claims costs. The rate is assumed to decrease 1 percent in each of the subsequent years until the ultimate trend of 5.5 percent is reached.
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Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect (in thousands):
|
1-Percentage |
1-Percentage |
|
|
Effect on postretirement benefit obligation as of September 30, 2005 |
$2,533 |
$(2,136) |
Asset Allocation
The asset allocations at the measurement date for 2005 and 2004, and the target allocation for 2006, by asset category, are as follows (in thousands):
|
Asset Category |
Pension Plan |
Postretirement Benefits |
||||
|
2006 Target |
2005 |
2004 |
2006 Target |
2005 |
2004 |
|
|
Equity securities |
67.0% |
68.8% |
66.7% |
67.0% |
- |
- |
Investment Strategy The Company's pension investment policy seeks to achieve sufficient growth to enable the Pension Plan to meet its future benefit obligations to participants, to maintain certain funded ratios and minimize near-term cost volatility. Current guidelines specify generally that 67 percent of plan assets be invested in equity securities and 33 percent of plan assets be invested in debt securities. The asset allocation mix is being reassessed in 2006.
The Company's postretirement investment policy seeks to achieve sufficient funding levels to meet future benefit obligations to participants and minimize near-term cost volatility. During 2005, the plan assets were invested in cash equivalents. The Company plans to adopt an asset allocation mix in 2006 similar to its Pension Plan assets.
Plan Assets
The changes in Plan assets are shown below (in thousands):
|
Pension Plan |
Postretirement Benefits |
||||
|
Change in Plan Assets Actual return on plan assets Employer contributions* Plan participants' contributions Benefits paid* Fair value of assets as of measurement date (September 30) * Includes benefits paid from employer assets |
2005 8,787 3,380 - (5,896) $67,784 - |
2004 6,722 1,127 - (5,640) $61,513 - |
2005 91 3,416 504 (2,480) $6,174 $1,976 |
2004 $4,230 4 2,329 376 (2,296) $4,643 $1,920 |
|
Fair Value The fair value of Pension Plan assets was $67,784,150 at the measurement date for 2005 and $61,513,357 at the measurement date for 2004, while the expected long-term rate of return was 8.25 percent for 2005 and 2004.
The fair value of postretirement benefit assets was $6,173,737 at the measurement date for 2005 and $4,643,339 at the measurement date for 2004, while the expected long-term rate of return was 8.25 percent for 2005 and 2004.
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Funded Status
The Plans' funded status was as follows (in thousands):
|
Pension Plan |
Postretirement Plan |
|||
|
Reconciliation of funded status |
2005 |
2004 |
2005 |
2004 |
|
Fair value of assets |
$67,784 |
$61,513 |
$6,174 |
$4,643 |
The amounts recognized in the Company's Consolidated Balance Sheets consisted of (in thousands):
|
Pension Plan |
Postretirement Plan |
|||
|
2005 |
2004 |
2005 |
2004 |
|
|
Accrued benefit liability |
$(15,665) |
$(14,631) |
$(3,500) |
$(3,773) |
Net Periodic Benefit Costs
Components of net periodic benefit costs were as follows (in thousands):
|
Pension Benefits |
Postretirement Benefits |
|||||
|
2005 |
2004 |
2003 |
2005 |
2004 |
2003 |
|
|
Net benefit costs include the following components Service cost Interest cost Expected return on plan assets Amortization of prior service cost Recognized net actuarial loss Amortization of transition (asset) obligation Net periodic benefit cost Less amount allocated to other accounts Net benefit costs expensed |
|
|
|
|
|
|
Benefit Cost Assumptions Weighted-average assumptions used to determine net periodic costs at measurement date (September 30) are shown in the table below. The weighted-average assumptions shown for 2005, which were set at September 30, 2004, were used in determining 2005 expense. Likewise, the 2004 and 2003 weighted-average assumptions were used in determining 2004 and 2003 expense, respectively.
|
Pension Benefits |
Postretirement Benefits |
|||||
|
2005 |
2004 |
2003 |
2005 |
2004 |
2003 |
|
|
Weighted-average discount rates |
6.00% |
6.00% |
6.50% |
6.00% |
6.00% |
6.50% |
Expected Rate of Return on Plan Assets
The Company expects an annual long-term return for the pension asset portfolio of 8.25 percent, based on a representative allocation within the target asset allocation described above. In formulating this assumed rate of return, the Company considered historical returns by asset category and expectations for future returns by asset category based, in part, on simulated capital market performance over the next 10 years.
The Pension Plan assets earned a rate of return for the Plan years ended September 30, of 15.6 percent for 2005, 12.3 percent for 2004 and 18.5 percent for 2003.
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Based on the postretirement investment policy described above, the Company expects an annual long-term return for the postretirement portfolio of 8.25 percent. In formulating this assumed long-term rate of return, asset categories and expectations for future returns by asset category were considered.
Pension and postretirement benefit expenses for 2005 were based on an expected long-term return on assets rate of 8.25 percent. The same percentage will be used to determine the 2006 expenses.
Pension Equity Adjustment Risk
Certain negative scenarios and unfavorable market conditions (asset returns are lower than expected, reductions in discount rates, and liability experience losses) may cause the Pension Plan's accumulated benefit obligation ("ABO") to exceed the fair value of Pension Plan assets as of the measurement date and would result in an unfunded minimum liability. If that occurs and the minimum liability exceeds the accrued benefit cost, an additional minimum pension liability may be required to be recorded, net of tax, as a non-cash charge to other comprehensive income, included in common stock equity on the balance sheet. The ABO represents the present value of benefits earned without considering future salary increases. The Company did not have a reduction in equity for the qualified Pension Plan for the year ended December 31, 2005 since the intangible asset, representing prior service costs and transition obligation, offset the additional minimum pension liability. Based on actual asset returns through December 31, 2005 and assuming all assumptions are met for the remainder of the measurement period through September 30, 2006, the Company does not anticipate a reduction in equity for the year ending December 31, 2006.
The Pension Plan currently meets the minimum funding requirements of the Employee Retirement Income Security Act of 1974. In 2005, the Company was required to contribute $3.4 million to the Pension Plan and will have funding requirements of $4.9 million in 2006. In March 2006, the Company contributed an additional $12.2 million to the Pension trust fund and an additional $4.1 million to the Postretirement trust funds. The Company may also consider making additional contributions to the Pension and Postretirement trust funds in the third and fourth quarters of 2006.
Expected Cash Flows
The table below reflects the total benefits expected to be paid from the external Pension Plan trust fund or from the Company's assets, including both the Company's share of the pension and postretirement benefit costs and the participants' share of the postretirement benefit cost funded by participant contributions. Of the benefits expected to be paid in 2006, about $5.1 million will be paid from the Pension Plan trust fund and about $1.9 million related to postretirement benefits will be paid from the Company's assets. Expected contributions reflect amounts expected to be contributed to funded plans. Information about the expected cash flows for the Pension Plan and postretirement benefit plans is as follows (in millions):
|
Pension Benefits |
Postretirement Benefits |
|
|
Employer Contributions Expected Benefit Payments 2006 2007 2008 2009 2010 2011 - 2015 |
|
|
As of October 1, 2005, the Medicare Part D subsidy reduced the postretirement benefit obligation by $2.0 million and reduced the 2005 net periodic benefit cost by 0.3 million. The expected Medicare Part D subsidy included in the expected gross postretirement benefit payments amounts to about $0.2 million for each of the years 2006 through 2015.
Page 106 of 153
O
therNOTE 11 - INCOME TAXES
The Company's income tax provision (benefit) from continuing operations consisted of the following (in thousands):
|
For the years ended December 31 |
|||
|
2005 2004 2003 |
|||
|
Federal: |
|
|
|
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The reconciliation between income taxes computed by applying the U.S. federal statutory rate and the reported income tax provision (benefit) from continuing operations follows (in thousands):
|
For the years ended December 31 |
|||
|
2005 |
2004 |
2003 |
|
|
(Loss) income before income tax |
$(672) |
$9,561 |
$27,279 |
During 2004, the Company received income tax refunds totaling $0.9 million (exclusive of interest). One refund related to an appeal of an overpayment from a prior federal income tax audit for the tax years 1982 through 1984. The proceeds from the settlement included a federal income tax refund of $0.5 million. The others were related to an appeal of federal and state income tax overpayments for 2000. The proceeds from these settlements included a federal income tax refund of $0.3 million and a state refund of $0.1 million.
The Company decreased its estimate for tax contingencies by $0.7 million in 2005 and $0.6 million in 2004 due to a reduction in potential tax liabilities.
Valuation Allowances: SFAS No. 109 prohibits the recognition of all or a portion of deferred income tax benefits if it is more likely than not that the deferred tax asset will not be realized. For the periods ended 2005 and 2004, there were no valuation allowances recorded.
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2005 and 2004 are presented below (in thousands):
|
2005 2004 |
||
|
Deferred tax assets - current Other accruals |
499 |
|
|
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||
|
Deferred tax assets - long term |
40,123 1,544 468 4,135 1,888 964 49,122 28,647 $25,448 |
|
On June 7, 2004, the State of Vermont enacted legislation that reduced the state income tax rate from 9.75 percent to 8.9 percent effective January 1, 2006, and from 8.9 percent to 8.5 percent effective January 1, 2007. Deferred tax assets and liabilities were adjusted in 2004 to reflect the enacted income tax rate change. This rate change reduced regulatory tax assets by about $1.4 million, and increased income tax expense by about $0.2 million. Book and tax differences have to be estimated due to the fact that the tax rate changes occur after 2004 and over a two-year period.
NOTE 12 - RETAIL RATES
The Company recognizes adequate and timely rate relief is required to maintain its financial strength, particularly since Vermont law does not allow purchased power and fuel costs to be passed on to consumers through purchased power and fuel adjustment clauses. The Company will continue to review costs and request rate increases when warranted.
On April 7, 2004, the PSB issued an order to investigate the Company's retail rates. On July 15, 2004, the Company filed a cost of service study pursuant to the rate investigation, and filed a separate request for a 5.01 percent rate increase, effective April 1, 2005. The Company also requested that the two cases be consolidated; that request was later approved by the PSB. In October 2004, both the DPS and AARP, interveners in the case, filed testimony with the PSB. Technical hearings with the PSB began in early November 2004, and hearings and filings continued through February 2005.
On February 18, 2005, the PSB approved the Company's request for an Accounting Order that allowed for deferral of 2004 utility earnings in excess of an 11 percent return on equity. Per the Accounting Order, the Company reduced 2004 utility earnings by about $2.3 million after-tax to achieve the 11 percent, and recorded an offsetting pre-tax regulatory liability of $3.8 million to be used or accounted for as the PSB determined in its final order.
On March 29, 2005, the PSB issued its Order ("Rate Order") on the rate investigation and the Company's request for a rate increase. The PSB concluded that the Company's rates were higher than was just and reasonable, and must be reduced. In the Rate Order, the PSB determined the annual revenue requirement for the period beginning April 1, 2004, established rates retroactive to April 7, 2004 and established new rates beginning April 1, 2005. The Rate Order included, among other things, the following: 1) a 1.88 percent rate reduction beginning April 1, 2005; 2) a $3.3 million refund to customers, 3) a 10 percent return on equity (reduced from 11 percent); and 4) a requirement that the gain resulting from termination of the power contract related to the 2004 Connecticut Valley sale be applied to the benefit of ratepayers to compensate for increased costs. The Company was also required to file a compliance
Page 109 of 153
filing by April 1, 2005, which it did, and file a new rate design within 90 days of the Rate Order. The Company filed a new rate design on August 29, 2005, based on the PSB's approval for an extension on the filing date.
The PSB finalized the rate refund and rate reduction amounts in its April 4, 2005 Compliance Order. The rate refund amounted to about $6.5 million pre-tax and the rate reduction amounted to 2.75 percent ($7.2 million pre-tax on an annual basis).
For accounting purposes, the Rate Order resulted in a $21.8 million pre-tax unfavorable effect on utility earnings in the first quarter of 2005. The primary components of the charge to earnings included: 1) a revised calculation of overearnings for the period 2001 - 2003; 2) application of the gain resulting from termination of the power contract with Connecticut Valley to reduce costs; 3) a customer refund for over-collections for the period April 7, 2004 through March 31, 2005; and 4) amortization of costs and other adjustments required in the Rate Order. These are described in more detail under the caption 2005 Rate Order below.
On April 12, 2005, the Company filed with the PSB a Request for Reconsideration of the Rate Order. Specific items for reconsideration included: 1) treatment of the costs and benefits associated with the January 1, 2004 Connecticut Valley sale; 2) the 10 percent return on equity; and 3) various other matters for clarification.
On April 12, 2005, the DPS filed with the PSB a Motion for Reconsideration of the Rate Order. Specific items for reconsideration included: 1) treatment of costs formerly recovered by the Company through a service contract with Connecticut Valley; and 2) certain adjustments related to the calculation of overearnings for 2001 - 2003.
The Company, DPS and AARP submitted their responses to these motions by April 26, 2005 as required by the PSB. On May 25, 2005, the PSB issued its Order on both Motions for Reconsideration. All requests to modify the Rate Order were denied with the exception of a minor modification to one sentence in the Rate Order, and a request for the Company to inform the PSB and other parties on its treatment of construction work in process in the overearnings calculation. That matter has been resolved.
On June 22, 2005, the Company filed an appeal of portions of the Rate Order with the Vermont Supreme Court. On July 11, 2005, the Company filed a docketing statement with the court in which it outlined the issues in its case. The docketing statement describes the ordered payback of earnings from periods prior to the opening of the rate investigation, namely the years 2001 to 2003 and also the first quarter of 2004, when the Company recorded a gain from the Connecticut Valley sale. The issues that were raised on appeal primarily focus on whether the Rate Order set rates retroactively without statutory authorization. On July 27, 2005, the DPS filed a response opposing the Company's position. The Company filed its legal brief and other materials in the case on August 22, 2005. Expedited oral argument occurred on January 31, 2006. The Company expects a Vermont Supreme Court decision on the case in the second or third quarter of 2006. The Company is not able to predict the outcome of this matter at this time.
The Company's August 29, 2005 rate design proposal that it filed in compliance with the Rate Order maintains the Company's overall revenue requirement approved in the Rate Order, but modestly reallocates rate class revenue between some rate classes. Several Vermont ski areas have intervened, and the Company will participated in workshops to seek a settlement with all parties. If settlement discussions are not successful, a schedule for hearings will be determined.
2005 Rate Order The table below reflects the impact of the first-quarter 2005 Rate Order charge to earnings on specific line items of the Consolidated Statement of Income on a pre-tax basis (in millions).
|
Income Statement Line Item Purchased Power (#4 below) Other Operation (#1, 2, 3 and 4 below) Other Income (#4 below) Other Deductions (#4 below) Other Interest (#1, 3 and 4 below) Total Rate Order Impact |
|
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The primary components of the charge to earnings include: 1) a revised calculation of overearnings for the period 2001 - 2003; 2) application of the gain resulting from termination of the power contract with Connecticut Valley to reduce costs; 3) a customer refund for over-collections for the period April 7, 2004 through March 31, 2005; and 4) amortization of costs and other adjustments required in the Rate Order. These are described in more detail below (all on a pre-tax basis).
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Also see Note 4 - Regulatory Assets, Deferred Charges and Deferred Credits.
NOTE 13 - COMMITMENTS AND CONTINGENCIES
Nuclear Investments The Company has a 2 percent equity ownership in Maine Yankee, 2 percent equity ownership in Connecticut Yankee and 3.5 percent equity ownership in Yankee Atomic, all of which are permanently shut down and are currently conducting decommissioning activities. The Company is responsible for paying its equity ownership percentage of decommissioning costs for all three plants. See Note 2 - Investments in Affiliates for additional information. The Company is also responsible for its 1.7303 joint-ownership percentage of decommissioning costs for Millstone Unit #3 as explained in Joint-ownership below.
Nuclear Insurance The Price-Anderson Act ("Act") currently limits public liability from a single incident at a nuclear power plant to about $10 billion. The Act has been renewed five times since it was first enacted in 1957, and expired in August 2003. The Energy Policy Act of 2005, enacted in August 2005, extends the Act for 20 years and provides a framework for immediate, no-fault insurance coverage for the public in the event of a nuclear reactor accident. The Act consists of two levels of coverage. The primary level provides liability insurance coverage of $300 million. If this amount is not sufficient to cover claims arising from an accident, the second level, referred to as secondary financial protection, applies. For the second level, each nuclear plant must pay a retrospective premium equal to its proportionate share of the excess loss, up to a maximum of $95.8 million per reactor per incident, limited to a maximum annual assessment of $15 million. These assessments will be adjusted for inflation. Currently, based on its joint-ownership interest in Millstone Unit #3, the Company could become liable for about $0.3 million of such maximum assessment per incident per year. The Maine Yankee, Connecticut Yankee and Yankee Atomic plants have received exemptions from participating in the secondary financial protection program under the Act.
Vermont Yankee The Company has a 35 percent entitlement in Vermont Yankee plant output sold by Entergy Nuclear Vermont Yankee, LLC ("ENVY") to VYNPC, through a long-term power purchase contract ("PPA") with VYNPC. One remaining secondary purchaser continues to receive a small percentage of the Company's entitlement, reducing its entitlement to about 34.83 percent. ENVY has no obligation to supply energy to VYNPC over the amount the plant is producing, so entitlement holders receive reduced amounts when the plant is operating at a reduced level, and no energy when the plant is not operating. The plant normally shuts down for about one month every 18 months for maintenance and to insert new fuel into the reactor. A summary of the Company's estimated purchases under the PPA follows:
|
Estimated Average |
||
|
2005 |
2006 - 2012 |
|
|
Average capacity acquired |
180 MW |
182 MW |
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In 2005, purchases amounted to about $57.3 million based on the Company's entitlement share of plant output. Future purchases are expected to be $60.9 million in 2006, $58.1 million in 2007, $59.1 million in 2008, $65.3 million in 2009 and $61.9 million in 2010.
The plant's last scheduled refueling outage began on October 22, 2005 and was originally expected to end about November 20 but it resumed production on November 10, 2005 followed by a three day ramp-up to full power. Prior to the outage, the Company purchased forward supplies of replacement energy at a fixed price of about $115 per mWh for the expected outage duration to minimize exposure to spot market energy price volatility. The price for replacement power was significantly higher than what is currently being recovered in retail rates. The net cost of incremental replacement power amounted to about $5.4 million. On December 23, 2005, the Company filed a request for an Accounting Order from the PSB to defer $4.7 million of the net incremental replacement power costs for recovery in its next rate proceeding, representing the incremental amount above those already embedded in current retail rates. The Company's request also included approval to apply the $1.1 million credit it received through VYNPC power bills in 2005 to reduce the deferral. If the PSB approves the Company's request, the result would be a net deferral of $3.6 million for recovery in its next rate proceeding.
On March 6, 2006, the DPS asked the PSB to deny the Company's request for an Accounting Order, and recommended that the $1.1 million credit and unrelated savings due to increased deliveries under the Hydro-Quebec contract as described below be recorded as regulatory liabilities for return to ratepayers. Due to settlement discussions with the DPS and other timing issues, the PSB has deferred ruling on the Company's request or on the DPS recommendations. Absent an approved Accounting Order, recovery of these costs is uncertain, so the Company was not able to defer the $4.7 million of net costs or offset them with the $1.1 million credit that is currently recorded as a deferred credit on the Consolidated Balance Sheet. Therefore, the purchases of replacement power are included in purchased power expense and related resale sales are included in operating revenue on the Consolidated Statement of Income.
In March 2004, the PSB approved ENVY's request to increase generation at the Vermont Yankee plant by 110 megawatts. The PSB's approval included a condition that ENVY provide outage protection indemnification ("Ratepayer Protection Proposal" or "RPP") for times the uprate causes reductions in output that reduce the value of the PPA. The Company's maximum right to indemnification under the RPP is about $2.8 million for the three-year period beginning in May 2004 and ending after completion of the uprate (or a maximum of three years).
Plant output has been reduced since the April 2004 scheduled refueling outage, and will continue until ENVY receives NRC approval for the uprate. The Company's entitlement was reduced by an average of about 4 MW during this period. The financial effect of such a reduction will be covered under the terms of the RPP. Additionally, the Company has sought recovery from ENVY, under the RPP, for incremental replacement energy costs incurred when the plant was shut down for 19 days beginning in mid-June 2004. The Company believes the plant went off line due to problems associated with uprate-related improvements made by ENVY, and sought about $0.8 million from ENVY. ENVY contends that the problem would have occurred regardless of the uprate. Having failed to reach a settlement with ENVY, the Company petitioned the PSB for resolution.
There are risks that may not be covered under the RPP. After the Vermont Yankee plant uprating is complete, the Company's percentage of energy output under the PPA would decline proportionately such that we would receive the same quantity of energy from the plant. Four other nuclear plants with steam dryers similar to Vermont Yankee's have experienced problems, and all were required to return to their pre-uprate power level until the problems were corrected. If such a problem were to occur with the Vermont Yankee plant's uprate, it is possible that under the PPA, the Company's entitlement to plant output could be reduced proportionately to the derating until operation is permitted at the post-uprate MW level. While this risk is mitigated in part by additional, controlled testing, during the process of increasing power output, under the supervision of the NRC and DPS, the Company estimates that this could have a material adverse effect on net power costs.
The NRC gave final approval to the uprate on March 2, 2006. If the uprate were to be ultimately unsuccessful, it is also possible that the plant could be shut down earlier than its current licensed life. Any material reduction in output that is not compensated under the terms of the RPP or otherwise by ENVY could have a material impact on the Company's financial position and results of operations, if those increased costs are not recovered in retail rates in a timely fashion.
