Item 1. Business
General
Maine & Maritimes Corporation (“MAM” or the “Company”), a Maine corporation, became a holding company effective June 30, 2003. MAM owns all of the common stock of Maine Public Service Company (“MPS”). All other shares of MPS common stock were converted into an equal number of shares of MAM common stock, which are listed on the American Stock Exchange (“AMEX”) under the symbol “MAM.” The reorganization into a holding company was approved by MPS’s shareholders at its annual meeting on May 30, 2003. The U.S. Securities and Exchange Commission (“SEC”) had previously accepted MAM’s S-4A Registration Statement for registration. Other required state and federal regulatory agencies issued necessary approvals on various dates in 2003. Financial results and amounts shown through 2002 and the first three months of 2003 were reported by MPS.
MAM is the parent holding company for MPS, Energy Atlantic, LLC (“EA”), and Maine & Maritimes Energy Services Company (“MAMES”). Maine & New Brunswick Electrical Power Company, Ltd (“Me&NB”), is a wholly-owned Canadian subsidiary of MPS. MAMES (dba “The Maricor Group”) is the parent company of Maricor Ltd (“Maricor”), also a wholly-owned Canadian subsidiary. General descriptions of these companies and subsidiaries are discussed more fully below.
Maine & Maritimes Corporation and Subsidiaries
• MPS is a regulated electric transmission and distribution utility serving all of Aroostook County and a portion of Penobscot County in northern Maine.
• Maine & New Brunswick Electrical Power Company, Ltd, an inactive Canadian subsidiary of MPS, formerly owned MPS’s Canadian electric generation assets.
• Energy Atlantic, LLC is a licensed, but currently inactive Competitive Energy Supplier (“CES”) of retail electricity and formerly served the northern and central regions of the state of Maine.
• Maine & Maritimes Energy Services Company (dba “The Maricor Group”) is a development, engineering, energy efficiency and asset management firm focused on markets in the United States providing fee-for-service mechanical and electrical engineering services.
• Maricor Ltd is a Canadian subsidiary of Maine & Maritimes Energy Services Company, whose principal business is primarily the delivery of similar products and services as MAMES, but in Canadian markets.
Discussion and Description of the Company’s Growth Strategy
MPS’s decision to convert to a holding company structure and begin implementation of a diversification and growth strategy was based on a combination of regulatory and economic factors including, but not limited to: (a) the impacts of deregulation and generation divestiture on MPS’s revenue model, (b) flat to declining demographic and economic
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conditions within MPS’s service area; (c) regulatory constraints or barriers to implementation of a growth strategy under MPS’s organizational structure; (d) a declining rate base as a result of reductions in stranded costs as regulatory assets; and (e) the strategic objective to implement an effective risk management structure associated with the Company’s overall growth strategy.
As a result of Maine’s deregulation and MPS’s generation divestiture, MPS no longer serves as a vertically integrated electric utility. With the exception of stranded cost recovery, MPS’s revenues come almost exclusively from regulated transmission and distribution services associated with transporting electric supply. MPS does receive varying returns on its stranded regulatory assets, as well as varying returns on its regulated transmission and distribution rate bases. Generally, stranded cost represents the difference in value or contract value of generation assets in a regulated environment, as compared with market values of these same assets or contracts for purchased power agreements. In a regulated regime, investor-owned public utilities are allowed to make a “fair” rate of return on their prudently invested capital. In practice, regulators set the price of electricity so that the utility receives enough income to pay its financial obligations plus a reasonable return on its fixed investments. In effect, historical or accounting costs of asset installations determine the current market value of capital. Regulators adjust the revenue stream up or down to allow a public utility to earn the approved rate of return on the book value of its capital, which is also known in a regulatory context as its “rate base.” MPS continues to earn regulated rates of return on its transmission and distribution assets. MPS’s distribution services are regulated by the Maine Public Utilities Commission (the “MPUC”) and its transmission services are regulated by the U.S. Federal Energy Regulatory Commission (“FERC”).