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On March 16, 2006, the Company, Green Mountain Power, ENVY and the DPS filed a settlement with the PSB resolving all issues raised in the petition before the PSB, plus the related derate issue described above. The settlement would resolve all issues through February 28, 2006. The Company's share of the settlement is estimated to be about $1.6 million including $0.7 million related to the June 2004 outage described above and the remaining for uprate-related costs. Pursuant to the Rate Order, any partial or full reimbursement received by the Company from ENVY under the RPP shall be recorded as a regulatory liability for return to ratepayers in the Company's next rate proceeding. The settlement is not effective until the PSB issues a final order. The Company cannot predict the timing or outcome of this matter at this time.
In April 2004, ENVY reported that two short spent fuel rod segments were not in what ENVY believed to be their documented location in the spent fuel pool. Subsequently, ENVY's continuing documentation review led to the discovery of the fuel rod segments in a container in the spent fuel pool. During that time, ENVY notified VYNPC that based on the terms of the Purchase and Sale Agreement dated August 1, 2001, and facts at the time, it was their view that costs associated with the spent fuel rod segment inspection effort were the responsibility of VYNPC. VYNPC responded that based on the information at the time there was no basis for ENVY's claim. While this has not been fully resolved with ENVY, Management does not believe that the Company has any potential liability related to this matter.
ENVY has announced that, under current operating parameters, it will exhaust the capacity of its nuclear waste (spent fuel) storage pool in 2007 or 2008 and will need to store nuclear waste in so-called 'dry cask storage' facilities to be constructed on the site. Construction and use of such dry cask storage facilities requires approval from the Vermont State Legislature, in addition to PSB approval. In early June 2005, the Vermont State Legislature passed a law authorizing ENVY to construct and use dry cask storage facilities on the site through its current license. In late June 2005, ENVY filed an application with the PSB for permission to install dry cask storage facilities at the site. At this time the PSB has not ruled on ENVY's application.
If the PSB does not approve dry cask storage, ENVY has announced that it could be required to shut down the Vermont Yankee plant in 2007 or 2008, instead of its current license life of 2012. If the Vermont Yankee plant is shut down, the Company would lose about 50 percent of its committed energy supply and would have to acquire replacement power resources comprising about 40 percent of its estimated power supply needs. Based on projected market prices, the value of the lost output is estimated to be about $55 million on an annual basis. Based on this estimate, the Company would require a retail rate increase of about 20 percent for full cost recovery. The Company is not able to predict whether there will be an early shutdown of the Vermont Yankee plant or whether the PSB will allow timely and full recovery of increased costs related to any such shutdown. The implications of an early shut down of the Vermont Yankee plant could have a material effect on the Company's financial position and future results of operations, if those costs are not recovered in retail rates in a timely fashion.
In January 2006, ENVY submitted a renewal application with the NRC for a 20-extension of the Vermont Yankee plant operating license. If approved it would allow the plant to operate until 2032. ENVY will also need approval from the PSB to keep operating beyond 2012. The Company's purchases under the PPA will end in 2012. The Vermont Legislature is considering legislation that would require its approval for any license extension at the plant.
Hydro-Quebec The Company is purchasing varying amounts of power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power Contract through 2016. The VJO includes a group of Vermont electric companies and municipal utilities, of which the Company is a participant. The VJO Power Contract has been in place since 1987 and purchases began in 1990. Related contracts were subsequently negotiated between the Company and Hydro-Quebec, which altered the terms and conditions contained in the original contract by reducing the overall power requirements and related costs.
There are specific contractual provisions that provide that in the event any VJO member fails to meet its obligation under the contract with Hydro-Quebec, the balance of the VJO participants, including the Company, will "step-up" to the defaulting party's share on a pro-rata basis. The VJO contract runs through 2020, but the Company's purchases related to the contract end in 2016. As of December 31, 2005, the Company's obligation is about 47 percent of the total VJO Power Contract through 2016, which translates to about $606 million, on a nominal basis. The average annual amount of capacity that the Company will purchase from January 1, 2006 through October 31, 2012 is about 144.7 MW, with lesser amounts purchased through October 31, 2016.
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In accordance with guidance set forth in FASB Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others ("FIN 45"), the Company is required to disclose the "maximum potential amount of future payments (undiscounted) the guarantor could be required to make under the guarantee." Such disclosure is required even if the likelihood is remote. In regards to the "step-up" provision in the VJO Power Contract, the Company must assume that all members of the VJO simultaneously default in order to estimate the "maximum potential" amount of future payments. The Company believes this is a highly unlikely scenario given that the majority of VJO members are regulated utilities with regulated cost recovery. Each VJO participant has received regulatory approval to recover the cost of this purchased power in their most recent rate applications. Despite the remote chance that such an event could occur, the Company estimates that its undiscounted purchase obligation would be about an additional $709 million for the remainder of the contract, assuming that all members of the VJO defaulted by January 1, 2006 and remained in default for the duration of the contract. In such a scenario, the Company would then own the power and could seek to recover its costs from the defaulting members or its retail customers, or resell the power in the wholesale power markets in New England. The range of outcomes (full cost recovery, potential loss or potential profit) would be highly dependent on Vermont regulation and wholesale market prices at the time.
In the early phase of the VJO Power Contract, two sellback contracts were negotiated, the first delaying the purchase of 25 MW of capacity and associated energy, the second reducing the net purchase of Hydro-Quebec power through 1996. In 1994, the Company negotiated a third sellback arrangement whereby it received a reduction in capacity costs from 1995 to 1999. In exchange for this sellback, Hydro-Quebec obtained two options. The first gives Hydro-Quebec the right upon four years written notice, to reduce capacity deliveries by 50 MW beginning as early as 2010, including the use of a like amount of the Company's Phase I/II transmission facility rights. The second gives Hydro-Quebec the right, upon one years written notice to curtail energy deliveries in a contract year (12 months beginning November 1) from an annual load factor of 75 to 50 percent due to adverse hydraulic conditions in Quebec. This second option can be exercised five times through October 2015.
The Company has assessed the third sellback arrangement under the requirements of SFAS No. 133, and determined that the first option is a derivative, but the second is not a derivative because it is contingent upon a physical variable. The year-end estimated fair value of the first option was an unrealized loss of $5.0 million in 2005 and an unrealized loss of $5.7 million in 2004.
Under the VJO Power Contract, the VJO can elect to change the annual load factor from 75 percent to between 70 and 80 percent five times through 2020, while Hydro-Quebec can elect to reduce the load factor to not less than 65 percent three times during the same period of time. Hydro-Quebec has used all of its elections, resulting in a 65 percent load factor obligation from November 1, 2002 to October 31, 2005. The VJO recently elected to purchase at an 80 percent load factor for the current contract year beginning November 1, 2005 and ending October 31, 2006. The VJO now have one load factor election remaining.
The Hydro-Quebec contracts are summarized in the table below, including average annual projections for the calendar years as shown (dollars in thousands, except per kWh amounts):
|
Estimated |
Estimated |
||
|
2005 |
2006 - 2012 |
2013 - 2016 |
|
|
Annual Capacity Acquired |
142.8MW |
144.0MW |
(a) |
|
(a) Annual capacity acquired is projected to be about 116 MW for 2013 through 2014 and 19 MW for 2016. |
|||
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Total purchases from Hydro Quebec were $58.4 million in 2005, $56.9 million in 2004 and $57.5 million in 2003. The Company's estimated cost of energy and capacity under the existing contracts with Hydro-Quebec, based on the load factors shown in the table above, are $64.2 million in 2006, $63.8 million in 2007, $62.8 million in 2008, $63.2 million in 2009 and $62.8 million in 2010.
Independent Power Producers The Company receives power from several Independent Power Producers ("IPPs"). These plants primarily use water and biomass as fuel. Most of the power comes through a state-appointed purchasing agent, VEPP Inc. ("VEPPI"), which assigns power to all Vermont utilities under PSB rules. In 2005, the Company received 160,396 mWh under these long-term contracts, about 86 percent related to VEPPI. Total IPP purchases accounted for 6.0 percent of the Company's total mWh purchased and 13.2 percent of purchased power costs. Total IPP purchases were $19.7 million in 2005, $20.3 million in 2004, and $19.1 million in 2003. Estimated purchases from IPPs are expected to be $18.5 million in 2006, $18.8 million in 2007, $19.1 million in 2008, $17.9 million in 2009 and $17.8 in 2010. These amounts reflect annual savings of about $0.4 million related to the IPP settlement described below.
Power costs associated with power purchases from IPPs have been reduced since mid 2003 based on the PSB's January 2003 final order approving a settlement reached by the Company, other parties and the DPS, to reduce such costs. The settlement was related to various legal proceedings and negotiations that began in 1999 to change the IPPs' contracts with VEPPI to reduce power costs for customers' benefit. Nominal cost savings to all Vermont utilities are estimated to be about $7.3 million between 2006 and 2020, exclusive of savings that might result from implementation of IPP contract buy downs through securitization. The Company's share is about 39 percent of the power savings credits under the settlement. VEPPI began passing along power cost savings to all Vermont utilities in June 2003 when all conditions of the settlement were met. The Company's share amounted to $0.4 million in 2005 and in 2004.
Performance Assurance At December 31, 2005, the Company had posted $19.1 million of collateral under performance assurance requirements for certain of its power contracts. These payments are included in Special Deposits on the Consolidated Balance Sheet. In the second quarter, the PSB provided interim approval to meet collateral requirements on power contracts, with the exception of ISO-New England collateral that had been previously approved. On October 21, 2005, the Company received final PSB approval to meet collateral requirements associated with power transactions. Performance assurance requirements are described in more detail below.
The Company is subject to performance assurance requirements associated with its power purchase and sale transactions through ISO-New England under the Financial Assurance Policy for NEPOOL members. The Company must post collateral if the net amount owed exceeds its credit limit at ISO-New England. A company's credit limit is calculated as a percentage, based on its credit rating, of its net worth. At the Company's previous credit rating of 'BBB-', the credit limit with ISO-New England was about $2.7 million. At the Company's current credit rating of 'BB+', the credit limit with ISO-New England is zero and the Company is required to post collateral for all net purchase transactions. ISO-New England reviews collateral requirements on a daily basis. As of December 31, 2005, the Company posted $2.4 million of collateral with ISO-New England.
The Company is currently selling power in the wholesale market pursuant to two third-party contracts covering periods through late 2006 and late 2008. Under both of these contracts, the Company is required to post collateral if its credit rating is downgraded below investment-grade status, but only if requested to do so by the counterparties. As of December 31, 2005, the Company posted $16.7 million of collateral related to one of the third-party contracts. This collateral requirement is reviewed on a weekly basis. At this time, the Company has not been requested to post collateral under the other third-party contract. If it had been, the additional collateral requirement would have amounted to about $12.4 million at December 31, 2005, based on estimates of forward market prices at that time.
The Company is also subject to performance assurance requirements under its Vermont Yankee power purchase contract (the 2001 Amendatory Agreement). If ENVY, the seller, has commercially reasonable grounds for insecurity regarding the Company's ability to pay for its monthly power purchases, ENVY may ask VYNPC and VYNPC may then ask the Company to provide adequate financial assurance of payment. In the fourth quarter of 2005, ENVY contacted the Company regarding its ability to pay for its power purchases. The Company responded and has not yet had to post collateral under this contract.
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Joint-ownership The Company's share of operating expenses for these facilities is included in the corresponding operating accounts on the Consolidated Statements of Income. Each participant in these facilities must provide for its financing. The Company's ownership interests in jointly owned generating and transmission facilities are set forth in the following table and are included in Net utility plant on the Company's Consolidated Balance Sheets (dollars in thousands):
|
|
|
In Service Date |
MW Entitlement |
December 31 |
||
|
Wyman #4 |
Oil |
1.7769% |
1978 |
10.8 |
$3,419 |
$3,385 |
Millstone Unit #3 As a joint owner of the Millstone Unit #3 facility, in which Dominion Nuclear Corporation ("DNC") is the lead owner with about 93.47 percent of the plant joint-ownership, the Company is responsible for its share of nuclear decommissioning costs. The Company has an external trust dedicated to funding its joint-ownership share of future decommissioning costs. DNC has suspended contributions to the Millstone Unit #3 Trust Fund because the minimum NRC funding requirements are being met or exceeded. The Company has also suspended contributions to the Trust Fund, but could choose to renew funding at its own discretion as long as the minimum requirement is met or exceeded. If a need for additional decommissioning funding is necessary, the Company will be obligated to resume contributions to the Trust Fund. See Note 6 - Financial Instruments and Investment Securities for more detail related to the Trust Fund and Note 1 - Summary of Significant Accounting Policies for discussion of asset retirement obligations.
In January 2004, DNC filed, on behalf of itself and the two minority owners, including the Company, a lawsuit against the DOE seeking recovery of costs related to storage of spent nuclear fuel arising from the failure of the DOE to comply with its obligations to commence accepting such fuel in 1998. The schedule for further proceedings in the lawsuit is not known at this time. Millstone Unit #3 spent fuel from the beginning of commercial operations in 1986 resides in the spent fuel pool. The Company continues to pay its share of the DOE Spent Fuel assessment expenses levied on actual generation and will share in recovery from the lawsuit, if any, in proportion to its ownership interest. On November 28, 2005, the NRC renewed the operating license for Millstone Unit #3 for an additional 20 years. This extends the licensed life from November 2025 to November 2045.
In the fourth quarter of 2005, Millstone Unit #3 performed its scheduled refueling outage that extended from September 29 until October 27. Based on approved regulatory accounting treatment, the Company defers the cost of incremental replacement energy and incremental maintenance costs of the scheduled refueling outage, and is allowed to amortize those costs through the next scheduled refueling outage, which typically spans over an 18-month period. The Company purchased replacement power through ISO-New England during the outage period. The Company deferred about $1.4 million for incremental replacement power costs and $0.5 million for incremental maintenance costs related to the scheduled refueling outage.
Environmental Over the years, more than 100 companies have merged into or been acquired by the Company. At least two of the companies used coal to produce gas for retail sale. This practice ended more than 50 years ago. Gas manufacturers, their predecessors and the Company used waste disposal methods that were legal and acceptable then, but may not meet modern environmental standards and could represent a liability.
Some operations and activities are inspected and supervised by federal and state authorities, including the Environmental Protection Agency. The Company believes that it is in compliance with all laws and regulations and has implemented procedures and controls to assess and assure compliance. Corrective action is taken when necessary. Below is a brief discussion of known material issues.
Cleveland Avenue Property The Cleveland Avenue property in Rutland, Vermont, was used by a predecessor to make gas from coal. Later, the Company sited various operations there. Due to coal tar deposits, Polychlorinated Biphenyl contamination and potential off-site migration, the Company conducted studies in the
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late 1980s and early 1990s to quantify the situation. Investigation has continued, and the Company is working with the State of Vermont to develop a mutually acceptable solution.
Brattleboro Manufactured Gas Facility In the 1940s, the Company owned and operated a manufactured gas facility in Brattleboro, Vermont. The Company ordered a site assessment in 1999 at the request of the State of New Hampshire. In 2001, New Hampshire said no further action was required, though it reserved the right to require further investigation or remedial measures. In 2002, the Vermont Agency of Natural Resources notified the Company that its corrective action plan for the site was approved. That plan is now in place.
Dover, New Hampshire, Manufactured Gas Facility In 1999, Public Service Company of New Hampshire ("PSNH") contacted the Company about this site. PSNH alleged that the Company was partially liable for cleanup, since the site was previously operated by Twin State Gas and Electric, which merged into the Company the same day that PSNH bought the facility. In 2002, the Company reached a settlement with PSNH in which certain liabilities it might have had were assigned to PSNH in return for a cash settlement paid by the Company based on completion of PSNH's cleanup effort. The Company's remaining obligation related to this settlement is less than $0.1 million.
As of December 31, 2005, a $5.4 million reserve for environmental matters is recorded on the Consolidated Balance Sheet. At December 31, 2004, the reserve was $6.1 million. The reserve represents Management's best estimate of the cost to remedy issues at these sites based on available information ranging from a high of $7.6 million to a low of $4.5 million. There is no pending or threatened litigation regarding other sites with the potential to cause material expense. No government agency has sought funds from the Company for any other study or remediation.
Leases and support agreements
Capital Leases: The Company participated with other electric utilities in the construction of the Phase I Hydro-Quebec interconnection transmission facilities in northeastern Vermont, which were completed at a total cost of about $140 million. Under a support agreement relating to participation in the facilities, the Company is obligated to pay its 4.55 percent share of Phase I Hydro-Quebec capital costs over a 20-year recovery period ending in 2006. The Company also participated in the construction of Phase II Hydro-Quebec transmission facilities constructed throughout New England, which were completed at a total cost of about $487 million. Under a similar support agreement, the New England participants, including the Company, contracted to pay their proportionate share of the total cost of constructing, owning and operating the Phase II facilities, including capital costs. The Company is obligated to pay its 5.132 percent share of Phase II Hydro-Quebec capital costs over a 25-year recovery period ending in 2015. These agreements meet the capital lease accounting requirements under SFAS No. 13, Accounting for Leases. All costs under these agreements are recorded as purchased transmission expense in accordance with the Company's ratemaking policies. Future expected payments will range from about $3.2 million to $2.7 million annually from 2006 through 2015 and will decline thereafter. Approximately $0.6 million of the annual costs are reimbursed to the Company pursuant to the New England Power Pool Open Access Transmission Tariff.
For the year ended December 31, 2005, imputed interest on capital leases totaled $0.7 million. The following table summarizes the minimum lease payments associated with the Phase I and Phase II Hydro-Quebec arrangements and other capital leases at December 31, 2005:
|
(in thousands) |
|
|
Year |
Capital Leases |
|
2006 |
$1,515 |
Operating Leases: The Company leases its vehicles and related equipment under one operating lease agreement. The leases are mutually cancelable one year from each individual lease inception. The Company has the ability to lease vehicles and related equipment up to an aggregate unamortized balance of $10 million, of which about $6.3 million and $4.4 million was outstanding for the years ended 2005 and 2004, respectively.
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Under the terms of the vehicle operating lease, the Company has guaranteed a residual value to the lessor in the event the leased items are sold. The guarantee provides for reimbursement of up to 87 percent of the unamortized value of the lease portfolio. Under the guarantee, if the entire lease portfolio had a fair value of zero at December 31, 2005, the Company would have been responsible for a maximum reimbursement of $5.4 million and at December 31, 2004, the Company would have been responsible for a maximum reimbursement of $3.9 million. The Company had a liability of $0.2 million at December 31, 2005 representing its obligation under the guarantee based on the fair market value of the entire portfolio.
Pursuant to the terms of the Company's lease for its corporate headquarters, in 2005 the Company exercised its final renewal option for a period of ten years beginning November 2006. While the current and prior leases have been considered capital leases, the Company believes that the lease renewal will qualify as an operating lease. Annual lease payments are considered nominal, with total future minimum lease payments amounting to less than $0.1 million at December 31, 2005.
Other operating lease commitments are considered minimal, as most are cancelable after one year from inception. Total rental expense, which includes pole attachment rents in addition to the operating lease agreements described above, included in the determination of net income amounted to about $5.5 million in 2005, $5.2 million in 2004, and $4.4 million in 2003 .
Legal proceedings The Company is involved in legal and administrative proceedings in the normal course of business and does not believe that the ultimate outcome of these proceedings will have a material adverse effect on its financial position or results of operations, except as otherwise disclosed herein.
Appropriated Retained Earning Major hydro-electric project licenses provide that after an initial 20-year period, a portion of the earnings of such project in excess of a specified rate of return is to be set aside in appropriated retained earnings in compliance with FERC Order No. 5, issued in 1978. The Company's appropriated retained earnings included in retained earnings on the Consolidated Balance Sheets were $0.8 million at December 31, 2005 and $0.7 million at December 31, 2004.
Change of control The Company has management continuity agreements with certain officers that become operative upon a change in control of the Company. Potential severance expense under the agreements varies over time depending on several factors, including the specific plan for individual officers and officers' compensation and age at the time of the change of control.
NOTE 14 - SEGMENT REPORTING
The Company's reportable operating segments include: Central Vermont Public Service Corporation ("CV"), which engages in the purchase, production, transmission, distribution and sale of electricity in Vermont; Custom Investment Corporation is included with CV in the table below; Eversant Corporation, ("Eversant"), which engages in the sale or rental of electric water heaters through a subsidiary, SmartEnergy Water Heating Services, Inc., to customers in Vermont and New Hampshire; and Catamount Resources & Other, which includes Catamount Resources Corporation ("Catamount Resources") and C.V. Realty, Inc. Catamount Resources was formed to hold the Company's subsidiaries that invest in unregulated business opportunities, and C V Realty, Inc. is a real estate company whose purpose is to own, acquire, buy, sell and lease real and personal property and interests therein related to the utility business. Its operations and assets are below the quantitative threshold tests; therefore, CV Realty is included in Catamount Resources and Other.
In 2005, Catamount Resources exceeded the quantitative threshold test for the following reasons: 1) its assets exceeded 10 percent of total consolidated assets, primarily resulting from the sale of Catamount and 2) it exceeded the test as a result of its loss from continuing operations. Also, in 2005, Eversant exceeded the quantitative threshold test as a result of its income; therefore, both segments require separate disclosure and the Company has revised the table below including prior years to present Catamount Resources and Eversant as separate reportable operating segments. Prior to 2005, Catamount Resources and Eversant were below the quantitative threshold, and were included under the caption 'All Other' in the segment table. The Company's discontinued operations include Catamount and Connecticut Valley as described in Note 3 - Discontinued Operations. Both had been separate reportable operating segments of the Company, prior to reclassification as discontinued operations.
Page 119 of 153
The accounting policies of operating segments are the same as those described in the summary of significant accounting policies. Inter-segment revenues include revenues for support services, including allocations of software systems and equipment, to Eversant. Financial information by segment is shown in the table below (in thousands).
|
|
|
Catamount |
|
Reclassification |
|
|
|
2005 |
||||||
|
Revenues from external customers |
|
|
|
|
|
|
|
2004 |
||||||
|
Revenues from external customers |
$302,286 |
$1,833 |
- |
- |
$(1,833) |
$302,286 |
|
2003 |
||||||
|
Revenues from external customers |
$306,098 |
$1,908 |
- |
- |
$(1,908) |
$306,098 |
Page 120 of 153
NOTE 15 - UNAUDITED QUARTERLY FINANCIAL INFORMATION
The following quarterly financial information is unaudited and includes all adjustments consisting of normal recurring accruals which are, in the opinion of Management, necessary for a fair statement of results of operations for such periods. The tables below include originally reported amounts and revised amounts to reflect reclassification of Catamount as discontinued operations in 2005 and 2004. The Company was not required to report Catamount as discontinued operations until the fourth quarter of 2005. See Note 3 - Discontinued Operations for additional information (in thousands, except per share amounts):
|
|
|
|
|||
|
March |
June |
September |
December |
Total (a) |
|
|
Operating revenues Operating (loss) income (Loss) income from continuing operations Income (loss) from discontinued operations Less dividends on preferred stock Net income available for common stock Catamount Reclassifications (See Note 3) Operating revenues (b) Operating (loss) income (b) (Loss) income from continuing operations Income (loss) from discontinued operations As Reclassified for Catamount Discontinued Operations Operating revenues Operating (loss) income (Loss) income from continuing operations Income from discontinued operations Less dividends on preferred stock Net income available for common stock Per Share Data (c) As Originally Reported Basic (loss) earnings per share from: Continuing operations Discontinued operations Total basic earnings per share Diluted (loss) earnings per share from: Continuing operations Discontinued operations Total diluted earnings per share As Reclassified for Catamount Discontinued Operations Basic (loss) earnings per share from: Continuing operations Discontinued operations Total basic earnings per share Diluted (loss) earnings per share from: Continuing operations Discontinued operations Total diluted earnings per share |
|
|
|
|
|
|
(a) The summation of quarterly earnings per share data may not equal annual data due to rounding. |
|||||
Page 121 of 153
|
2004 |
Quarter Ended |
||||
|
March |
June |
September |
December |
Total (a) |
|
|
As Originally Reported Operating (loss) income (Loss) income from continuing operations Income (loss) from discontinued operations Less dividends on preferred stock Net income available for common stock Catamount Reclassifications (See Note 3) Operating revenues (b) Operating (loss) income (b) (Loss) income from continuing operations Income (loss) from discontinued operations As Reclassified for Catamount Discontinued Operations Operating revenues Operating (loss) income (Loss) income from continuing operations Income from discontinued operations Less dividends on preferred stock Net income available for common stock Per Share Data (c) As Originally Reported Basic (loss) earnings per share from: Continuing operations Discontinued operations Total basic earnings per share Diluted (loss) earnings per share from: Continuing operations Discontinued operations Total diluted earnings per share As Reclassified for Catamount Discontinued Operations Basic (loss) earnings per share from: Continuing operations Discontinued operations Total basic earnings per share Diluted (loss) earnings per share from: Continuing operations Discontinued operations Total diluted earnings per share |
|
|
|
|
|
|
(a) The summation of quarterly earnings per share data may not equal annual data due to rounding. |
|||||
NOTE 16 - RESTATEMENT
Page 122 of 153
HSS senior series preferred stock in December 2002. The Company's impairment analysis as of December 31, 2002 did not take this fact into account. Consequently, the Company should have recorded the impairment, $0.8 million after-tax, in December 2002.
As a result of the errors described above, the $0.8 million after-tax investment impairment in 2002 has been reflected as a prior period correction to retained earnings as of January 1, 2003. The Company's 2004 and 2003 Consolidated Statements of Income have been restated to correct misclassification errors, but originally reported net income for both periods did not change. The Company's 2004 Consolidated Balance Sheet has been restated to reflect correction of errors resulting in a $3.9 million increase in Total Assets and Total Capitalization and Liabilities. The Company's 2004 and 2003 Statements of Cash Flows have been restated to reflect the correction of balance sheet misclassifications impacting 2002 through 2004, and prior year presentation of discontinued operations. All of the amounts included in this report reflect the effects of these restated financial results.
The following tables provide a reconciliation of originally reported amounts to restated amounts with reference to the above errors. A reclassification column is included in the tables due to presentation of Catamount as discontinued operations beginning in the fourth quarter of 2005.
Page 123 of 153
Consolidated Statements of Income Data: (in thousands)
|
|
As |
|
|
As |
|
Other Income and (Deductions) |
||||
|
Other income (e) |
$8,845 |
$1,072 |
$(3,569) |
$6,348 |
|
Other deductions (e) |
(9,255) |
(1,072) |
8,365 |
(1,962) |
|
Interest Expense |
||||
|
Interest on long-term debt (b) |
$8,925 |
$(138) |
$(137) |
$8,650 |
|
Other interest (b) |
991 |
138 |
(40) |
1,089 |
|
Total Interest Expense |
$9,859 |
$- |
$(177) |
$9,682 |
|
2003 |
||||
|
Other Income and (Deductions) |
||||
|
Other income (e) |
$7,211 |
$1,029 |
$(3,015) |
$5,225 |
|
Other deductions (e) |
(10,855) |
(1,029) |
9,709 |
(2,175) |
|
Interest Expense |
||||
|
Interest on long-term debt (b) |
$11,231 |
$(126) |
$(520) |
$10,585 |
|
Other interest (b) |
547 |
126 |
(137) |
536 |
|
Total Interest Expense |
$11,740 |
$- |
$(657) |
$11,083 |
Consolidated Balance Sheet Data:
|
|
As |
|
|
As |
|
Assets |
||||
|
Non-utility investments (a) |
$25,670 |
$(1,362) |
$(24,308) |
- |
|
Total investments and other assets |
$77,460 |
$(1,362) |
$(24,822) |
$51,276 |
|
Restricted cash (f) |
$2,000 |
$(2,000) |
- |
- |
|
Special deposits (f) |
- |
$2,000 |
- |
$2,000 |
|
Accounts receivable, less allowance (f) |
$20,832 |
$1,273 |
$(14) |
$22,091 |
|
Allowance for doubtful accounts (f) |
$(1,886) |
$(341) |
$278 |
$(1,949) |
|
Deferred income taxes (c) |
- |
$2,993 |
- |
$2,993 |
|
Other current assets (f) |
$2,213 |
$(1,139) |
$(293) |
$781 |
|
Total current assets |
$113,574 |
$3,127 |
$37,626 |
$154,327 |
|
Other (d) (f) |
$6,183 |
$2,178 |
$(121) |
$8,240 |
|
Total deferred charges and other assets |
$56,269 |
$2,178 |
$(121) |
$58,326 |
|
Total Assets |
$546,763 |
$3,943 |
$12,683 |
$563,389 |
|
Capitalization and Liabilities |
||||
|
Retained Earnings (a) |
$100,512 |
$(810) |
- |
$99,702 |
|
Total common stock equity |
$225,463 |
$(810) |
- |
$224,653 |
|
Long-term debt (b) |
$126,750 |
$(10,800) |
- |
$115,950 |
|
Total capitalization |
$373,361 |
$(11,610) |
- |
$361,751 |
|
Notes Payable (b) |
- |
$10,800 |
- |
$10,800 |
|
Other current liabilities (f) |
$20,331 |
$(341) |
$(1,415) |
$18,575 |
|
Total current liabilities |
$45,905 |
$10,459 |
$18,575 |
$74,939 |
|
Deferred income taxes (c) |
$32,379 |
$2,441 |
$(4,999) |
$29,821 |
|
Accrued pension and benefit obligations (d) |
$23,508 |
$2,563 |
- |
$26,071 |
|
Power contract derivatives (f) |
- |
$90 |
$5,735 |
$5,825 |
|
Total deferred credits and other liabilities |
$127,497 |
$5,094 |
$(5,892) |
$126,699 |
|
Total capitalization and liabilities |
$546,763 |
$3,943 |
$12,683 |
$563,389 |
Page 124 of 153
Consolidated Statements of Cash Flows Data: (in thousands)
|
As |
|
|
As |
|
|
For the year ended December 31, 2004: |
||||
|
OPERATING ACTIVITIES |
||||
|
(Increase) decrease in accounts receivable and unbilled revenues (f) |
$(1,791) |
$380 |
$(1,746) |
$(3,157) |
|
(Increase) decrease in other current assets (f, h) |
$(2,508) |
$(39) |
$3,708 |
$1,161 |
|
Increase (decrease) in other current liabilities (f) |
$1,744 |
$(341) |
- |
$1,403 |
|
Net cash provided by (used for) operating activities of continuing operations |
$25,589 |
- |
$(621) |
$24,968 |
|
INVESTING ACTIVITIES |
||||
|
Proceeds from sale of available-for-sale securities (g) |
$336,645 |
$12,725 |
$(34,125) |
$315,245 |
|
Proceeds from sale of discontinued operations (h) |
- |
$30,164 |
- |
$30,164 |
|
Net cash (used for) provided by investing activities of continuing operations |
$(52,080) |
$42,889 |
$(1,254) |
$(10,445) |
|
DISCONTINUED OPERATIONS |
||||
|
Net cash provided by (used for) discontinued operations (h) |
$30,164 |
$(30,164) |
$(804) |
$(804) |
|
Net (decrease) increase in cash and cash equivalents |
$(12,050) |
$12,725 |
- |
$675 |
|
Cash and cash equivalents at beginning of the period |
$23,772 |
$(12,725) |
- |
$11,047 |
|
Cash and cash equivalents at end of the period |
$11,722 |
- |
- |
$11,722 |
|
As |
|
|
As |
|
|
For the year ended December 31, 2003: |
||||
|
OPERATING ACTIVITIES |
||||
|
Decrease (increase) in accounts receivable and unbilled revenues (f) |
$874 |
$(1,272) |
$1,839 |
$1,441 |
|
(Increase ) decrease in other current assets (h) |
$(4,538) |
$1,272 |
$471 |
$(2,795) |
|
Net cash provided by (used for) operating activities of continuing operations |
$46,577 |
- |
$(3,863) |
$42,714 |
|
INVESTING ACTIVITIES |
||||
|
Investments in available-for-sale securities (g) |
$(171,249) |
$(12,725) |
$10,000 |
$(173,974) |
|
Proceeds from sale of available-for-sale securities (g) |
$143,974 |
$14,100 |
- |
$158,074 |
|
Net cash (used for) provided by investing activities of continuing operations |
$(35,142) |
$1,375 |
$5,844 |
$(27,923) |
|
Net (decrease) increase in cash and cash equivalents |
$(16,932) |
$1,375 |
- |
$(15,557) |
|
Cash and cash equivalents at beginning of the period |
$40,704 |
$(14,100) |
- |
$26,604 |
|
Cash and cash equivalents at end of the period |
$23,772 |
$(12,725) |
- |
$11,047 |
NOTE 17 - SUBSEQUENT EVENTS
Tender Offer
Connecticut Yankee - Bechtel Litigation On February 27, 2006, Connecticut Yankee and Bechtel participated in a mediation process, following which Connecticut Yankee and Bechtel agreed to a settlement in principle. On March 7, 2006, Connecticut Yankee and Bechtel entered a settlement, the material terms of which are: the litigation shall be terminated by dismissals with prejudice of all claims and counterclaims, with each party bearing its own costs; Bechtel shall release all liens, garnishments and attachments that it has obtained against Connecticut Yankee assets; Bechtel shall petition FERC to withdraw its intervention in the Connecticut Yankee rate case; the parties shall exchange mutual general releases including releases of Connecticut Yankee shareholders and their affiliates; Bechtel shall pay Connecticut Yankee the sum of $15.0 million; and Connecticut Yankee shall withdraw its termination of the decommissioning contract for default, and the contract shall be deemed terminated by agreement. At this time, the Company cannot predict the effect, if any, this settlement will have related to the FERC litigation. To the extent any amounts of the settlement payment are ultimately returned to the Company, these amounts will be credited for the future benefit of retail ratepayers.
Page 125 of 153
Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, with participation from the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act")), as of the end of the period covered by this annual report on Form 10-K. In the course of this evaluation, our management considered (i) the material weakness in our internal control over financial reporting discussed below (see Management's Report on Internal Control Over Financial Reporting), and (ii) the errors that occurred in connection with a December 20, 2005 Form 8-K filing discussed below. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2005, our disclosure controls and procedures were not effective. In the first quarter of 2006, the Company discovered that it had inadvertently disclosed the sale of its subsidiary, Catamount Energy Corporation, using Item 1.01 in its December 20, 2005 Form 8-K, and should have used Item 2.01. The Company notified the SEC upon completion of its analysis of the error, and filed an amended Form 8-K/A including certain pro forma financial information as required under Item 2.01. Additionally, the Company has implemented a policy of requiring confirmation from legal counsel that all filings with the SEC are in proper form (i.e., requiring legal "approval as to form"). The Company's policy already required legal counsel review of each filing as to substance. The events that led to the omission have been carefully reviewed with both senior management and the Audit Committee of the Board of Directors.
To address the material weakness in internal control described below, we performed additional analysis and other post-closing procedures in an effort to ensure our consolidated financial statements included in this annual report have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.
Management's Report on Internal Control Over Financial Reporting
The Company's management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. The Company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and of the preparation and fair presentation of the Company's financial statements for external reporting purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision of the Company's Chief Executive Officer and Chief Financial Officer, and with participation of our management, we assessed the effectiveness of the Company's internal control over financial reporting based on the framework established in "Internal Control - Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO").
A material weakness is a significant deficiency (as defined in Public Company Accounting Oversight Board Auditing Standard No. 2), or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. Based on the COSO framework, management's assessment identified the following material weakness:
The Company had inadequate internal controls over the Company's financial accounting and closing process. Specifically, the Company did not have adequate controls to (a) provide reasonable assurance that non-routine transactions were evaluated and accounted for in accordance with generally accepted accounting principles, (b) appropriately review the presentation of balances within the consolidated balance sheets to provide reasonable assurance that assets and liabilities were classified in accordance with generally accepted accounting principles, and (c) ensure timeliness and consistency of account reconciliations and analyses.
Page 126 of 153
Due to the potential pervasive effect on financial statement account balances and disclosures and the importance of the annual financial closing and reporting process and the lack of other mitigating controls, there is a more than remote likelihood that a material error would not be prevented or detected. As such, the Company has concluded that its internal control over financial reporting was not effective as of December 31, 2005.
This material weakness was discussed with the Audit Committee of the Board of Directors. Deloitte & Touche LLP, the independent registered public accounting firm that audited the Company's consolidated financial statements included in this report, has issued an attestation report on management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2005. The report is included in this Item under the heading "Report of Independent Registered Public Accounting Firm."
Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting during the fourth quarter of 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
During the first quarter of 2006, we developed a plan to take the following steps to remediate the material weakness as of December 31, 2005:
We will not be able to conclude that the material weakness has been successfully remediated until the testing of controls demonstrates that such controls have operated effectively for a sufficient period of time.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Central Vermont Public Service Corporation:
We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that Central Vermont Public Service Corporation and subsidiaries (the "Company") did not maintain effective internal control over financial reporting as of December 31, 2005, because of the effect of the material weakness identified in management's assessment based on criteria established in Internal Control -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
Page 127 of 153
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in management's assessment:
The Company had inadequate controls over the Company's financial accounting and closing process. Specifically, the Company did not have adequate controls to, (a) provide reasonable assurance that non-routine transactions were evaluated and accounted for in accordance with generally accepted accounting principles, (b) appropriately review the presentation of balances with the consolidated balance sheets to provide reasonable assurance that assets and liabilities were classified in accordance with generally accepted accounting principals, and (c) ensure the timeliness and consistency of account reconciliations and analyses.
This material weakness resulted in the restatement of previously issued financial statements as described in Note 16 to the consolidated financial statements and significant audit adjustments which were required to present the 2005 financial statements in accordance with generally accepted accounting principles. Due to the potential pervasive effect on financial statement account balances and disclosures and the importance of the annual financial closing and reporting process and the lack of other mitigating controls, there is a more than remote likelihood that a material error would not be prevented or detected.
This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated financial statements and consolidated financial statement schedules as of and for the year ended December 31, 2005, of the Company and this report does not affect our report on such consolidated financial statements or consolidated financial statement schedules.
In our opinion, management's assessment that the Company did not maintain effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Page 128 of 153
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and consolidated financial statement schedules as of and for the year ended December 31, 2005, of the Company and our reports dated March 30, 2006 expressed an unqualified opinions on those consolidated financial statements and consolidated financial statement schedules. Our opinion on the consolidated financial statements includes an explanatory paragraph regarding the sale of the Company's interest in Catamount Energy Corporation and an explanatory paragraph regarding the restatement of the 2004 and 2003 consolidated financial statements.
/s/ Deloitte & Touche LLP
Boston, Massachusetts
March 30, 2006
Item 9B. Other Information
None
PART III
Item 10. Directors and Executive Officers of the Registrant.
The information required by this item is incorporated herein by reference to the Proxy Statement of the Company for the 2006 Annual Meeting of Stockholders. The Executive Officers information is listed under Part I, Item 1. Definitive proxy materials will be filed with the Securities and Exchange Commission pursuant to Regulation 14A on or about April 7, 2006.
Item 11. Executive Compensation.
The information required by this item is incorporated herein by reference to the Proxy Statement of the Company for the 2006 Annual Meeting of Stockholders. Definitive proxy materials will be filed with the Securities and Exchange Commission pursuant to Regulation 14A on or about April 7, 2006.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this item related to security ownership of certain beneficial owners is incorporated herein by reference to the Proxy Statement of the Company for the 2006 Annual Meeting of Stockholders. Definitive proxy materials will be filed with the Securities and Exchange Commission pursuant to Regulation 14A on or about April 7, 2006. The Equity Compensation Plan Information is shown in the table below.
|
|
|
|
Number of |
|
Equity compensation plans approved by security holders 1997 Stock Option Plan for Key Employees 1998 Stock Option Plan for Non-employee Directors 2000 Stock Option Plan for Key Employees 2002 Long-Term Incentive Plan |
|
|
|
|
Total |
652,321 |
$17.0235 |
107,540 |
Item 13. Certain Relationships and Related Transactions.
The information required by this item is incorporated herein by reference to the Proxy Statement of the Company for the 2006 Annual Meeting of Stockholders. Definitive proxy materials will be filed with the Securities and Exchange Commission pursuant to Regulation 14A on or about April 7, 2006.
Item 14. Principal Accountant Fees and Services.
The information required by this item is incorporated herein by reference to the Proxy Statement of the Company for the 2006 Annual Meeting of Stockholders. Definitive proxy materials will be filed with the Securities and Exchange Commission pursuant to Regulation 14A on or about April 7, 2006.