Based on MPS’s current amortization of stranded costs and approved stranded cost rates of return approved by the MPUC, and subject to a number of variables embedded in the calculation of those stranded costs, the majority of MPS’s stranded cost should be recovered by the end of 2012. A significant portion of MPS’s stranded costs are associated with an existing non-utility generator (“NUG”) supply contract referred to in this document as the “Wheelabrator-Sherman NUG Contract.” The Wheelabrator-Sherman NUG Contract resulted from the passage by the U.S. Congress of the 1978 Public Utilities Regulatory Policy Act (“PURPA”) and is summarized more fully below. The facility itself is a small bio-mass (principally wood chip) electric generation facility. Over approximately the next eight years, MPS’s rate base will decline as these and other stranded costs are reduced or eliminated. Management and the Board of Directors also believe that MPS’s rate base will continue to decline as a result of: (a) the economic impact of deregulation and generation divestiture on MPS’s core revenue model; (b) MPS’s economically lagging service area; and (c) regulatory risks in connection with rate making and stranded cost recovery. Based on management’s and the Board of Directors’ assessment of MPS’s declining rate base, the decision was made to create a holding company, subject to shareholder approval, and to implement a comprehensive growth strategy.
Although the majority of MPS’s stranded cost rate base will decline gradually over approximately the next eight years, MPS believes it will experience deferred stranded cost freed-up cash flows during the period from 2007 through 2012 as certain stranded costs are recovered. This is a result of MPS’s historical decision to levelize its stranded cost portfolio and defer full recovery associated with its Wheelabrator-Sherman NUG Contract, These deferred stranded cost freed-up cash flows will not impact net income. Current plans for the anticipated stranded cost freed-up cash flows include: (a) utilizing such funds to reduce debt; (b) maintaining an optimum regulatory capital structure; and (c) to dividend a portion of the stranded cost freed-up cash flows to the parent MAM for the purpose of financing in part or in whole potential acquisitions consistent with the Company’s growth strategy. While MPS believes it will receive full stranded cost recovery and recovery of deferred collections, it cannot predict with certainty future regulatory and/or legislative actions. Regulatory and legislative risks may exist relative to full stranded cost recovery. In addition there are a number of variables, discussed in more detail below that may affect the timing and magnitude of MPS’s stranded cost recovery.
Management and the Board of Directors have adopted what they believe to be a realistic and conservative growth strategy, focusing primarily, but not exclusively, on market opportunities within New England and Atlantic Canada. As part of the Company’s growth and business strategy, focus and investments are being placed on strategies to improve the overall performance, system reliability, economics and efficiencies of MPS’s transmission and distribution systems. These strategies include the adoption of new productivity enhancing technologies, changes in core business processes, adoption of integrated asset management strategies, and development and implementation of long-term transmission and distribution plans. These plans may also include the construction of additional regulated
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transmission assets. The goals of these efforts are to reduce overall annual capital, operating, and maintenance expenditures, while improving system and customer service performance.
MAM’s growth strategy centers on a diversification approach that expands the Company’s business and revenue model to include, without limitation, mechanical and electrical engineering services, energy efficiency solutions, air emissions reductions, asset/facilities management related services and asset/facility ownership, in addition to its continuing focus on regulated and unregulated utility services. Unregulated utility services may include, but not be limited to, energy supply management and unregulated energy assets, such as central utility plants.
The Company is continuing to evaluate potential regulated and unregulated utility acquisitions, such as small electric utilities, local natural gas distribution companies, fuel oil and propane distributors, electric transmission projects and mid-stream natural gas assets across North America. However, the Company cannot assure that such acquisitions can or will be accomplished. Utility-related acquisitions are intended to seek to leverage MPS’s and other subsidiaries’ existing operating infrastructure, including without limitation, call center and collections operations, telecommunications technologies, billing and information technology applications, engineering capabilities, asset management systems, regulatory experience, and management expertise. MAM’s proposed overall growth strategy will be heavily influenced by acquisitions that meet certain desired strategic and financial criteria within the general categories defined below. Implementation of the acquisition strategy is dependent upon, among other things, MAM’s and its subsidiaries’ ability to raise sufficient capital. MAM believes that it can raise necessary capital to implement its acquisition strategy, but cannot assure investors of this ability.