Page 129 of 153
PART IV
|
Filed |
|||||
|
Item 15. |
Exhibits, Financial Statement Schedules. |
||||
|
(a)1. |
The following financial statements for Central Vermont Public Service |
|
|||
|
1.1 |
Consolidated Statement of Income for the three years ended |
||||
|
(a)2. |
Financial Statement Schedules: |
||||
|
2.1 |
Central Vermont Public Service Corporation and its wholly owned subsidiaries: |
||||
|
Schedules not included have been omitted because they are not applicable or the required information is shown in the financial statements or notes thereto. Separate financial statements of the Registrant (which is primarily an operating company) have been omitted since they are consolidated only with those of totally held subsidiaries. Separate financial statements of subsidiary companies not consolidated have been omitted since, if considered in the aggregate, they would not constitute a significant subsidiary. Separate financial statements of 50 percent or less owned persons for which the investment is accounted for by the equity method by the Registrant have been omitted since, if considered in the aggregate, they would not constitute a significant investment. |
|||||
|
(a)3. |
Exhibits (* denotes filed herewith) |
||||
|
Each document described below is incorporated by reference to the appropriate exhibit numbers and the Commission file numbers indicated in parentheses, unless the reference to the document is marked as follows: |
|||||
|
Exhibit 3 Articles of Incorporation and Bylaws |
|||||
|
3-1 |
By-laws, as amended October 8, 2005. (Exhibit 99.2, Current Report on Form 8-K Filed October 11, 2005, File No. 1-8222) |
||||
|
3-2 |
Articles of Association, as amended August 11, 1992. (Exhibit No. 3-2, 1992 10-K, File No. 1-8222) |
||||
|
Page 130 of 153 |
|||||
|
Exhibit 4 Instruments defining the rights of security holders, including Indentures |
|||||
|
Incorporated herein by reference: |
|||||
|
4-1 |
Mortgage dated October 1, 1929, between the Company and Old Colony Trust Company, Trustee, securing the Company's First Mortgage Bonds. (Exhibit B-3, File No. 2-2364) |
||||
|
4-2 |
Supplemental Indenture dated as of August 1, 1936. (Exhibit B-4, File No. 2-2364) |
||||
|
4-3 |
Supplemental Indenture dated as of November 15, 1943. (Exhibit B-3, File No. 2-5250) |
||||
|
4-4 |
Supplemental Indenture dated as of December 1, 1943. (Exhibit No. B-4, File No. 2-5250) |
||||
|
4-5 |
Directors' resolutions adopted December 14, 1943, establishing the Series C Bonds and dealing with other related matters. (Exhibit B-5, File No. 2-5250) |
||||
|
4-6 |
Supplemental Indenture dated as of April 1, 1944. (Exhibit No. B-6, File No. 2-5466) |
||||
|
4-7 |
Supplemental Indenture dated as of February 1, 1945. (Exhibit 7.6, File No. 2-5615) (22-385) |
||||
|
4-8 |
Directors' resolutions adopted April 9, 1945, establishing the Series D Bonds and dealing with other matters. (Exhibit 7.8, File No. 2-5615 (22-385) |
||||
|
4-9 |
Supplemental Indenture dated as of September 2, 1947. (Exhibit 7.9, File No. 2-7489) |
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|
4-10 |
Supplemental Indenture dated as of July 15, 1948, and directors' resolutions establishing the Series E Bonds and dealing with other matters. (Exhibit 7.10, File No. 2-8388) |
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|
4-11 |
Supplemental Indenture dated as of May 1, 1950, and directors' resolutions establishing the Series F Bonds and dealing with other matters. (Exhibit 7.11, File No. 2-8388) |
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|
4-12 |
Supplemental Indenture dated August 1, 1951, and directors' resolutions, establishing the Series G Bonds and dealing with other matters. (Exhibit 7.12, File No. 2-9073) |
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|
4-13 |
Supplemental Indenture dated May 1, 1952, and directors' resolutions, establishing the Series H Bonds and dealing with other matters. (Exhibit 4.3.13, File No. 2-9613) |
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|
4-14 |
Supplemental Indenture dated as of July 10, 1953. (July, 1953 Form 8-K, File No. 1-8222) |
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|
4-15 |
Supplemental Indenture dated as of June 1, 1954, and directors' resolutions establishing the Series K Bonds and dealing with other matters. (Exhibit 4.2.16, File No. 2-10959) |
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|
4-16 |
Supplemental Indenture dated as of February 1, 1957, and directors' resolutions establishing the Series L Bonds and dealing with other matters. (Exhibit 4.2.16, File No. 2-13321) |
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|
4-17 |
Supplemental Indenture dated as of March 15, 1960. (March, 1960 Form 8-K, File No. 1-8222) |
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|
4-18 |
Supplemental Indenture dated as of March 1, 1962. (March, 1962 Form 8-K, File No. 1-8222) |
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|
4-19 |
Supplemental Indenture dated as of March 2, 1964. (March, 1964 Form 8-K, File No, 1-8222) |
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|
4-20 |
Supplemental Indenture dated as of March 1, 1965, and directors' resolutions establishing the Series M Bonds and dealing with other matters. (April, 1965 Form 8-K, File No. 1-8222) |
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|
4-21 |
Supplemental Indenture dated as of December 1, 1966, and directors' resolutions establishing the Series N Bonds and dealing with other matters. (January, 1967 Form 8-K, File No. 1-8222) |
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Page 131 of 153 |
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4-22 |
Supplemental Indenture dated as of December 1, 1967, and directors' resolutions establishing the Series O Bonds and dealing with other matters. (December, 1967 Form 8-K, File No. 1-8222) |
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|
4-23 |
Supplemental Indenture dated as of July 1, 1969, and directors' resolutions establishing the Series P Bonds and dealing with other matters. (Exhibit B.23, July, 1969 Form 8-K, File No. 1-8222) |
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|
4-24 |
Supplemental Indenture dated as of December 1, 1969, and directors' resolutions establishing the Series Q Bonds January, and dealing with other matters. (Exhibit B.24, January, 1970 Form 8-K, File No. 1-8222) |
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|
4-25 |
Supplemental Indenture dated as of May 15, 1971, and directors' resolutions establishing the Series R Bonds and dealing with other matters. (Exhibit B.25, May, 1971, Form 8-K, File No. 1-8222) |
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|
4-26 |
Supplemental Indenture dated as of April 15, 1973, and directors' resolutions establishing the Series S Bonds and dealing with other matters. (Exhibit B.26, May, 1973, Form 8-K, File No. 1-8222) |
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|
4-27 |
Supplemental Indenture dated as of April 1, 1975, and directors' resolutions establishing the Series T Bonds and dealing with other matters. (Exhibit B.27, April, 1975, Form 8-K, File No. 1-8222) |
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|
4-28 |
Supplemental Indenture dated as of April 1, 1977. (Exhibit 2.42, File No. 2-58621) |
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|
4-29 |
Supplemental Indenture dated as of July 29, 1977, and directors' resolutions establishing the Series U, V, W, and X Bonds and dealing with other matters. (Exhibit 2.43, File No. 2-58621) |
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|
4-30 |
Thirtieth Supplemental Indenture dated as of September 15, 1978, and directors' resolutions establishing the Series Y Bonds and dealing with other matters. (Exhibit B-30, 1980 Form 10-K, File No. 1-8222) |
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|
4-31 |
Thirty-first Supplemental Indenture dated as of September 1, 1979, and directors' resolutions establishing the Series Z Bonds and dealing with other matters. (Exhibit B-31, 1980 Form 10-K, File No. 1-8222) |
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|
4-32 |
Thirty-second Supplemental Indenture dated as of June 1, 1981, and directors' resolutions establishing the Series AA Bonds and dealing with other matters. (Exhibit B-32, 1981 Form 10-K, File No. 1-8222) |
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|
4-45 |
Thirty-third Supplemental Indenture dated as of August 15, 1983, and directors' resolutions establishing the Series BB Bonds and dealing with other matters. (Exhibit B-45, 1983 Form 10-K, File No. 1-8222) |
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|
4-46 |
Bond Purchase Agreement between Merrill, Lynch, Pierce, Fenner & Smith, Inc., Underwriters and The Industrial Development Authority of the State of New Hampshire, issuer and Central Vermont Public Service Corporation. (Exhibit B-46, 1984 Form 10-K, File No. 1-8222) |
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|
4-47 |
Thirty-Fourth Supplemental Indenture dated as of January 15, 1985, and directors' resolutions establishing the Series CC Bonds and Series DD Bonds and matters connected therewith. (Exhibit B-47, 1985 Form 10-K, File No. 1-8222) |
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|
4-48 |
Bond Purchase Agreement among Connecticut Development Authority and Central Vermont Public Service Corporation with E. F. Hutton & Company Inc. dated December 11, 1985. (Exhibit B-48, 1985 Form 10-K, File No. 1-8222) |
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|
4-49 |
Stock-Purchase Agreement between Vermont Electric Power Company, Inc. and the Company dated August 11, 1986 relative to purchase of Class C Preferred Stock. (Exhibit B-49, 1986 Form 10-K, File No. 1-8222) |
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|
4-50 |
Thirty-Fifth Supplemental Indenture dated as of December 15, 1989 and directors' resolutions establishing the Series EE, Series FF and Series GG Bonds and matters connected therewith. (Exhibit 4-50, 1989 Form 10-K, File No. 1-8222) |
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|
4-51 |
Thirty-Sixth Supplemental Indenture dated as of December 10, 1990 and directors' resolutions establishing the Series HH Bonds and matters connected therewith. (Exhibit 4-51, 1990 Form 10-K, File No. 1-8222) |
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|
Page 132 of 153 |
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|
4-52 |
Thirty-Seventh Supplemental Indenture dated December 10, 1991 and directors' resolutions establishing the Series JJ Bonds and matters connected therewith. (Exhibit 4-52, 1991 Form 10-K, File No. 1-8222) |
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|
4-53 |
Thirty-Eight Supplemental Indenture dated December 10, 1993 establishing Series KK, LL, MM, NN, OO. (Exhibit 4-53, 1993 Form 10-K, File No. 1-8222) |
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|
4-54 |
Thirty-Ninth Supplemental Indenture Dated December 29, 1997. (Exhibit 4-54, 1997 Form 10-K, File No. 1-8222) |
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|
4-55 |
Fortieth Supplemental Indenture Dated January 28, 1998. (Exhibit 4-55, 1997 Form 10-K, File No. 1-8222) |
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|
4-56 |
Credit Agreement Dated As of November 5, 1997 among Central Vermont Public Service Corporation, The Lenders Named Herein and Toronto-Dominion (Texas), Inc., as Agent. (Exhibit 10.83, 1997 Form 10-K, File No. 1-8222) |
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|
4-56.1 First Amendment to Credit Agreement Dated as of April 15, 1998 |
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|
4-56.2 Second Amendment to Credit Agreement Dated as of June 2, 1998 |
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|
4-56-.3 Third Amendment to Credit Agreement Dated as of October 5, 1998 |
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|
4-56.4 Open-End Mortgage, Security Agreement, Assignment of Rents and Leases, |
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|
4-56.5 Security Agreement, dated as of October 5, 1998, between the Company and |
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|
4-57 |
Forty-First Supplemental Indenture, dated as of July 19, 1999 and resolutions establishing Series PP (Millstone) Bonds, Series QQ (Seabrook) Bonds and Series RR (East Barnet) Bonds And matters connected therewith adopted July 19, 1999. (Exhibit 4-57, Form 10-Q, September 30, 1999, File No. 1-8222) |
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|
4-58 |
Second Mortgage Indenture, dated as of July 15, 1999, Central Vermont Public Service Corporation to the Bank of New York, Trustee (Exhibit 4-58, Form 10-Q, September 30, 1999, File No. 1-8222) |
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|
4-59 |
First Supplemental Indenture to the Second Mortgage, Central Vermont Public Service Corporation to the Bank of New York, Trustee, dated as of July 15, 1999, creating an issue of Mortgage Bonds, 8-1/8 percent Second Mortgage Bonds due 2004 (Exhibit 4-59, Form 10-Q, September 30, 1999, File No. 1-8222) |
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|
4-60 |
A/B Exchange Registration Rights Agreement, dated as of July 30, 1999 by and among Central Vermont Public Service Corporation and Donaldson, Lufkin & Jenrette Securities Corporation, TD Securities (USA) Inc. (Exhibit 4-60, Form 10-Q, September 30, 1999, File No. 1-8222) |
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|
4-61 |
Forty-Second Supplemental Indenture, dated as of June 11, 2001 and resolutions connected therewith adopted June 11, 2001. (Exhibit 4-61, Form 8-K, June 28,2001, File No. 1-8222) |
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|
4-62 |
Forty-Third Supplemental Indenture, dated as of April 1, 2003 and resolutions connected therewith adopted February 24, 2003. (Exhibit 4-62, Form 10-Q, June 30, 2003, File No. 1-8222) |
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|
Page 133 of 153 |
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|
4-63 |
Forty-Fourth Supplemental Indenture, dated as of June 15, 2004 amending and restating the Company's Indenture of Mortgage dated as of October 1, 1929. (Exhibit 4-63, Form 10-Q, June 30, 2004, File No. 1-8222) |
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|
4-64 |
Forty-Fifth Supplemental Indenture, dated as of July 15, 2004 and directors' resolutions establishing the Series SS and Series TT Bonds and matter connected therewith. (Exhibit 4-64, Form 10-Q, June 30, 2004, File No. 1-8222) |
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|
4-65 |
Form of Bond Purchase Agreement dated as of July 15, 2004 relating to Series SS and Series TT Bonds. (Exhibit 4-65, Form 10-Q, June 30, 2004, File No. 1-8222) |
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|
Exhibit 10 Material Contracts (* Denotes filed herewith) |
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|
Incorporated herein by reference: |
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|
10.1 |
Copy of firm power Contract dated August 29, 1958, and supplements thereto dated September 19, 1958, October 7, 1958, and October 1, 1960, between the Company and the State of Vermont (the "State"). (Exhibit C-1, File No. 2-17184) |
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|
10.1.1 Agreement setting out Supplemental NEPOOL Understandings dated as of |
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|
10.2 |
Copy of Transmission Contract dated June 13, 1957, between Velco and the State, relating to transmission of power. (Exhibit 10.2, 1993 Form 10-K, File No. 1-8222) |
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|
10.2.1 Copy of letter agreement dated August 4, 1961, between Velco and |
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|
10.2.2 Amendment dated September 23, 1969. (Exhibit C-4, File No. 2-38161) |
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|
10.2.3 Amendment dated March 12, 1980. (Exhibit C-92, 1982 Form 10-K, File |
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|
10.2.4 Amendment dated September 24, 1980. (Exhibit C-93, 1982 Form 10-K, |
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|
10.3 |
Copy of subtransmission contract dated August 29, 1958, between Velco and the Company (there are seven similar contracts between Velco and other utilities). (Exhibit 10.3, 1993 Form 10-K, Form No. 1-8222) |
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|
10.3.1 Copies of Amendments dated September 7, 196l, November 2, 1967, |
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|
10.3.2 Amendment dated December 1, 1972. (Exhibit 10.3.2, 1993 Form 10-K, |
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|
10.4 |
Copy of Three-Party Agreement dated September 25, 1957, between the Company, Green Mountain and Velco. (Exhibit C-7, File No. 2-17184) |
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|
10.4.1 Superseding Three Party Power Agreement dated January 1, 1990. |
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|
10.4.2 Agreement Amending Superseding Three Party Power Agreement |
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|
10.5 |
Copy of firm power Contract dated December 29, 1961, between the Company and the State, relating to purchase of Niagara Project power. (Exhibit C-8, File No. 2-26485) |
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|
Page 134 of 153 |
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|
10.5.1 Amendment effective as of January 1, 1980. (Exhibit 10.5.1, 1993 |
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|
10.6 |
Copy of agreement dated July 16, 1966, and letter supplement dated July 16, 1966, between Velco and Public Service Company of New Hampshire relating to purchase of single unit power from Merrimack II. (Exhibit C-9, File No. 2-26485) |
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|
10.6.1 Copy of Letter Agreement dated July 10, 1968, modifying Exhibit A. |
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|
10.7 |
Copy of Capital Funds Agreement between the Company and Vermont Yankee dated as of February 1, 1968. (Exhibit C-11, File No. 70-4611) |
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|
10.7.1 Copy of Amendment dated March 12, 1968. (Exhibit C-12, File No. 70-4611) |
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|
10.7.2 Copy of Amendment dated September 1, 1993. (Exhibit 10.7.2, 1994 |
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|
10.8 |
Copy of Power Contract between the Company and Vermont Yankee dated as of February 1, 1968. (Exhibit C-13, File No. 70-4591) |
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|
10.8.1 Amendment dated April 15, 1983. (10.8.1, 1993 Form 10-K, File No. 1-8222) |
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|
10.8.2 Copy of Additional Power Contract dated February 1, 1984. (Exhibit C-123, |
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|
10.8.3 Amendment No. 3 to Vermont Yankee Power Contract, dated April 24, 1985. |
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|
10.8.4 Amendment No. 4 to Vermont Yankee Power Contract, dated June 1, 1985. |
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|
10.8.5 Amendment No. 5 dated May 6, 1988. (Exhibit 10-179, 1988 Form 10-K, |
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|
10.8.6 Amendment No. 6 dated May 6, 1988. (Exhibit 10-180, 1988 Form 10-K, |
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|
10.8.7 Amendment No. 7 dated June 15, 1989. (Exhibit 10-195, 1989 Form 10-K, |
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|
10.8.8 Amendment No. 8 dated November 17, 1999. (Exhibit 10.8.8, Form 10-Q, |
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|
10.8.9 Amendment No. 9 dated November 17, 1999. (Exhibit 10.8.9, Form 10-Q, |
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|
10.8.10 2001 Amendatory Agreement dated as of September 21, 2001 to which the |
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|
10.9 |
Copy of Capital Funds Agreement between the Company and Maine Yankee dated as of May 20, 1968. (Exhibit C-14, File No. 70-4658) |
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|
10.9.1 Amendment No. 1 dated August 1, 1985. (Exhibit C-125, 1984 Form 10-K, |
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|
Page 135 of 153 |
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|
10.10 |
Copy of Power Contract between the Company and Maine Yankee dated as of May 20, 1968. (Exhibit C-15, File No. 70-4658) |
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|
10.10.1 Amendment No. 1 dated March 1, 1984. (Exhibit C-112, 1984 Form 10-K, |
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|
10.10.2 Amendment No. 2 effective January 1, 1984. (Exhibit C-113, 1984 Form 10-K, |
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|
10.10.3 Amendment No. 3 dated October 1, 1984. (Exhibit C-114, 1984 Form 10-K, |
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|
10.10.4 Additional Power Contract dated February 1, 1984. (Exhibit C-126, 1985 Form 10-K, |
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|
10.11 |
Copy of Agreement dated January 17, 1968, between Velco and Public Service Company of New Hampshire relating to purchase of additional unit power from Merrimack II. (Exhibit C-16, File No. 2-32917) |
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|
10.12 |
Copy of Agreement dated February 10, 1968 between the Company and Velco relating to purchase by Company of Merrimack II unit power. (There are 25 similar agreements between Velco and other utilities.) (Exhibit C-17, File No. 2-32917) |
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|
10.13 |
Copy of Three-Party Power Agreement dated as of November 21, 1969, among the Company, Velco, and Green Mountain relating to purchase and sale of power from Vermont Yankee Nuclear Power Corporation. (Exhibit C-18, File No. 2-38161) |
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|
10.13.1 Amendment dated June 1, 1981. (Exhibit 10.13.1, 1993 Form 10-K, File No. 1-8222) |
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|
10.14 |
Copy of Three-Party Transmission Agreement dated as of November 21, 1969, among the Company, Velco, and Green Mountain providing for transmission of power from Vermont Yankee Nuclear Power Corporation. (Exhibit C-19, File No. 2-38161) |
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|
10.14.1 Amendment dated June 1, 1981. (Exhibit 10.14.1, 1993 Form 10-K, File No. 1-8222) |
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|
10.15 |
Copy of Stockholders Agreement dated September 25, 1957, between the Company, Velco, Green Mountain and Citizens Utilities Company. (Exhibit No. C-20, File No. 70-3558) |
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|
10.16 |
New England Power Pool Agreement dated as of September 1, 1971, as amended to November 1, 1975. (Exhibit C-21, File No. 2-55385) |
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|
10.16.1 Amendment dated December 31, 1976. (Exhibit 10.16.1, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.2 Amendment dated January 23, 1977. (Exhibit 10.16.2, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.3 Amendment dated July 1, 1977. (Exhibit 10.16.3, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.4 Amendment dated August 1, 1977. (Exhibit 10.16.4, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.5 Amendment dated August 15, 1978. (Exhibit 10.16.5, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.6 Amendment dated January 31, 1979. (Exhibit 10.16.6, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.7 Amendment dated February 1, 1980. (Exhibit 10.16.7, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.8 Amendment dated December 31, 1976. (Exhibit 10.16.8, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.9 Amendment dated January 31, 1977. (Exhibit 10.16.9, 1993 Form 10-K, File No. 1-8222) |
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|
Page 136 of 153 |
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|
10.16.10 Amendment dated July 1, 1977. (Exhibit 10.16.10, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.11 Amendment dated August 1, 1977. (Exhibit 10.16.11, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.12 Amendment dated August 15, 1978. (Exhibit 10.16.12, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.13 Amendment dated January 31, 1980. (Exhibit 10.16.13, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.14 Amendment dated February 1, 1980. (Exhibit 10.16.14, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.15 Amendment dated September 1, 1981. (Exhibit 10.16.15, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.16 Amendment dated December 1, 1981. (Exhibit 10.16.16, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.17 Amendment dated June 15, 1983. (Exhibit 10.16.17, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.18 Amendment dated September 1, 1985. (Exhibit 10-160, 1986 Form 10-K, File No. 1-8222) |
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|
10.16.19 Amendment dated April 30, 1987. (Exhibit 10-172, 1987 Form 10-K, File No. 1-8222) |
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|
10.16.20 Amendment dated March 1, 1988. (Exhibit 10-178, 1988 Form 10-K, File No. 1-8222) |
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|
10.16.21 Amendment dated March 15, 1989. (Exhibit 10-194, 1989 Form 10-K, File No. 1-8222) |
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|
10.16.22 Amendment dated October 1, 1990. (Exhibit 10-203, 1990 Form 10-K, File No. 1-8222) |
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|
10.16.23 Amendment dated September 15, 1992. (Exhibit 10.16.23, 1992 Form 10-K, File No. 1-8222) |
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|
10.16.24 Amendment dated May 1, 1993. (Exhibit 10.16.24, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.25 Amendment dated June 1, 1993. (Exhibit 10.16.25, 1993 Form 10-K, File No. 1-8222) |
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|
10.16.26 Amendment dated June 1, 1994. (Exhibit 10.16.26, 1994 Form 10-K, File No. 1-8222) |
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|
10.16.27 Thirty-Second Amendment dated September 1, 1995. (Exhibit 10.16.27, Form 10-Q |
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|
10.16.28 Security Agreement dated October 7, 2003 between Central Vermont Public Service |
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|
10.17 |
Agreement dated October 13, 1972, for Joint Ownership, Construction and Operation of Pilgrim Unit No. 2 among Boston Edison Company and other utilities, including the Company. (Exhibit C-23, File No. 2-45990) |
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|
10.17.1 |
Amendments dated September 20, 1973, and September 15, 1974. (Exhibit C-24, File No. 2-51999) |
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|
10.17.2 |
Amendment dated December 1, 1974. (Exhibit C-25, File No. 2-54449) |
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|
10.17.3 |
Amendment dated February 15, 1975. (Exhibit C-26, File No. 2-53819) |
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|
10.17.4 |
Amendment dated April 30, 1975. (Exhibit C-27, File No. 2-53819) |
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|
10.17.5 |
Amendment dated as of June 30, 1975. (Exhibit C-28, File No. 2-54449) |
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|
Page 137 of 153 |
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|
10.17.6 |
Instrument of Transfer dated as of October 1, 1974, assigning partial interest from the Company to Green Mountain Power Corporation. (Exhibit C-29, File No. 2-52177) |
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|
10.17.7 |
Instrument of Transfer dated as of January 17, 1975, assigning a partial interest from the Company to the Burlington Electric Department. (Exhibit C-30, File No. 2-55458) |
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|
10.17.8 |
Addendum dated as of October 1, 1974 by which Green Mountain Power Corporation became a party thereto. (Exhibit C-31, File No. 2-52177) |
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|
10.17.9 |
Addendum dated as of January 17, 1975 by which the Burlington Electric Department became a party thereto. (Exhibit C-32, File No. 2-55450) |
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|
10.17.10 |
Amendment 23 dated as of 1975. (Exhibit C-50, 1975 Form 10-K, File No. 1-8222) |
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|
10.18 |
Agreement for Sharing Costs Associated with Pilgrim Unit No.2 Transmission dated October 13, 1972, among Boston Edison Company and other utilities including the Company. (Exhibit C-33, File No. 2-45990) |
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|
10.18.1 |
Addendum dated as of October 1, 1974, by which Green Mountain Power Corporation became a party thereto. (Exhibit C-34, File No. 2-52177) |
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|
10.18.2 |
Addendum dated as of January 17, 1975, by which Burlington Electric Department became a party thereto. (Exhibit C-35, File No. 2-55458) |
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|
10.19 |
Agreement dated as of May 1, 1973, for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units among Public Service Company of New Hampshire and other utilities, including Velco. (Exhibit C-36, File No. 2-48966) |
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|
10.19.1 |
Amendments dated May 24, 1974, June 21, 1974, September 25, 1974, October 25, 1974, and January 31, 1975. (Exhibit C-37, File No. 2-53674) |
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|
10.19.2 |
Instrument of Transfer dated September 27, 1974, assigning partial interest from Velco to the Company. (Exhibit C-38, File No. 2-52177) |
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|
10.19.3 |
Amendments dated May 24, 1974, June 21, 1974, and September 25, 1974. (Exhibit C-81, File No. 2-51999) |
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|
10.19.4 |
Amendments dated October 25, 1974 and January 31, 1975. (Exhibit C-82, File No. 2-54646) |
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|
10.19.5 |
Sixth Amendment dated as of April 18, 1979. (Exhibit C-83, File No. 2-64294) |
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|
10.19.6 |
Seventh Amendment dated as of April 18, 1979. (Exhibit C-84, File No. 2-64294) |
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|
10.19.7 |
Eighth Amendment dated as of April 25, 1979. (Exhibit C-85, File No. 2-64815) |
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|
10.19.8 |
Ninth Amendment dated as of June 8, 1979. (Exhibit C-86, File No. 2-64815) |
||||
|
10.19.9 |
Tenth Amendment dated as of October 10, 1979. (Exhibit C-87, File No. 2-66334 ) |
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|
10.19.10 |
Eleventh Amendment dated as of December 15, 1979. (Exhibit C-88, File No.2-66492) |
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|
10.19.11 |
Twelfth Amendment dated as of June 16, 1980. (Exhibit C-89, File No. 2-68168) |
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|
10.19.12 |
Thirteenth Amendment dated as of December 31, 1980. (Exhibit C-90, File No. 2-70579) |
||||
|
10.19.13 |
Fourteenth Amendment dated as of June 1, 1982. (Exhibit C-104, 1982 Form 10-K, File No. 1-8222) |
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|
Page 138 of 153 |
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|
10.19.14 |
Fifteenth Amendment dated April 27, 1984. (Exhibit 10-134, 1986 Form 10-K, File No. 1-8222) |
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|
10.19.15 |
Sixteenth Amendment dated June 15, 1984. (Exhibit 10-135, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.19.16 |
Seventeenth Amendment dated March 8, 1985. (Exhibit 10-136, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.19.17 |
Eighteenth Amendment dated March 14, 1986. (Exhibit 10-137, 1986 Form 10-K, File No. 1-8222) |
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|
10.19.18 |
Nineteenth Amendment dated May 1, 1986. (Exhibit 10-138, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.19.19 |
Twentieth Amendment dated September 19, 1986. (Exhibit 10-139, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.19.20 |
Amendment No. 22 dated January 13, 1989. (Exhibit 10-193, 1989 Form 10-K, File No. 1-8222) |
||||
|
10.20 |
Transmission Support Agreement dated as of May 1, 1973, among Public Service Company of New Hampshire and other utilities, including Velco, with respect to New Hampshire Nuclear Units. (Exhibit C-39, File No. 2-48966) |
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|
10.21 |
Sharing Agreement - 1979 Connecticut Nuclear Unit dated September 1, 1973, to which the Company is a party. (Exhibit C-40, File No. 2-50142) |
||||
|
10.21.1 |
Amendment dated as of August 1, 1974. (Exhibit C-41, File No. 2-51999) |
||||
|
10.21.2 |
Instrument of Transfer dated as of February 28, 1974, transferring partial interest from the Company to Green Mountain. (Exhibit C-42, File No. 2-52177) |
||||
|
10.21.3 |
Instrument of Transfer dated January 17, 1975, transferring a partial interest from the Company to Burlington Electric Department. (Exhibit C-43, File No. 2-55458) |
||||
|
10.21.4 |
Amendment dated May 11, 1984. (Exhibit C-110, 1984 Form 10-K, File No. 1-8222) |
||||
|
10.22 |
Preliminary Agreement dated as of July 5, 1974, with respect to 1981 Montague Nuclear Generating Units. (Exhibit C-44, File No. 2-51733) |
||||
|
10.22.1 |
Amendment dated June 30, 1975. (Exhibit C-45, File No. 2-54449) |
||||
|
10.23 |
Agreement for Joint Ownership, Construction and Operation of William F. Wyman Unit No. 4 dated November 1, 1974, among Central Maine Power Company and other utilities including the Company. (Exhibit C-46, File No. 2-52900) |
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|
10.23.1 |
Amendment dated as of June 30, 1975. (Exhibit C-47, File No. 2-55458) |
||||
|
10.23.2 |
Instrument of Transfer dated July 30, 1975, assigning a partial interest from Velco to the Company. (Exhibit C-48, File No. 2-55458) |
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|
10.24 |
Transmission Agreement dated November 1, 1974, among Central Maine Power Company and other utilities including the Company with respect to William F. Wyman Unit No. 4. (Exhibit C-49, File No. 2-54449) |
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|
10.25 |
Copy of Power Contract between the Company and Yankee Atomic dated as of June 30, 1959. (Exhibit C-61, 1981 Form 10-K, File No. 1-8222) |
||||
|
10.25.1 |
Revision dated April 1, 1975. (Exhibit C-61, 1981 Form 10-K, File No. 1-8222) |
||||
|
10.25.2 |
Amendment dated May 6, 1988. (Exhibit 10-181, 1988 Form 10-K, File No. 1-8222) |
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|
Page 139 of 153 |
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|
10.25.3 |
Amendment dated June 26, 1989. (Exhibit 10-196, 1989 Form 10-K, File No. 1-8222) |
||||
|
10.25.4 |
Amendment dated July 1, 1989. (Exhibit 10-197, 1989 Form 10-K, File No. 1-8222) |
||||
|
10.25.5 |
Amendment dated February 1, 1992 (Exhibit 10.25.5, 1992 Form 10-K, File No. 1-8222) |
||||
|
10.26 |
Copy of Transmission Contract between the Company and Yankee Atomic dated as of June 30, 1959. (Exhibit C-63, 1981 Form 10-K, File No. 1-8222) |
||||
|
10.27 |
Copy of Power Contract between the Company and Connecticut |
||||
|
10.27.1 |
Supplementary Power Contract dated March 1, 1978. (Exhibit C-94, 1982 Form 10-K, File No. 1-8222) |
||||
|
10.27.2 |
Amendment dated August 22, 1980. (Exhibit C-95, 1982 Form 10-K, File No. 1-8222) |
||||
|
10.27.3 |
Amendment dated October 15, 1982. (Exhibit C-96, 1982 Form 10-K, File No. 1-8222) |
||||
|
10.27.4 |
Second Supplementary Power Contract dated April 30, 1984. (Exhibit C-115, 1984 Form 10-K, File No. 1-8222) |
||||
|
10.27.5 |
Additional Power Contract dated April 30, 1984. (Exhibit C-116, 1984 Form 10-K, File No. 1-8222) |
||||
|
10.27.6 |
1987 Supplementary Power Contract, dated as of April 1, 1987. (Exhibit 10.27.6, Form 10-Q, June 30, 2000, File No. 1-8222) |
||||
|
10.27.7 |
1996 Amendatory Agreement, dated December 1, 1996. (Exhibit 10.27.7, Form 10-Q, June 30, 2000, File No. 1-8222) |
||||
|
10.27.8 |
2000 Amendatory Agreement, dated May, 2000. (Exhibit 10.27.8, Form 10-Q, June 30, 2000, File No. 1-8222) |
||||
|
10.28 |
Copy of Transmission Contract between the Company and Connecticut Yankee dated as of July 1, 1964. (Exhibit C-65, 1981 Form 10-K, File No. 1-8222) |
||||
|
10.29 |
Copy of Capital Funds Agreement between the Company and Connecticut Yankee dated as of July 1, 1964. (Exhibit C-66, 1981 Form 10-K, File No. 1-8222) |
||||
|
10.29.1 |
Copy of Capital Funds Agreement between the Company and Connecticut Yankee dated as of September 1, 1964. (Exhibit C-67, 1981 Form 10-K, File No. 1-8222) |
||||
|
10.30 |
Copy of Five-Year Capital Contribution Agreement between the Company and Connecticut Yankee dated as of November 1, 1980. (Exhibit C-68, 1981 Form 10-K, File No. 1-8222) |
||||
|
10.31 |
Form of Guarantee Agreement dated as of November 7, 1981, among certain banks, Connecticut Yankee and the Company, relating to revolving credit notes of Connecticut Yankee. (Exhibit C-69, 1981 Form 10-K, File No. 1-8222) |
||||
|
10.32 |
Form of Guarantee Agreement dated as of November 13, 1981, between The Connecticut Bank and Trust Company, as Trustee, and the Company, relating to debentures of Connecticut Yankee. (Exhibit C-70, 1981 Form 10-K, File No. 1-8222) |
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|
Page 140 of 153 |
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|
10.33 |
Form of Guarantee Agreement dated as of November 5, 1981, between Bankers Trust Company, as Trustee of the Vernon Energy Trust, and the Company, relating to Vermont Yankee Nuclear Fuel Sale Agreement. (Exhibit C-71, 1981 Form 10-K, File No. 1-8222) |
||||
|
10.34 |
Preliminary Vermont Support Agreement re Quebec interconnection between Velco and among seventeen Vermont Utilities dated May 1, 1981. (Exhibit C-97, 1982 Form 10-K, File No. 1-8222) |
||||
|
10.34.1 |
Amendment dated June 1, 1982. (Exhibit C-98, 1982 Form 10-K, File No. 1-8222) |
||||
|
10.35 |
Vermont Participation Agreement for Quebec Interconnection between Velco and among seventeen Vermont Utilities dated July 15, 1982. (Exhibit C-99, 1982 Form 10-K, File No. 1-8222) |
||||
|
10.35.1 |
Amendment No. 1 dated January 1, 1986. (Exhibit C-132, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.36 |
Vermont Electric Transmission Company Capital Funds Support Agreement between Velco and among sixteen Vermont Utilities dated July 15, 1982. (Exhibit C-100, 1982 Form 10-K, File No. 1-8222) |
||||
|
10.37 |
Vermont Transmission Line Support Agreement, Vermont Electric Transmission Company and twenty New England Utilities dated December 1, 1981, as amended by Amendment No. 1 dated June 1, 1982, and by Amendment No. 2 dated November 1, 1982. (Exhibit C-101, 1982 Form 10-K, File No. 1-8222) |
||||
|
10.37.1 |
Amendment No. 3 dated January 1, 1986. (Exhibit 10-149, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.38 |
Phase 1 Terminal Facility Support Agreement between New England Electric Transmission Corporation and twenty New England Utilities dated December 1, 1981, as amended by Amendment No. 1 dated as of June 1, 1982 and by Amendment No. 2 dated as of November 1, 1982. (Exhibit C-102, 1982 Form 10-K, File No. 1-8222) |
||||
|
10.39 |
Power Purchase Agreement between Velco and CVPS dated June 1, 1981. (Exhibit C-103, 1982 Form 10-K, File No. 1-8222) |
||||
|
10.40 |
Agreement for Joint Ownership, Construction and Operation of the Joseph C. McNeil Generating Station by and between City of Burlington Electric Department, Central Vermont Realty, Inc. and Vermont Public Power Supply Authority dated May 14, 1982. (Exhibit C-107, 1983 Form 10-K, File No. 1-8222) |
||||
|
10.40.1 |
Amendment No. 1 dated October 5, 1982. (Exhibit C-108, 1983 Form 10-K, File No. 1-8222) |
||||
|
10.40.2 |
Amendment No. 2 dated December 30, 1983. (Exhibit C-109, 1983 Form 10-K, File No. 1-8222) |
||||
|
10.40.3 |
Amendment No. 3 dated January 10, 1984. (Exhibit 10-143, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.41 |
Transmission Service Contract between Central Vermont Public Service Corporation and The Vermont Electric Generation & Transmission Cooperative, Inc. dated May 14, 1984. (Exhibit C-111, 1984 Form 10-K, File No. 1-8222) |
||||
|
10.42 |
Copy of Highgate Transmission Interconnection Preliminary Support Agreement dated April 9, 1984. (Exhibit C-117, 1984 Form 10-K, File No. 1-8222) |
||||
|
10.43 |
Copy of Allocation Contract for Hydro-Quebec Firm Power dated July 25, 1984. (Exhibit C-118, 1984 Form 10-K, File No. 1-8222) |
||||
|
10.43.1 |
Tertiary Energy for Testing of the Highgate HVDC Station Agreement, dated September 20, 1985. (Exhibit C-129, 1985 Form 10-K, File No. 1-8222) |
||||
|
10.44 |
Copy of Highgate Operating and Management Agreement dated August 1, 1984. (Exhibit C-119, 1986 Form 10-K, File No. 1-8222) |
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|
Page 141 of 153 |
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|
10.44.1 |
Amendment No. 1 dated April 1, 1985. (Exhibit 10-152, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.44.2 |
Amendment No. 2 dated November 13, 1986. (Exhibit 10-167, 1987 Form 10-K, File No. 1-8222) |
||||
|
10.44.3 |
Amendment No. 3 dated January 1, 1987. (Exhibit 10-168, 1987 Form 10-K, File No. 1-8222) |
||||
|
10.45 |
Copy of Highgate Construction Agreement dated August 1, 1984. (Exhibit C-120, 1984 Form 10-K, File No. 1-8222) |
||||
|
10.45.1 |
Amendment No. 1 dated April 1, 1985. (Exhibit 10-151, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.46 |
Copy of Agreement for Joint Ownership, Construction and Operation of the Highgate Transmission Interconnection. (Exhibit C-121, 1984 Form 10-K, File No. 1-8222) |
||||
|
10.46.1 |
Amendment No. 1 dated April 1, 1985. (Exhibit 10-153, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.46.2 |
Amendment No. 2 dated April 18, 1985. (Exhibit 10-154, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.46.3 |
Amendment No. 3 dated February 12, 1986. (Exhibit 10-155, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.46.4 |
Amendment No. 4 dated November 13, 1986. (Exhibit 10-169, 1987 Form 10-K, File No. 1-8222) |
||||
|
10.46.5 |
Amendment No. 5 and Restatement of Agreement dated January 1, 1987. (Exhibit 10-170, 1987 Form 10-K, File No. 1-8222) |
||||
|
10.47 |
Copy of the Highgate Transmission Agreement dated August 1, 1984. (Exhibit C-122, 1984 Form 10-K, File No. 1-8222) |
||||
|
10.48 |
Copy of Preliminary Vermont Support Agreement Re: Quebec Interconnection - Phase II dated September 1, 1984. (Exhibit C-124, 1984 Form 10-K, File No. 1-8222) |
||||
|
10.48.1 |
First Amendment dated March 1, 1985. (Exhibit C-127, 1985 Form 10-K, File No. 1-8222) |
||||
|
10.49 |
Vermont Transmission and Interconnection Agreement between New England Power Company and Central Vermont Public Service Corporation and Green Mountain Power Corporation with the consent of Vermont Electric Power Company, Inc., dated May 1, 1985. (Exhibit C-128, 1985 Form 10-K, File No. 1-8222) |
||||
|
10.50 |
Service Contract Agreement between the Company and the State of Vermont for distribution and sale of energy from St. Lawrence power projects ("NYPA Power") dated as of June 25, 1985. (Exhibit C-130, 1985 Form 10-K, File No. 1-8222) |
||||
|
10.50.1 |
Lease and Operating Agreement between the Company and the State of Vermont dated as of June 25, 1985. (Exhibit C-131, 1985 Form 10-K, File No. 1-8222) |
||||
|
10.51 |
System Sales & Exchange Agreement Between Niagara Mohawk Power Corporation and Central Vermont Public Service Corporation dated October 1, 1986. (Exhibit C-133, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.54 |
Transmission Agreement between Vermont Electric Power Company, Inc. and Central Vermont Public Service Corporation dated January 1, 1986. (Exhibit 10-146, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.55 |
1985 Four-Party Agreement between Vermont Electric Power Company, Central Vermont Public Service Corporation, Green Mountain Power Corporation and Citizens Utilities dated July 1, 1985. (Exhibit 10-147, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.55.1 |
Amendment dated February 1, 1987. (Exhibit 10-171, 1987 Form 10-K, File No. 1-8222) |
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|
Page 142 of 153 |
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|
10.56 |
1985 Option Agreement between Vermont Electric Power Company, Central Vermont Public Service Corporation, Green Mountain Power Corporation and Citizens Utilities dated December 27, 1985. (Exhibit 10-148, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.56.1 |
Amendment No. 1 dated September 28, 1988. (Exhibit 10-182, 1988 Form 10-K, File No. 1-8222) |
||||
|
10.56.2 |
Amendment No. 2 dated October 1, 1991. (Exhibit 10.56.2, 1991 Form 10-K, File No. 1-8222) |
||||
|
10.56.3 |
Amendment No. 3 dated December 31, 1994. (Exhibit 10.56.3, 1994 Form 10-K, File No. 1-8222) |
||||
|
10.56.4 |
Amendment No. 4 dated December 31, 1996. (Exhibit 10.56.4, 1996 Form 10-K, file No. 1-8222) |
||||
|
10.57 |
Highgate Transmission Agreement dated August 1, 1984 by and between the owners of the project and the Vermont electric distribution companies. (Exhibit 10-156, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.57.1 |
Amendment No. 1 dated September 22, 1985. (Exhibit 10-157, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.58 |
Vermont Support Agency Agreement re: Quebec Interconnection - Phase II between Vermont Electric Power Company, Inc. and participating Vermont electric utilities dated June 1, 1985. (Exhibit 10-158, 1986 Form 10K, File No. 1-8222) |
||||
|
10.58.1 |
Amendment No. 1 dated June 20, 1986. (Exhibit 10-159, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.59 |
Indemnity Agreement B-39 dated May 9, 1969 with amendments 1-16 dated April 17, 1970 thru April 16, 1985 between licensees of Millstone Unit No. 3 and the Nuclear Regulatory Commission. (Exhibit 10-161, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.59.1 |
Amendment No. 17 dated November 25, 1985. (Exhibit 10-162, 1986 Form 10-K, File No. 1-8222) |
||||
|
10.62 |
Contract for the Sale of 50MW of firm power between Hydro-Quebec and Vermont Joint Owners of Highgate Facilities dated February 23, 1987. (Exhibit 10-173, 1987 Form 10-K, File No. 1-8222) |
||||
|
10.63 |
Interconnection Agreement between Hydro-Quebec and Vermont Joint Owners of Highgate facilities dated February 23, 1987. (Exhibit 10-174, 1987 Form 10-K, File No. 1-8222) |
||||
|
10.63.1 |
Amendment dated September 1, 1993 (Exhibit 10.63.1, 1993 Form 10-K, File No. 1-8222) |
||||
|
10.64 |
Firm Power and Energy Contract by and between Hydro-Quebec and Vermont Joint Owners of Highgate for 500MW dated December 4, 1987. (Exhibit 10-175, 1987 Form 10-K, File No. 1-8222) |
||||
|
10.64.1 |
Amendment No. 1 dated August 31, 1988. (Exhibit 10-191, 1988 Form 10-K, File No. 1-8222) |
||||
|
10.64.2 |
Amendment No. 2 dated September 19, 1990. (Exhibit 10-202, 1990 Form 10-K, File No. 1-8222) |
||||
|
10.64.3 |
Firm Power & Energy Contract dated January 21, 1993 by and between Hydro-Quebec and Central Vermont Public Service Corporation for the sale back of 25 MW of power. (Exhibit 10.64.3, 1992 Form 10-K, File No. 1-8222) |
||||
|
10.64.4 |
Firm Power & Energy Contract dated January 21, 1993 by and between Hydro-Quebec and Central Vermont Public Service Corporation for the sale back of 50 MW of power. (Exhibit 10.64.4, 1992 Form 10-K, File No. 1-8222) |
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|
Page 143 of 153 |
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|
10.66 |
Hydro-Quebec Participation Agreement dated April 1, 1988 for 600 MW between Hydro-Quebec and Vermont Joint Owners of Highgate. (Exhibit 10-177, 1988 Form 10-K, File No. 1-8222) |
||||
|
10.66.1 |
Hydro-Quebec Participation Agreement dated April 1, 1988 as amended and restated by Amendment No. 5 thereto dated October 21, 1993, among Vermont utilities participating in the purchase of electricity under the Firm Power and Energy Contract by and between Hydro-Quebec and Vermont Joint Owners of Highgate. (Exhibit 10.66.1, 1997 Form 10-Q, March 31, 1997, File. No. 1-8222) |
||||
|
10.67 |
Sale of firm power and energy (54MW) between Hydro-Quebec and Vermont Utilities dated December 29, 1988. (Exhibit 10-183, 1988 Form 10-K, File No. 1-8222) |
||||
|
10.75 |
Receivables Purchase Agreement between Central Vermont Public Service Corporation, Central Vermont Public Service Corporation as Service Agent and The First National Bank of Boston dated November 29, 1988. (Exhibit 10-192, 1988 Form 10-K) |
||||
|
10.75.1 |
Agreement Amendment No. 1 dated December 21, 1988 Exhibit 10.75.1, 1993 Form 10-K, File No. 1-8222) |
||||
|
10.75.2 |
Letter Agreement dated December 4, 1989 (Exhibit 10.75.2, 1993 Form 10-K, File No. 1-8222) |
||||
|
10.75.3 |
Agreement Amendment No. 2 dated November 29, 1990 (Exhibit 10.75.3, 1993 Form 10-K, File No. 1-8222) |
||||
|
10.75.4 |
Agreement Amendment No. 3 dated November 29, 1991 (Exhibit 10.75.4, 1993 Form 10-K, File No. 1-8222) |
||||
|
10.75.5 |
Agreement Amendment No. 4 dated November 29, 1992 (Exhibit 10.75.5, 1993 Form 10-K, File No. 1-8222) |
||||
|
10.75.6 |
Agreement Amendment No. 5 dated November 29, 1993 (Exhibit 10.75.6, 1997 Form 10-K, File No. 1-8222) |
||||
|
10.75.7 |
Agreement Amendment No. 6 dated November 29, 1994 (Exhibit 10.75.7, 1997 Form 10-K, File No. 1-8222) |
||||
|
10.75.8 |
Agreement Amendment No. 7 dated November 29, 1995 (Exhibit 10.75.8, 1997 Form 10-K, File No. 1-8222) |
||||
|
10.75.9 |
Agreement Amendment No. 8 dated February 5, 1997 (Exhibit 10.75.9, 1997 Form 10-K, File No. 1-8222) |
||||
|
10.75.10 |
Agreement Amendment No. 9 dated February 2, 1998 (Exhibit 10.75.10, 1997 Form 10-K, File No. 1-8222) |
||||
|
10.83 |
Credit Agreement Dated As of November 5, 1997, see exhibit 4-56; 10.83.1 and 10.83.2, see exhibit 4-56.1 and 4-56.2. |
||||
|
10.84 |
Settlement Agreement effective dated June 1, 2001 to which the Company is a party re: Vermont Yankee Nuclear Power Corporation. (Exhibit 10-84, Form 10-Q, June 30, 2001, File No. 1-8222) |
||||
|
10.85 |
Form of Secondary Purchaser Settlement Agreement dated December 6, 2001, with Acknowledgement and Consent of VELCO, among the Company, Green Mountain Power Corporation and each of: City of Burlington Electric Department; Village of Lyndonville Electric Department; Village of Northfield Electric Department; Village of Orleans Electric Department; Town of Hardwick Electric Department; Town of Stowe Electric Department; and, Washington Electric Cooperative. (Exhibit 10-85, 2001 Form 10-K, File No. 1-8222) |
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|
Page 144 of 153 |
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|
10.86 |
Purchase and Sale Agreement by and between Public Service Company of New Hampshire and Central Vermont Public Service Corporation/Connecticut Valley Electric Company Inc. dated January 31, 2003. (Exhibit 10-86, Form 10-Q, March 31, 2003, File No. 1-8222) |
||||
|
10.87 |
Settlement Agreement by and between Connecticut Valley Electric Company Inc. Central Vermont Public Service Corporation The Governor's Office of Energy and Community Services The Staff of the New Hampshire Public Utilities Commission Office of Consumer Advocate The City of Claremont, New Hampshire New Hampshire Legal Assistance dated January 31, 2003. (Exhibit 10-87, Form 10-Q, March 31, 2003, File No. 1-8222) |
||||
|
10.88 |
Agreement between Central Vermont Public Service Corporation and Local Union No. 300 International Brotherhood of Electrical Workers Effective as of January 1, 2005. (Exhibit 10.88, Current Report on Form 8-K Filed January 5, 2005, File No. 1-8222) |
||||
|
10.89 |
Financing Agreement among Catamount Sweetwater Holdings LLC; UFJ Bank Limited; Bayerische Landesbank; and The Lenders Parties Hereto dated as of July 12, 2005. (Catamount Sweetwater Holdings LLC is a wholly owned subsidiary of Catamount Energy Corporation. Catamount Energy Corporation is a wholly owned subsidiary of Catamount Resources Corporation. Catamount Resources Corporation is a wholly owned subsidiary of Central Vermont Public Service Corporation. (Exhibit 10.89, Current Report on Form 8-K Filed July 15, 2005, File No. 1-8222) |
||||
|
10.90 |
Stock Subscription Agreement by and among CEC Wind Acquisition, LLC, Catamount Energy Corporation, Catamount Resources Corporation, and Central Vermont Public Service Corporation, dated October 12, 2005. (Exhibit 10.90, Current Report on Form 8-K Filed October 18, 2005, File No. 1-8222) |
||||
|
10.90.1 Form of the Amended and Restated Certificate of Incorporation. (Exhibit 10.90.1, Current |
|||||
|
10.90.2 Stockholders' Agreement among Catamount Energy Corporation and the stockholders parties |
|||||
|
10.90.3 Registration Rights Agreement among Catamount Energy Corporation and the stockholders |
|||||
|
10.90.4 Put Option Purchase and Sale Agreement between Central Vermont Public Service Corporation |
|||||
|
10.90.5 Exercise of Put Option Notice. (Exhibit 10.90.5, Current Report on Form 8-K Filed November |
|||||
|
10.91 |
Credit Agreement dated as of October 21, 2005 between Central Vermont Public Service Corporation as Borrower and JPMorgan Chase Bank, N.A. as Lender. (Exhibit 10.91, Current Report on Form 8-K Filed November 1, 2005, File No. 1-8222) |
||||
|
10.92 |
Voting Agreement and Irrevocable Proxy between Central Vermont Public Service Corporation and Mr. Jerry Zucker. (Exhibit 10.92, Current Report on Form 8-K Filed March 16, 2006, File No. 1-8222) |
||||
|
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS |
|||||
|
A 10.68 |
Stock Option Plan for Non-Employee Directors dated July 18, 1988. (Exhibit 10-184, 1988 Form 10-K, File No. 1-8222) |
||||
|
A 10.69 |
Stock Option Plan for Key Employees dated July 18, 1988. (Exhibit 10-185, 1988 Form 10-K, File No. 1-8222) |
||||
|
Page 145 of 153 |
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|
A 10.70 |
Officers Supplemental Insurance Plan authorized July 9, 1984. (Exhibit 10-186, 1988 Form 10-K, File No. 1-8222) |
||||
|
A 10.71 |
Officers Supplemental Deferred Compensation Plan dated November 4, 1985. (Exhibit 10-187, 1988 Form 10-K, File No. 1-8222) |
||||
|
A 10.71.1 |
Amendment dated October 2, 1995. (Exhibit 10.71.1, 1995 Form 10-K, File No. 1-8222) |
||||
|
A 10.72 |
Directors' Supplemental Deferred Compensation Plan dated November 4, 1985. (Exhibit 10-188, 1988 Form 10-K, File No. 1-8222) |
||||
|
A 10.72.1 |
Amendment dated October 2, 1995. (Exhibit 10.72.1, 1995 Form 10-K, File No. 1-8222) |
||||
|
A 10.73 |
Management Incentive Compensation Plan as adopted September 9, 1985. (Exhibit 10-189, 1988 Form 10-K, File No. 1-8222) |
||||
|
A 10.73.1 |
Revised Management Incentive Plan as adopted February 5, 1990. (Exhibit 10-200, 1989 Form |
||||
|
A 10.73.2 |
Revised Management Incentive Plan dated May 2, 1995. (Exhibit 10.73.2, 1995 Form 10-K, |
||||
|
A 10.74 |
Officers' Change of Control Agreements as approved October 3, 1988. (Exhibit 10-190, 1988 Form 10-K, File No. 1-8222) |
||||
|
A 10.78 |
Stock Option Plan for Non-Employee Directors dated April 30, 1993 (Exhibit 10.78, 1993 Form 10-K, File No. 1-8222) |
||||
|
A 10.79 |
Officers Insurance Plan dated November 15, 1993 (Exhibit 10.79, 1993 Form 10-K, File No. 1-8222) |
||||
|
A 10.79.1 |
Amendment dated October 2, 1995. (Exhibit No. 10.79.1, 1995 Form 10-K, File No. 1-8222) |
||||
|
A 10.80 |
Directors' Supplemental Deferred Compensation Plan dated January 1, 1990 (Exhibit 10.80, 1993 Form 10-K, File No. 1-8222) |
||||
|
A 10.80.1 |
Amendment dated October 2, 1995. (Exhibit No. 10.80.1, 1995 Form 10-K, File No. 1-8222) |
||||
|
A 10.81 |
Officers' Supplemental Deferred Compensation Plan dated January 1, 1990 (Exhibit 10.81, 1993 Form 10-K, File No. 1-8222) |
||||
|
A 10.82 |
Management Incentive Plan for Executive Officers dated January 1, 1997. (Exhibit 10.82, 1996 Form 10-K, File No. 1-8222) |
||||
|
A 10.83 |
Management Incentive Plan for Executive Officers dated January 1, 1998 (Exhibit A10.83, Form 10-Q, March 31, 1998, File No. 1-8222) |
||||
|
A 10.84 |
Officers' Change of Control Agreement dated January 1, 1998 (Exhibit 10.84, 1998 Form 10-K, File No. 1-8222) |
||||
|
A 10.85 |
Officers' Supplemental Retirement and Deferred Compensation Plan as Amended and Restated Effective January 1, 1998 (Exhibit 10.85, 1998 Form 10-K, File No. 1-8222) |
||||
|
A 10.85.1 Officers' Supplemental Retirement and Deferred Compensation Plan, Amended and |
|||||
|
A 10.86 |
1993 Stock Option Plan for Non-employee Directors (Exhibit 28 to Registration Statement, Registration 33-62100) |
||||
|
Page 146 of 153 |
|||||
|
A 10.87 |
1997 Stock Option Plan for Key Employees (Exhibit 4.3 to Registration Statement, Registration 333-57001) |
||||
|
A 10.88 |
1997 Restricted Stock Plan for Non-employee Directors and Key Employees (Exhibit 4.3 to Registration Statement, Registration 333-57005) |
||||
|
A 10.89 |
Management Incentive Plan for Executive Officers dated January 1, 1999. (Exhibit A10.89, Form 10-Q, March 31, 1999, File No. 1-8222) |
||||
|
A 10.90 |
Performance Share Incentive Plan dated effective January 1, 1999. (Exhibit A10.90, Form 10-Q, June 30, 1999, File No. 1-8222) |
||||
|
A 10.91 |
Management Incentive Plan for Executive Officers dated January 1, 2000. (Exhibit A10.91, Form 10-Q, March 31, 2000, File No. 1-8222) |
||||
|
A 10.92 |
Officers' Change of Control Agreements as approved April 3, 2000. (Exhibit A10.92, Form 10-Q, March 31, 2000, File No. 1-8222) |
||||
|
A 10.93 |
Management Incentive Plan for Executive Officers dated January 1, 2001. (Exhibit A10.93, Form 10-Q, March 31, 2001, File No. 1-8222) |
||||
|
A 10.94 |
Termination Agreement between the Company and Craig A. Parenzan. (Exhibit A10.94, Form 10-Q, March 31, 2001, File No. 1-8222) |
||||
|
A 10.95 |
2000 Stock Option Plan for Key Employees. (Form S-8 Registration Statement, Registration 333-39664) |
||||
|
A 10.96 |
Form of Deferred Compensation Plan for Officers and Directors. (Exhibit A10.96, Form 10-Q, March 31, 2002, File No. 1-8222) |
||||
|
A 10.96.1 Deferred Compensation Plan for Officers and Directors of Central Vermont Public Service |
|||||
|
A 10.97 |
Management Incentive Plan for Executive Officers dated January 1, 2002. (Exhibit A10.97, Form 10-Q, March 31, 2002, File No. 1-8222) |
||||
|
A 10.97.1 Management Incentive Plan, Effective as of January 1, 2005. (Exhibit A10.97.1, 2004 Form |
|||||
|
* A 10.97.2 Management Incentive Plan, Effective as of January 1, 2006. |
|||||
|
A 10.98 |
Change-In-Control Agreement dated April 15, 2002 between the Company and Jean H. Gibson. (Exhibit A10.98, Form 10-Q, March 31, 2002, File No. 1-8222) |
||||
|
A 10.99 |
2002 Long-Term Incentive Plan. (Form S-8 Registration Statement, Registration 333-102008) |
||||
|
A 10.100 |
Performance Share Incentive Plan dated effective January 1, 2004. (Exhibit A10.100, Form 10-Q, June 30, 2004, File No. 1-8222) |
||||
|
A 10.100.1 Performance Share Incentive Plan, Effective January 1, 2005. (Exhibit A10.100.1, 2004 |
|||||
|
* A 10.100.2 Performance Share Incentive Plan, Effective January 1, 2006. |
|||||
|
A 10.101 |
Form of Central Vermont Public Service Performance Share Agreement Pursuant to the Performance Share Incentive Plan. (Exhibit A10.101, Form 10-Q, September 30, 2004, File No. 1-8222) |
||||
|
Page 147 of 153 |
|||||
|
A 10.102 |
Form of Central Vermont Public Service Corporation Stock Option Agreement Pursuant to the 2002 Long-Term Incentive Plan. (Exhibit A10.102, Form 10-Q, September 30, 2004, File No. 1-8222) |
||||
|
A 10.103 |
Form of Central Vermont Public Service Corporation Stock Option Agreement Pursuant to the 2000 Stock Option Plan for Key Employees of Central Vermont Public Service Corporation. (Exhibit A10.103, Form 10-Q, September 30, 2004, File No. 1-8222) |
||||
|
A 10.104 |
Form of Central Vermont Public Service Corporation Stock Option Agreement Pursuant to the 1997 Stock Option Plan for Key Employees of Central Vermont Public Service Corporation. (Exhibit A10.104, Form 10-Q, September 30, 2004, File No. 1-8222) |
||||
|
A 10.105 |
Form of Indemnity Agreement between Directors and Executive Officers and Central Vermont Public Service Corporation. (Exhibit A10.105, 2004 Form 10-K, File No. 1-8222) |
||||
|
A 10.106 |
Change-In-Control Agreement dated as of November 17, 2003 between the Company and Dale A. Rocheleau. (Exhibit A10.106, 2004 Form 10-K, File No. 1-8222) |
||||
|
A 10.107 |
Catamount Energy Corporation 2002 Project Incentive Compensation Plan effective January 1, 2002. |
||||
|
A 10.107.1 Amended and Restated Catamount Energy Corporation 2002 Project Incentive |
|||||
|
A 10.108 |
Restricted Stock Award Agreement dated February 27, 2006 between the Company and Robert H. Young. (Exhibit A10.108, Current Report on Form 8-K filed March 3, 2006, File No. 1-8222) |
||||
|
A - Compensation related plan, contract, or arrangement. |
|||||
|
12 |
Statements Regarding Computation of Ratios |
|
* |
12.1 Statements Regarding Computation of Ratios |
|
21 |
Subsidiaries of the Registrant |
|
* |
21.1 List of Subsidiaries of Registrant |
|
23 |
Consent of Independent Registered Public Accounting Firm |
|
* |
23.1 Consent of Independent Registered Public Accounting Firm |
|
24 |
Power of Attorney |
|
* |
24.1 Power of Attorney executed by Directors and Officers of Company |
|
* |
31.1 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
* |
31.2 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
* |
32.1 Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant |
|
* |
32.2 Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant |
Page 148 of 153
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Central Vermont Public Service Corporation
We have audited the consolidated financial statements of Central Vermont Public Service Corporation and subsidiaries (the "Company") as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, and the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, and have issued our reports thereon dated March 30, 2006 (our report on the consolidated financial statements expresses an unqualified opinion and includes explanatory paragraphs regarding the sale of the Company's interest in Catamount Energy Corporation and regarding the restatement of the 2004 and 2003 consolidated financial statements and our report on internal control over financial reporting expresses an adverse opinion on the effectiveness of internal control over financial reporting because of a material weakness); such consolidated financial statements and reports are included in this Form 10-K. Our audits also included the consolidated financial statement schedules of the Company, referred to as Schedule II, listed in Item 15. These consolidated financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Boston, Massachusetts
March 30, 2006
Page 149 of 153
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 2005
|
Additions |
|||||
|
Balance at |
Charged to |
Charged |
|
Balance at |
|
|
Reserves deducted from assets to |
|||||
|
$118,657 (1) |
$1,414,379 (3) |
||||
|
479,489 (2) |
|||||
|
433,169 (2a) |
|||||
|
Reserve for uncollectible |
|
|
|
|
|
|
Discontinued Operations - |
|
|
|
|
|
|
Accumulated depreciation of |
|||||
|
Rental water heater program |
$3,550,429 |
$171,345 |
- |
$291,770 (4) |
$3,430,004 |
|
Other |
817,300 |
30,179 |
- |
- |
633,487 |
|
- |
(213,992)(5) |
- |
- |
|
|
|
Discontinued Operations - |
|
|
|
|
|
|
$4,877,179 |
$27,821 |
- |
$841,509 |
$4,063,491 |
|
|
Reserves shown separately: |
|||||
|
Injuries and damages reserve (6) |
$225,580 |
- |
- |
$25,580 |
$200,000 |
|
Environmental Reserve |
$6,064,654 |
- |
- |
$638,544 (7) |
$5,426,110 |
(1) Amount collected from collection agencies
(2) Collections of accounts previously written off
(2a) Reserve against rents
(3) Uncollectible accounts written off
(4) Retirement and sale of rental water heaters
(5) Transfer out of utility property due to reclassification of assets
(6) This represents the Company's long-term reserve for injuries & damages needed to meet the Company's liability not covered by insurance. The Company is self-insured up to $200,000; therefore, any activity for the year is charged to expense and recorded to the current liability.
(7) Environmental remediation payments from reserve.
Page 150 of 153
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 2004
|
Additions |
|||||
|
Balance at |
Charged to |
Charged |
|
Balance at |
|
|
Reserves deducted from assets to |
|||||
|
$153,959 (1) |
|||||
|
|
479,295 (2) |
$2,248,648 (3) |
|||
|
|
189,412 (2a) |
(50,703) (3a) |
|||
|
Reserve for uncollectible |
|
|
|
|
|
|
Discontinued Operations- |
|
|
|
|
|
|
Accumulated depreciation of |
|||||
|
Rental water heater program |
$3,661,113 |
$168,438 |
- |
$279,122 (4) |
$3,550,429 |
|
Other |
290,037 |
13,695 |
- |
- |
817,300 |
|
Discontinued Operations - |
|
|
|
|
|
|
|
513,568 (5) |
- |
- |
- |
|
|
$4,412,778 |
$743,523 |
$279,122 |
$4,877,179 |
||
|
Reserves shown separately: |
|||||
|
Injuries and damages reserve (6) |
$225,580 |
- |
- |
- |
$225,580 |
|
Environmental Reserve |
$7,190,633 |
- |
- |
$1,125,979 (7) |
$6,064,654 |
(1) Amount collected from collection agencies
(2) Collections of accounts previously written off
(2a) Charged against revenue
(2b) Reserve against rents
(3) Uncollectible accounts written off
(3a) Amount related to Connecticut Valley discontinued operations
(4) Retirement and sale of rental water heaters
(5) Transfer from utility property due to reclassification of assets
(6) This represents the Company's long-term reserve for injuries & damages needed to meet the Company's liability not covered by insurance. The Company is self-insured up to $200,000; therefore, any activity for the year is charged to expense and recorded to the current liability.
(7) Environmental remediation payments from reserve.
Page 151 of 153
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 2003
|
Additions |
|||||
|
Balance at |
Charged to |
Charged |
|
Balance at |
|
|
Reserves deducted from assets to |
|||||
|
$121,268 (1) |
|||||
|
|
495,358 (2) |
$1,948,451 (3) |
|||
|
426,692 (2a) |
(4,024) (3a) |
||||
|
Reserve for uncollectible |
|
|
|
|
|
|
Accumulated depreciation of |
|||||
|
Rental water heater program |
$3,755,167 |
$169,302 |
- |
$263,356 (4) |
$3,661,113 |
|
Other |
276,346 |
13,691 |
- |
- |
290,037 |
|
Discontinued Operations - |
|
|
|
|
|
|
$4,431,059 |
$245,075 |
- |
$263,356 |
$4,412,778 |
|
|
Reserves shown separately: |
|||||
|
Injuries and damages reserve (5) |
$225,580 |
- |
- |
- |
$225,580 |
|
Environmental Reserve |
$7,451,789 |
- |
- |
$261,756 (6) |
$7,190,633 |
(1) Amount collected from collection agencies
(2) Collections of accounts previously written off
(2a) Charged against revenue
(3) Uncollectible accounts written off
(3a) Amount related to Connecticut Valley discontinued operations
(4) Retirement and sale of rental water heaters
(5) This represents the Company's long-term reserve for injuries & damages needed to meet the Company's liability not covered by insurance. The Company is self-insured up to $200,000; therefore, any activity for the year is charged to expense and recorded to the current liability.
(6) Environmental remediation payments from reserve.
Page 152 of 153
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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: /s/ Edmund F. Ryan
Edmund F. Ryan
Acting Chief Financial Officer, and Treasurer
March 31, 2006
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 31, 2006.
|
Signature |
Title |
|
Robert H. Young* /s/ Edmund F. Ryan |
President and Chief Executive Officer, and Director (Principal Executive Officer) |
By: /s/ Edmund F. Ryan
(Edmund F. Ryan)
Attorney-in-Fact for each of the persons indicated.
* Such signature has been affixed pursuant to a Power of Attorney filed as an exhibit hereto and incorporated herein
by reference thereto.
Page 153 of 153
|
EXHIBIT A 10.97.2 CENTRAL VERMONT PUBLIC SERVICE CORPORATION Effective as of January 1, 2006
Execution Copy
CENTRAL VERMONT PUBLIC SERVICE CORPORATION Effective as of January 1, 2006 TABLE OF CONTENTS |
|
ARTICLE I |
INTRODUCTION AND PURPOSE |
Page |
|
|
1.1 |
Purpose of the Plan |
1 |
|
|
ARTICLE II |
DEFINITIONS |
||
|
2.1 |
"Annual Incentive Award" |
2 |
|
|
ARTICLE III |
PARTICIPATION |
||
|
3.1 |
Participation |
4 |
|
|
ARTICLE IV |
PERFORMANCE GOALS AND AWARD OPPORTUNITIES |
||
|
4.1 |
Performance Goals |
5 |
|
|
ARTICLE V |
DETERMINATION AND PAYMENT OF ANNUAL INCENTIVE AWARDS |
||
|
5.1 |
Timing and Determination of Annual Incentive Awards |
8 |
|
|
ARTICLE VI |
ADMINISTRATION |
||
|
6.1 |
Committee |
10 |
|
|
ARTICLE VII |
MISCELLANEOUS |
||
|
7.1 |
Amendment |
11 |
|
|
ARTICLE I INTRODUCTION AND PURPOSE |
|
|
1.1 |
Purpose of the Plan . The Central Vermont Public Service Corporation Management Incentive Plan (the "Plan") is an incentive compensation program for eligible officers of Central Vermont Public Service Corporation (the "Company"). The purpose of the Plan is to focus the efforts of the Executive Team in achievement of challenging and demanding objectives. The Plan is designed and intended to further the attainment of the customer service, financial, process improvement and employee related objectives of the Company, to assist the Company in attracting and retaining highly qualified executives, and to enhance the mutual interest of customers, shareholders and eligible officers of the Company. In addition, this Plan supports the Company's performance oriented culture. |
|
ARTICLE II DEFINITIONS |
|
|
2.1 |
"Annual Incentive Award" shall mean a cash incentive payable to a Participant under the terms of this Plan. |
|
2.2 |
"Award Payment Date" shall mean, for each Performance Period, the date that the amount of the Annual Incentive Award for that Performance Period shall be paid to the Participant under Article 5 of the Plan. |
|
2.3 |
"Base Salary" shall mean a Participant's annualized salary for the Performance Period for which the amount of an Annual Incentive Award is being determined. |
|
2.4 |
"Board" or "Board of Directors" shall mean the Board of Directors of the Company. |
|
2.5 |
"Change in Control" shall have the same meaning as the term defined in the Change of Control Agreement approved by the Employer's Board of Directors on April 3, 2000. |
|
2.6 |
"Code" shall mean the Internal Revenue Code of 1986, as amended, and references to particular provisions of the Code shall include any amendments thereto or successor provisions and any rules and regulations promulgated thereunder. |
|
2.7 |
"Committee" shall mean the Compensation Committee of the Board of Directors of the Company or any other duly established committee or subcommittee appointed by the Board for purposes of this Plan. |
|
2.8 |
"Company" shall mean Central Vermont Public Service Corporation, a Vermont corporation. |
|
2.9 |
"Effective Date" shall mean January 1, 2006. The Plan shall be effective for the Performance Period beginning on January 1, 2006. |
|
2.10 |
"Eligible Employee " shall mean the Chief Executive Officer (CEO) of Central Vermont Public Service Corporation and other executive officers of the Company. |
|
2.11 |
"For Cause" shall mean, but is not limited to, fraud, dishonesty, theft of corporate assets, gross misconduct, failure to substantially perform assigned duties, material breach of any agreement with the Company, the commission of a crime or act which involves dishonesty or moral turpitude, or willful misconduct which subjects the Company to potential liability. |
|
2.12 |
"Participant" for a Performance Period shall mean each Eligible Employee who is an Eligible Employee for that Performance Period. |
|
2.13 |
"Performance Goals" shall mean the measures of the Company's performance as defined in Section 4.1 of this Plan that must be met for any Participant to receive any Annual Incentive Award under this Plan, as provided in Section 4.1. |
|
2.14 |
"Performance Period" shall mean the taxable year of the Company or any other period designated by the Committee with respect to which an Annual Incentive Award may be granted. |
|
2.15 |
"Permanent and Total Disability" shall mean any disability that would qualify as permanent and total disability under any long term disability policy sponsored by the Company. |
|
2.16 |
"Plan" shall mean this Central Vermont Public Service Corporation Management Incentive Plan, as it may be amended from time to time. |
|
2.17 |
"Target Potential" shall mean the targeted percentage of Base Salary for each Participant. |
|
ARTICLE III PARTICIPATION |
|
|
3.1 |
Participation . An Eligible Employee will become a Participant in this Plan as of the later of the Effective Date, the Eligible Employee's date of hire or the date the individual becomes an Eligible Employee.An Eligible Employee who is a Participant for the entire length of a Performance Period shall be eligible for consideration for an Annual Incentive Award with respect to that Performance Period. The Committee may provide a prorated Annual Incentive Award for an Eligible Employee who becomes a Participant during the Performance Period. |
|
ARTICLE IV PERFORMANCE GOALS AND AWARD OPPORTUNITIES |
|||
|
4.1 |
Performance Goals . The measures of Performance Goals are established as follows: |
||
|
a. |
Company Balanced Business Performance. Measures the overall company performance, through a balanced set of measures established annually, including customer satisfaction, financial performance, process improvement and employee measures. |
||
|
b. |
Individual Performance. Based on advice and recommendation from the Chief Executive Officer for those reporting to him, the Compensation Committee and Board of Directors evaluate each Participant's individual performance compared to performance objectives set early in the year. The Chairman and Committee evaluate the Chief Executive Officer's performance versus his performance objectives. This individual performance measure is at the full discretion of the Board. |
||
|
Company and Individual Performance Goals will be established in writing for each Performance Period by no later than the first quarter of the Performance Period. The Company Balanced Business Performance is weighted 80%, and Individual Performance has a 20% weight. |
|||
|
4.2 |
Performance Levels . Company measures described in Section 4.1 will be established for three performance levels: threshold, target and maximum. These levels are set based on the following probabilities: 90% probability of achieving the threshold level; 50% probability of achieving target level; and 10% probability of achieving the maximum level. |
||
|
4.3 |
Participant Goals . Participants will have a combination of Company Balanced Business Performance and Individual Performance measured goals used in determining any Annual Incentive Award as described in 4.1 above. |
||
|
4.4 |
Target Potential . For each time period, the Committee and Board set the target potential measured as a percentage of Base Salary for each eligible employee. The target level of incentive award for the Plan is as follows:
The maximum payout is capped at two times target potential. |
||
|
4.5 |
Amount of Award . Following the completion of the Performance Period, the Committee shall undertake or direct a calculation of actual performance for each of the Company and individual measures for such performance year, based on criteria used in the measures. The actual award opportunity for each Participant will be determined as follows: |
||
|
a. |
For each measure in the scorecard for the Company Balanced Business Performance threshold, target and maximum performance levels are defined. Actual performance is determined and linear interpolation is used between three points where achieving the threshold level of performance results in no payout; the target level of performance results in 100% of the target payout and achieving the maximum level of performance results in a 200% of the target payout. The individual performance rating between one and five is translated where three is the threshold, four is target and five is the maximum. |
||
|
b. |
A weighted average of the target incentive multiplier for each component of the Company Balanced Business Performance measure will be determined. A weighted average rating for each component of the Individual Performance measure will also be determined. |
||
|
c. |
A weighted average of the target incentive multiplier for the Company and individual performance measures will be determined, based on the weightings described in Section 4.1 for Eligible Employees. |
||
|
d. |
The final target incentive multiplier will be multiplied by the Participant's Target potential to determine the Annual Incentive Award percentage. Unless the financial measures of the Company Balanced Business Performance meet the target goal, the final incentive multiplier cannot exceed 100% of the target incentive multiplier overall. |
||
|
e. |
The Annual Incentive Award percentage will then be multiplied by the Participant's Base Salary to determine the Participant's Annual Incentive Award, prior to any further reductions as described in this Plan, including Sections 5.2, 5.3, 5.4, 5.5 and 6.2. |
||
|
ARTICLE V DETERMINATION AND PAYMENT OF ANNUAL INCENTIVE AWARDS |
|||
|
5.1 |
Timing and Determination of Annual Incentive Awards . Following the completion of a Performance Period, the Committee shall undertake or direct an evaluation of performance results as compared to the appropriate performance criteria established for the Performance Period as determined in Article IV. The Committee will report to the Board with respect to achievement of previously approved Company and individual performance targets for that Performance Period, and will submit to the Board its recommendations as to the appropriate award payment levels for each eligible participant.Recommendations of the Committee, with such modifications as may be made by the Board, will be binding on all Participants. No Annual Incentive Award may be paid without the prior approval of the Committee. Any Annual Incentive Awards will be paid on the Award Payment Date, which shall be as soon as practicable following the end of the Performance Period to which they relate. |
||
|
5.2 |
Short Performance Year . In the event that a determination of an Annual Incentive Award must be made for a Performance Period of less than 12 months, and the year of termination of employment, the determination shall be made in accordance with the provisions of this Plan, except that: |
||
|
a. |
In the year of hire, if hired after the first date a Performance Period begins, or year of termination, retirement, death, or Permanent and Total Disability, the amount otherwise determined under the Plan shall be prorated to reflect the period of time during which the Participant was a Participant in the Plan compared to the total period of time of the Performance Period. |
||
|
b. |
In the year of a Change in Control, the Company will be assumed to have achieved a target performance level prorated by time. |
||
|
5.3 |
Termination, Death, Retirement or Permanent and Total Disability . In the event of the termination, death, retirement, or Permanent and Total Disability of a Participant during a Performance Period, such Participant may, only in the discretion of the Committee, be eligible for a prorated Annual Incentive Award with respect to that Performance Period to the extent the Committee deems appropriate. |
||
|
5.4 |
Change in Control . Notwithstanding any of the Plan provisions to the contrary, if a Change in Control, as defined in the Company's Change of Control Agreement as approved by the Board on April 3, 2000, occurs during a Performance Period, each Participant will, effective as of the date of the Change in Control, become fully vested in his right to receive an Annual Incentive Award, based on the Plan's provisions for such Performance Period in which the Change in Control occurs. |
||
|
5.5 |
Limitation on Right to Payment of Award . Notwithstanding any other Plan provision to the contrary, no Participant shall have a right to receive payment of an Annual Incentive Award under the Plan if, subsequent to the commencement of the Performance Period and prior to the date any award would otherwise be payable, is terminated For Cause. |
||
|
ARTICLE VI ADMINISTRATION |
|||
|
6.1 |
Committee . The Plan shall be operated and administered by the Committee. |
||
|
6.2 |
Authority of the Committee . The Committee shall have full power except as limited by it's Charter, the bylaws of the Company or any restrictions or directions imposed by the Board and subject to the provisions herein, to determine the Performance Goals during each Performance Period, to determine the terms, conditions and amounts of Annual Incentive Awards in a manner consistent with the Plan, and to establish, amend or waive rules and regulations as it deems appropriate for the Plan's administration in a manner consistent with the terms of this Plan. Further, the Committee shall make all other determinations that may be necessary or advisable for the administration of the Plan. The Committee's determinations and interpretations with respect to this Plan shall be binding on all parties. While the Committee may appoint individuals to act on its behalf in the administration of this Plan, the Committee will have the sole, final and conclusive authority to administer, construe and interpret this Plan.The Committee may, for reasons it deems appropriate, in its discretion, determine to delay, disapprove, reduce or eliminate any Participant's Annual Incentive Award as it deems warranted by extraordinary circumstances. |
||
|
6.3 |
Costs . The Company shall pay all costs of administration of the Plan. |
||
|
ARTICLE VII MISCELLANEOUS |
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7.1 |
Amendment . The Committee or the Board may at any time alter or amend any provision of the Plan, provided that no such amendment that would require the consent of the stockholders of the Company pursuant to the Code, or any other applicable law, rule or regulation, shall be effective without such consent. No such amendment which adversely affects in any material way a Participant's rights to, or interest in, an Annual Incentive Award earned through the end of the Performance Period in which such amendment is adopted or becomes effective unless the Participant shall have agreed thereto in writing, unless such amendment is required by applicable law. |
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7.2 |
Termination . The Board may suspend or terminate this Plan at any time, and in the case of such termination, the following provisions of this Section shall apply notwithstanding any other provisions of the Plan to the contrary. In no event shall the suspension or termination of the Plan adversely affect the rights of any Participant to an Annual Incentive Award earned through the end of the Performance Period in which such suspension or termination is adopted or becomes effective, unless the Participant shall have agreed thereto in writing. |
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7.3 |
Employment Rights . The Plan does not constitute a contract of employment and participation in this Plan will not give an Eligible Employee the right to be rehired or retained in the employ of the Company, nor will participation in this Plan give any Eligible Employee any right or claim to any benefit under this Plan, unless such right or claim has specifically accrued under the terms of this Plan. This Plan is not a contract between the Company and its Eligible Employees or Participants. No Participant or other person shall have any claim or right to be granted an Annual Incentive Award under this Plan until such Annual Incentive Award is actually granted. Neither the establishment of this Plan, nor any action taken hereunder, shall be construed as giving any Participant any right to be retained in the employ of the Company. Nothing contained in this Plan shall limit the ability of the Company to make payments or awards to Participants under any other plan, agreement or arrangement. To the extent any provision of this Plan conflicts with any provision of a written agreement between an Employee and the Company, the provisions of the employment agreement shall control. |
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7.4 |
Nonalienation of Benefits . A Participant's right and interest under the Plan may not be assigned or transferred and any attempted assignment or transfer shall be null and void and shall extinguish, in the Company's sole discretion, the Company's obligation under the plan to pay Annual Incentive Awards with respect to the Participant. |
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7.5 |
No Funding . The Plan shall be unfunded. The Company shall not be required to establish any special segregation of assets to assure payment of Annual Incentive Awards. |
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7.6 |
Tax Withholding . The Company shall have the right to deduct from Annual Incentive Awards paid any taxes or other amounts required by law to be withheld. |
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7.7 |
Controlling Laws . All questions pertaining to the construction, regulation, validity and effect of the provisions of the plan shall be determined in accordance with the laws of the State of Vermont, except to the extent superseded by laws of the United States. |
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7.8 |
Gender and Number . Where the context admits, words in the masculine gender shall include the feminine gender, the plural shall include the singular and the singular shall include the plural. |
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7.9 |
Action by the Company . Any action required of or permitted by the Company under this Plan shall be by written resolution of the Board or by a person or persons authorized by written resolution of the Board. |
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7.10 |
Mistake of Fact . Any mistake of fact or misstatement of fact shall be corrected when it becomes known and proper adjustment made by reason thereof. |
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7.11 |
Severability . In the event any provision of this Plan shall be held to be illegal or invalid for any reason, such illegality or invalidity shall not affect the remaining parts of this Plan, and this Plan shall be construed and endorsed as if such illegal or invalid provision had never been contained in this Plan. |
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7.12 |
Effect of Headings . The descriptive headings of the Articles and Sections of this Plan are inserted for convenience of reference and identification only and do not constitute a part of this Plan for purposes of interpretation. |
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7.13 |
No Liability . No member of the Board or the Committee or any officer or employee of the Company or an affiliate shall be personally liable for any action, omission or determination made in good faith in connection with this Plan. The Company shall indemnify and hold harmless the members of the Committee, the Board and the officers and employees of the Company and any affiliates, and each of them, from and against any and all loss which results from liability to which any of them may be subjected by reason of any act or conduct (except willful misconduct or gross negligence) in their official capacities in connection with the administration of this Plan, including all expenses reasonably incurred in their defense, in case the Company fails to provide such defense. By participating in this Plan, each Eligible Employee agrees to release and hold harmless each of the Company and any affiliates (and their respective directors, officers and employees), the Board and the Committee, from and against any tax or other liability, including without limitation, interest and penalties, incurred by the Eligible Employee in connection with his participation in the plan. |
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7.14 |
Successors . All obligations of the Company under the plan with respect to Annual Incentive Awards granted hereunder shall be binding on any successor to the Company, whether the existence of such successor is a result of a direct or indirect purchase, merger, consolidation or otherwise, of all or substantially all of the business and/or assets of the Company. |
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IN WITNESS WHEREOF, the Employer has caused this instrument to be executed by its duly authorized officer as of the 8th day of March , 2006. |
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CENTRAL VERMONT PUBLIC |
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Attest: |
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EXHIBIT A 10.100.2 CENTRAL VERMONT PUBLIC SERVICE CORPORATION PERFORMANCE SHARE INCENTIVE PLAN
Effective January 1, 2006
TABLE OF CONTENTS
Execution Copy CENTRAL VERMONT PUBLIC SERVICE CORPORATION PERFORMANCE SHARE INCENTIVE PLAN TABLE OF CONTENTS |
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Section |
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ARTICLE I |
- PURPOSE |
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ARTICLE II |
- DEFINITIONS |
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"Account" |
2.1 |
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ARTICLE III |
- DETERMINATION OF PERFORMANCE SHARES |
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Designation of PeRS and Related Terms |
3.1 |
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ARTICLE IV |
- PAYMENT OF GRANTS |
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Performance Awards |
4.1 |
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ARTICLE V |
- TERMINATION OF EMPLOYMENT |
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Termination Prior to Completion of Performance Cycle |
5.1 |
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ARTICLE VI |
- ADMINISTRATION |
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Committee |
6.1 |
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ARTICLE VII |
- GENERAL PROVISIONS |
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Payments to Minors and Incompetents |
7.1 |
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ARTICLE I Effective January 1, 2006, Central Vermont Public Service Corporation (the "Employer") has established The Central Vermont Public Service Corporation Performance Share Plan (the "Plan") in order to strengthen the ability of the Employer to attract and retain talented executives and to promote the long-term growth and profitability of the Employer by linking a significant element of executives' compensation opportunity to the performance of the Employer in meeting key operational and shareholder return goals over an extended period of time. Shareholder return and customer satisfaction are both relative to established peer groups. |
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ARTICLE II |
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2.1 |
"Account" means the bookkeeping account established for the Participant under Section 4.2. |
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2.2 |
"Award" means any payment or settlement in respect of a grant of Common Stock or cash or any combination thereof in accordance with Section 4.1. |
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2.3 |
"Board" means the Board of Directors of Central Vermont Public Service Corporation. |
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2.4 |
"Change of Control" shall have the same meaning as the term defined in the Change of Control Agreement approved by the Employer's Board of Directors on April 3, 2000. |
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2.5 |
"Code" means the Internal Revenue Code of 1986, as amended from time to time, and pertinent regulations issued thereunder. Reference to any section of the Code shall include any successor provision thereto. |
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2.6 |
"Committee" means the Compensation Committee appointed by the Board to administer this Plan. The Committee shall be comprised of at least 3 members who qualify as "non-employee directors" within the meaning of Rule 16B-3 promulgated under the Exchange Act. |
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2.7 |
"Common Stock" or "Stock" means the common stock of the Employer. |
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2.8 |
"Comparison Group" means the peer group of companies designated by the Committee as the Comparison Group relative to a given Performance Cycle, as described in Section 3.1(c) |
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2.9 |
"Component" means the part of the plan related to specific measures. Starting in 2005, there are two plan components - one related to relative Total Shareholder Return performance and the second related to meeting key operational measure performance. |
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2.10 |
"Dividend Equivalent" means credits in respect of each PeRS (as defined in section 2.18) or other Stock Unit representing an amount equal to the dividends or distributions declared and paid on a share of Common Stock. |
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2.11 |
"Effective Date" means January 1, 2006, the effective date of this Plan. |
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2.12 |
"Employer" means Central Vermont Public Service Corporation, its subsidiaries and affiliates, and its successor or successors. |
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2.13 |
"Exchange Act" means the Securities Exchange Act of 1934, as amended and in effect from time to time, including all rules and regulations promulgated thereunder. |
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2.14 |
"Fair Market Value" means the average of the high and low quoted selling price for a share of Common Stock of the Company on the applicable date as quoted on the New York Stock Exchange ("NYSE") in the Eastern Edition of the Wall Street Journal or in a similarly readily available public source on such date. If such date shall not be a business day, then the preceding day which shall be a business day, or if no sale takes place, then the average of the bid and asked prices on such date. |
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2.15 |
"Operational Measures" means the specific measures of operational performance chosen for a three year performance cycle. (See Exhibit B.) |
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2.16 |
"Participant" means an executive officer of the Employer who is selected by the Board to participate in this Plan. |
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2.17 |
"Performance Cycle" means the period over which PeRS designated in respect of the Performance Cycle potentially may be earned. Performance Cycles will be three-year periods extending from January 1 of the initial year through December 31 of the third year in the Performance Cycle. Performance Cycles generally will begin each year, and therefore will overlap with one another. |
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2.18 |
"PeRS" means Stock Units which are potentially earnable by a Participant hereunder upon achievement of specific levels of performance for the two plan components as shown in Exhibit A and B. The term is an acronym for "performance-based restricted Stock Units". |
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2.19 |
"Plan" means the Central Vermont Public Service Corporation Performance Share Incentive Plan, as set forth herein, as may be amended from time to time. Shares for this plan were approved by shareholders on May 7, 2002 as the 2002 Long-Term Incentive Plan and any subsequent replacement plans. |
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2.20 |
"Pro Rata Portion" means a portion of shares which is determined by multiplying a predetermined number of PeRS by the ratio of months in a thirty six month performance cycle which the executive was employed by the Company in that cycle. |
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2.21 |
"Stock Unit" is a bookkeeping unit which represents a right to receive one share of Common Stock upon settlement, together with a right to accrual of additional Stock Units as a result of Dividend Equivalents, subject to the terms and conditions of this Plan. Stock Units are arbitrary accounting measures created and used solely for purposes of this Plan, and do not represent ownership rights in the Employer, shares of Common Stock, or any asset of the Employer. |
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2.22 |
"Target PeRS" means a number of PeRS designated as a target number that may be earned by a Participant in respect to a given Performance Cycle plus the number of PeRS resulting directly or indirectly from Dividend Equivalents on the originally designated number of Target PeRS. |
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2.23 |
"Termination of Employment" means the Participant's termination of employment with the Employer. |
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2.24 |
"Total Shareholder Return" means the amount, expressed as a percentage, of market price appreciation or depreciation of a share of common stock plus dividends on a share of Common Stock or on the common stock of a company in the Comparison Group (in both cases excluding extraordinary dividends), assuming dividend reinvestment at the dividend payment date, for the specified 3-year period. |
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ARTICLE III |
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3.1 |
a. |
Designation of PeRS and Related Terms . Not later than 90 days after the beginning of a Performance Cycle, the Committee shall: (i) select employees to participate in the Performance Cycle; (ii) designate, for each such employee Participant, the Target PeRS number such Participant shall have the opportunity to earn in such Performance Cycle related to Total Shareholder Return performance component of the plan; (iii) designate, for each such employee Participant, the Target PeRS number such Participant shall have the opportunity to earn in such Performance cycle related to operational measure performance; (iv) specify the duration of the Performance Cycle; (v) specify a table (Exhibit A), grid or formula that sets forth the amount of PeRS that will be earned in the first component of the Plan corresponding to the percentile rank of the Company's average Total Shareholder Return for the three years ending on the last day of the Performance Cycle as compared to the unweighted average Total Shareholder Return of the Comparison Group for the three years ending on the last day of the Performance Cycle; and (vi) specify a table (Exhibit B) grid or formula that sets forth the amount of PeRS that will be earned corresponding to the company's performance based on the key operational measure component of the plan. The Committee may, in its discretion, reduce or eliminate the amount of payment with respect to an Award of PeRS to a Participant, notwithstanding the achievement of a specified performance condition. |
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b. |
New Participants . The provisions of 3.1(a) notwithstanding, at any time during a Performance Cycle, the Committee may select a new employee or a newly promoted employee who was not currently participating in the Performance Cycle to participate in the Performance Cycle and designate, for any such employee Participant, the number of PeRS or additional PeRS such Participant shall have the opportunity to earn in such Performance Cycle; provided, however, that such designation must be effective at least six months before the stated end date of the Performance Cycle. In determining the number of Target PeRS to be designated under this paragraph (b), the Committee may take into account the portion of the Performance Cycle already elapsed, the performance achieved during such elapsed portion of the Performance Cycle, and such other considerations as the Committee may deem relevant. The Committee shall also determine whether any calculation of the Pro Rata Portion for such Participant shall be adjusted to include or exclude periods prior to the Participant's employment in the numerator or denominator used in calculating such amount. |
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c. |
Comparison Group . The Comparison Group for each Performance Cycle shall be designated by the Committee, provided that, if the Committee does not designate a new Comparison Group for any Performance Cycle, the Comparison Group shall be that most recently designated by the Committee.The Comparison Group for each Performance Cycle for the Total Shareholder Return Component of the Plan is developed including all publically traded utilities as defined by SIC Codes 4911 -Electric Services, and 4931 - Electric Services and Other Service Combinations. In the event a merger, acquisition, or other extraordinary corporate event affects a company included in the Comparison Group, and if as a result in the Committee's judgment such event causes Total Shareholder Return for such company not to be comparable with periods prior to the event or otherwise necessitates a change or adjustment to ensure continued comparability, the Committee shall make such adjustments in order to maintain the comparability of results of the Comparison Group. The Comparison Group for relative customer satisfaction, one of the measures in the operational component, is all East Region electric utilities in the J.D. Powers residential customer satisfaction telephone survey. These include all electric utilities with over 200,000 customers throughout the East Region including vertically integrated utilities, utilities with retail access, and public and private utilities. The Employer's overall customer satisfaction compared to the East Region average of electric utilities measured by J.D. Powers will be calculated for each year and averaged over the 3 year performance cycle. The 3 year average percent vs. East Region average will be used to determine relative performance. |
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d. |
Determination of Number of Earned PeRS . Not later than 120 days after the end of each Performance Cycle, the Committee shall determine the extent to which the performance goals for the earning of PeRS were achieved during such Performance Cycle and the number of PeRS (or, the "Award") earned by each Participant with respect to each component for the Performance Cycle (see Exhibit A and Exhibit B). The Committee shall make written determinations that the performance goals and any other material terms relating to the earning of PeRS were in fact satisfied. |
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3.2 |
Adjustment of and Changes in Stock . In the event of any change in the outstanding shares of Common Stock by reason of any stock dividend or split, recapitalization, merger, consolidation, spinoff, combination or exchange of shares or other similar corporate transaction, or any distributions to common shareholders other than regular cash dividends, the Committee may make such substitution or adjustment, if any, as it deems to be equitable, as to the number or kind of shares of Common Stock, PeRS, and/or other securities issued, reserved or granted for any purpose under this Plan. |
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ARTICLE IV |
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4.1 |
Performance Awards . Subject to the applicable provisions of Article III, each Participant shall be entitled to receive an Award of Common Stock in an amount equal to the aggregate Fair Market Value of the PeRS earned in respect of a Performance Cycle. Participants shall be immediately vested in such Award as of the date it is granted. |
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4.2 |
Accounts . The Committee shall maintain a bookkeeping Account for each Participant reflecting the number of PeRS credited to the Participant hereunder including dividend equivalents. The Account may include subaccounts or other designations as the Committee may deem appropriate. |
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4.3 |
Payment of Account . Payment of an Account may be made in shares of Common Stock, in cash equal to the Fair Market Value of the shares on the date as of which payment is made, or in any combination of Common Stock and cash, and at such time or times as the Committee, in its discretion, shall determine. The intent is to grant the payment in shares of common stock subject to sections 3.2 and 7.5 of this plan.The Committee may, whether at the time of grant or at any time thereafter prior to payment or settlement, permit (subject to such conditions as the Committee may from time to time establish in order to provide for matters such as the effective deferral of taxation) a Participant to elect to defer receipt of all or any portion of any payment of shares of Common Stock that would otherwise be due to such Participant in payment or settlement of any Award under the Plan. An eligible participant may elect to defer the award through the Deferred Compensation Plan for Officers and Directors of Central Vermont Public Service Corporation. The shares of Common Stock which may be issued under the Plan may be authorized and unissued shares or issued shares which have been reacquired by the Employer. No fractional share of the Common Stock shall be issued under the Plan. Awards of fractional shares of the Common Stock, if any, shall be settled in cash. |
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ARTICLE V |
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5.1 |
Termination Prior to Completion of Performance Cycle . |
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a. |
Upon a Participant's Termination of Employment with the Employer prior to completion of a Performance Cycle all unearned PeRS relating to such Performance Cycle shall cease to be earnable and shall be cancelled, and Participant shall have no further rights or opportunities hereunder. |
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b. |
Disability, Death, or Retirement . If Termination of Employment is due to the death or the Disability or Retirement (as such terms are defined under the provisions of The Pension Plan of Central Vermont Public Service Corporation and Its Subsidiaries, i.e., the "Pension Plan") of the Participant, the Participant or his beneficiary (as designated for purposes of the Pension Plan) shall be deemed to have earned and shall be entitled to receive settlement of the Pro Rata Portion of the PeRS relating to the Performance Cycles in effect at the date of termination, at the time and to the extent such PeRS would otherwise have been earned and settled, in accordance with Article IV if the individual had not terminated until after the close of the Performance Cycles. Notwithstanding the foregoing, in the event that such Termination of Employment is effective as of the last day of a calendar year, the Participant shall only be entitled to earn the aforementioned PeRS, as otherwise determined in this paragraph (b), upon approval of the Board.If the Participant has timely filed an irrevocable election to defer settlement of PeRS following a termination of employment, such earned PeRS shall be settled in accordance with such deferral election. Other PeRS relating to the Performance Cycles in effect at the date of such termination will cease to be earnable and will be cancelled. |
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5.2 |
Upon a Participant's Termination of Employment that occurs as a result of a Termination Event as defined in the Employer's Change of Control Agreement approved by the Board April 3, 2000, following a Change in Control, the Participant shall be deemed to have earned and shall be entitled to receive, in accordance with the applicable provisions of the Plan, the Pro Rata Portion of the PeRS relating to Performance Cycles in effect as of the Change in Control. Other PeRS relating to the Performance Cycles will cease to be earnable and will be cancelled. |
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ARTICLE VI |
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6.1 |
Committee . This Plan shall be administered by the Board through the Compensation Committee. The Committee shall have full discretion to interpret and administer the Plan and its decision in any matter involving the interpretation and application of this Plan shall be final and binding on all parties. The Committee may delegate to one or more of its members or to any Officer or Officers of the Company such administrative duties under the Plan as the Committee may deem advisable. |
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6.2 |
Amendment and Termination . The Compensation Committee reserves the right to amend, modify, suspend or terminate this Plan in whole or in part at any time by action of the Board. However, no such amendment may alter the maximum number of shares without shareholder approval. |
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ARTICLE VII |
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7.1 |
Payments to Minors and Incompetents . If any Participant, spouse or beneficiary entitled to receive any benefits hereunder is a minor or is deemed by the Committee or is adjudged to be legally incapable of giving valid receipt and discharge for such benefits, they will be paid to such person or institution as the Committee may designate or to the duly appointed guardian. Such payment shall, to the extent made, be deemed a complete discharge of any such payment under the Plan. |
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7.2 |
No Contract . This Plan shall not be deemed a contract of employment with any Participant, nor shall any provision hereof affect the right of the Employer to terminate a Participant's employment. |
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7.3 |
Use of Masculine and Feminine; Singular and Plural . Wherever used in this Plan, the masculine gender will include the feminine gender and the singular will include the plural, unless the context indicates otherwise. |
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7.4 |
Non-Alienation of Benefits . No amount payable to, or held under the Plan for the account of, any Participant, spouse or beneficiary shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, or charge, and any attempt to so anticipate, alienate, sell, transfer, assign, pledge, encumber, or charge the same shall be void; nor shall any amount payable to, or held under the Plan for the account of, any Participant be in any manner liable for such Participant's debts, contracts, liabilities, engagements, or torts, or be subject to any legal process to levy upon or attach. |
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7.5 |
Income Tax Withholding . As a condition to the delivery of any Shares, the Committee may require that the Participant, at the time of such payment of shares, pay to the Company an amount to satisfy any applicable tax withholding obligation or such greater amount of withholding as the Committee shall determine from time to time, or the Committee may take such other action as it may deem necessary to satisfy any such withholding obligations. The Committee, in its sole discretion, may permit or require Participant to satisfy all or a part of the tax withholding obligations incident to the payment of shares by having the Company withhold a portion of the Shares that would otherwise be issuable to the Participant. Such Shares shall be valued based on their Fair Market Value on the date the tax withholding is required to be made. Any such Share withholding with respect to a Participant subject to Section 16(a) of the Exchange Act shall be subject to such limitations as the Committee may impose to comply with the requirements of Section 16 of the Exchange Act. |
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7.6 |
Continuation of Plan . In the event of a Change of Control, this Plan shall remain in full force and effect as an obligation of the Employer or its successors in interest. |
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7.7 |
Governing Law . The provisions of the Plan shall be interpreted, construed, and administered in accordance with the referenced provisions of the Code and with the laws of the State of Vermont. |
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7.8 |
Captions . The captions contained in the Plan are inserted only as a matter of convenience and for reference and in no way define, limit, enlarge, or describe the scope or intent of the Plan nor in any way affect the construction of any provision of the Plan. |
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7.9 |
Severability . If any provision of the Plan is held invalid or unenforceable, its invalidity or unenforceability will not affect any other provision of the Plan, and the Plan will be construed and enforced as if such provision had not been included. |
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IN WITNESS WHEREOF, the Employer has caused this instrument to be executed by its duly authorized officer as of the 8th day of March , 2006. |
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CENTRAL VERMONT PUBLIC |
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Attest: |
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Exhibit A PeRS Earned for Total Shareholder Return Performance Component |
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Three-Year Total Shareholder |
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75th percentile or higher |
1.5 |
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The resulting three-year Total Shareholder Return determined for this Plan shall be rounded up to nearest percentile specified above. The multiple of Target PeRS earned between each of the respective percentiles specified above shall be determined by linear interpolation. |
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Exhibit B PeRS Earned for Operational Measure Performance Component |
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0X |
1X |
1.5X |
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A measure of operational financial |
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The multiple of Target PeRS is determined by using the weighted performance of the measures above. Linear interpolation is used for actual performance between performance points specified above for the quantitative measures. |
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Exhibit B 2006 SERVE |
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Target |
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Call not answered in 20 seconds |
25% |
15% |
10% |
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Each SERVE measure is equally weighted. |
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EXHIBIT 12.1 Central Vermont Public Service Corporation |
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(dollars in thousands) |
2005(a) |
2004(a) |
2003(a) |
2002(b) |
2001 |
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Earnings, as defined - S-K 503(d): |
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Pre-tax income from continuing operations |
$(672) |
$9,561 |
$27,279 |
$28,505 |
$7,970 |
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Plus: distributed income |
1,938 |
1,229 |
2,441 |
14,679 |
7,409 |
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Less: equity in earnings |
(1,869) |
(1,225) |
(1,801) |
(15,512) |
(8,747) |
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Less: interest capitalized |
(79) |
(76) |
(87) |
(41) |
(67) |
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Less: preference security dividends, as defined |
(624) |
(624) |
(2,031) |
(2,547) |
(2,827) |
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Plus: fixed charges, as below |
11,161 |
12,090 |
14,314 |
16,638 |
18,148 |
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Total Earnings, as defined |
$9,855 |
$20,955 |
$40,115 |
$41,722 |
$21,886 |
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Fixed charges, as defined: |
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Interest on debt |
$9,519 |
$10,397 |
$ 11,150 |
$13,021 |
$14,089 |
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Imputed interest in rental charges |
1,018 |
1,069 |
1,133 |
1,070 |
1,232 |
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Preferred dividends, as defined |
624 |
624 |
2,031 |
2,547 |
2,827 |
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Total fixed charges, as defined |
$11,161 |
$12,090 |
$14,314 |
$16,638 |
$18,148 |
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Ratio of Earnings to Fixed Charges |
0.88 |
1.73 |
2.80 |
2.51 |
1.21 |
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(a) Reflects Catamount Energy Corporation as discontinued operations. |
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EXHIBIT 21.1 Subsidiaries of the Registrant |
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State in Which |
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Vermont Electric Power Company, Inc. (b) (F2) Vermont Yankee Nuclear Power Corporation (b) (F2) C.V. Realty, Inc. (a) (F1) Central Vermont Public Service Corporation - Custom Investment Corporation (a) (F1) Catamount Resources Corporation (a) (F1) Eversant Corporation (a) (c) (F1) |
Vermont Vermont Vermont
Vermont Vermont Vermont |
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- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - |
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(FN) (F2) |
(b) Separate financial statements do not need to be filed under Regulation S-X, Rule 1-02 (w) (c) Eversant Corporation has two wholly owned subsidiaries operating in the United States. |
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EXHIBIT 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement File No. 333-102008 on Form S-8 of our reports dated March 30, 2006, relating to the consolidated financial statements of Central Vermont Public Service Corporation and its subsidiaries, management's report on the effectiveness of internal control over financial reporting, and the consolidated financial statement schedules contained in Schedule II, Item 15 (our report on the consolidated financial statements expresses an unqualified opinion and includes explanatory paragraphs regarding the sale of the Company's interest in Catamount Energy Corporation and regarding the restatement of the 2004 and 2003 consolidated financial statements and our report on internal control over financial reporting expresses an adverse opinion on the effectiveness of internal control over financial reporting because of a material weakness), appearing in this Annual Report on Form 10-K of Central Vermont Public Service Corporation for the year ended December 31, 2005. /s/ Deloitte & Touche LLP Boston, Massachusetts |
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EXHIBIT 24.1
POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that the undersigned Chief Executive Officer and Senior Vice President, Chief Financial Officer, and Treasurer and the undersigned Directors of Central Vermont Public Service Corporation, a Vermont Corporation, which corporation proposes to file with the Securities and Exchange Commission an Annual Report on Form 10-K for the year ended December 31, 2005, under the Securities Exchange Act of 1934, as amended, does each for himself/herself and not for one another, hereby constitute and appoint Robert H. Young and Edmund F. Ryan and each of them, his/her true and lawful attorneys, in his/her name, place and stead, to sign his/her name to said proposed Annual Report on Form 10-K and any and all amendments thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to grant and hereby granting to said individuals, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do regarding the preparation, execution, filing of Form 10-K. IN WITNESS WHEREOF, each of the undersigned has hereunto set their hand as of the 18th day of January, 2006. |
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/s/ Robert H. Young Robert H. Young Chief Executive Officer and Director |
/s/ Frederic H. Bertrand Frederic H. Bertrand Chair of the Board of Directors |
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/s/ Edmund F. Ryan Edmund F. Ryan Acting Chief Financial Officer, and Treasurer |
/s/ Robert L. Barnett Robert L. Barnett, Director /s/ Rhonda L. Brooks Rhonda L. Brooks, Director /s/ Janice B. Case Janice B. Case, Director /s/ Robert G. Clarke Robert G. Clarke, Director /s/ Timothy S. Cobb Timothy S. Cobb, Director /s/ Bruce M. Lisman Bruce M. Lisman, Director /s/ George MacKenzie, Jr. George MacKenzie, Jr., Director /s/ Mary Alice McKenzie Mary Alice McKenzie, Director /s/ Janice L. Scites Janice L. Scites, Director |
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EXHIBIT 31.1 ANNUAL CERTIFICATION OF CHIEF EXECUTIVE OFFICER REQUIRED BY I, Robert H. Young, certify that: |
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1. |
I have reviewed this annual report on Form 10-K of Central Vermont Public Service Corporation (the "registrant"); |
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2. |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
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3. |
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
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4. |
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
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a) |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
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b) |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
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c) |
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
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d) |
Disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the registrant's 4th fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
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5. |
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
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a) |
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
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b) |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
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Date: March 31, 2006 |
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EXHIBIT 31.2 ANNUAL CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY I, Edmund F. Ryan, certify that: |
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1. |
I have reviewed this annual report on Form 10-K of Central Vermont Public Service Corporation (the "registrant"); |
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2. |
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
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3. |
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
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4. |
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
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a) |
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
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b) |
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
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c) |
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
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d) |
Disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the registrant's 4th fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
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5. |
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
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a) |
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
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b) |
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
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Date: March 31, 2006 |
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EXHIBIT 32.1
CERTIFICATION PURSUANT TO In connection with the Annual Report of Central Vermont Public Service Corporation (the "Company") on Form 10-K for the period ended December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I Robert H. Young, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge and belief: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Robert H. Young A signed original of this written statement required by Section 906 has been provided to Central Vermont Public Service Corporation ("CVPS") and will be retained by CVPS and furnished to the Securities and Exchange Commission or its staff upon request. |
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EXHIBIT 32.2 CERTIFICATION PURSUANT TO In connection with the Annual Report of Central Vermont Public Service Corporation (the "Company") on Form 10-K for the period ended December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I Edmund F. Ryan, Acting Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge and belief: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Edmund F. Ryan A signed original of this written statement required by Section 906 has been provided to Central Vermont Public Service Corporation ("CVPS") and will be retained by CVPS and furnished to the Securities and Exchange Commission or its staff upon request. |
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
March 31, 2006
Securities & Exchange Commission
Gentlemen: I am enclosing a copy of Central Vermont Public Service Corporation's Form 10-K for the fiscal year ended December 31, 2005 filed electronically on March 31, 2006 through EDGAR. The financial statements in the report reflect no change from the preceding year in any accounting principles or practices, or in the method of applying any such principles or practices. Very truly yours, /s/ Mary C. Marzec Mary C. Marzec |