Organizational Overview of Proposed Strategic Vision
Showing Examples of Potential Business Sector Acquisitions
* MAM does not warrant that it can or will implement acquisitions in each of the revenue models. However, acquisitions in each of the revenue models will be evaluated and are under consideration.
As a part of the process in developing the Company’s growth strategy, market and public policy trends were analyzed for the Atlantic Canada and New England regions. As a result of these analyses, it appears that a number of critical economic, environmental, energy, and infrastructure trends are converging within these regions. In Atlantic Canada, electric transmission appears to be significantly limited and the adequacy of on-peak electric generation also appears to be unclear. The region has historically been highly dependent on oil as an energy source and has limited alternative fuel choice options, such as natural gas or other fuels for its electric generation. As a result, Atlantic
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Canada may face near-term on-peak energy shortages and increasing energy price issues. The Company believes both regions appear to face complex energy challenges in the near to long-term. Also, should the cost of energy rise and availability of energy supplies come into question, air quality concerns and related regulation and legislation may inhibit the construction of new, adequate generation within the region. Canada’s adoption of the Kyoto Protocol and the 28th Annual Conference of the New England Governors and the eastern Canadian Premiers Resolution 28-7, a resolution concerning environmental projects and issues, are examples of increasing public policies that are placing more stringent air quality requirements on the construction or refurbishment of energy producing or using facilities. Management also believes the combination of energy price, energy availability, and air quality concerns is exacerbated within the region due to additional apparent uncertainty concerning the economics and approval for the refurbishment and retooling of older, existing electric generation facilities that may include, for example a nuclear generation facility within New Brunswick, Canada. Management believes that these public policy issues are placing new pressures on governments and organizations to improve energy efficiency, gain greater control of energy costs, and reduce air emissions. At the same time, Management believes the two regions also face the reality that tax revenues and existing economic growth are inadequate to fund infrastructure renewals associated with schools, hospitals, municipal operations and universities. This recognition appears to be bringing increased focus on the significant deferred maintenance liabilities of public assets, and the requirement to ensure that capital dollars for facility renewals and replacements are spent in the most optimal manner to extend the life of such facilities, i.e. the facility asset lifecycles. Consequently, Management believes that governments, both domestic and foreign, are beginning to require lifecycle asset management plans and the determination of lifecycle costs before additional capital dollars are spent for facility renewals and replacements. The Company’s overall growth strategy is primarily based on these beliefs, issues, observed trends, analyses and conclusions.
Utilizing a combination of strategic acquisitions and non-acquisition growth, the Company’s business model, includes the acquisition of mechanical and electrical engineering companies offering asset lifecycle management and engineering services. Through the integration of engineering skills and certain asset lifecycle management software accessed by the Company or its subsidiaries; MAMES’ and Maricor’s services are being offered to improve facility energy efficiency, define and reduce deferred maintenance, extend asset lifecycles, and reduce air emissions. These services are also intended to enhance the economic efficiency of a facility’s electric and mechanical systems resulting in reduced operating costs. In addition, the Company and its subsidiaries are focused on identifying and developing energy asset related projects that may consist of either small “green field” development projects located on or related to a customer’s premises, or the acquisition of a customer’s energy assets, such as a central utility plant or a district energy project, with a long-term contract from one or more customers for the energy asset’s output. These development projects may, or may not involve a third party financing and ownership entity. The Company intends to market such services within Atlantic Canada and New England, however it does not intend to be geographically limited to these regions. Specific primary market sectors of emphasis include, without limitation, the government, university, school, hospital, commercial and institutional markets. MAMES and Maricor also offer fee-for-service engineering services, which are provided to a broader cross-section of businesses and industries within the regions.
The Company’s intended strategic plan, subject to market opportunities and conditions, also includes the potential acquisition of a small, regional real estate development and facilities management business, which is intended to compliment the Company’s asset or facilities-centric engineering business model. Efforts are on-going to evaluate market opportunities for the acquisition of such a firm within the Atlantic Canada and New England regions. The Company’s intended objective is to acquire a small to medium real estate portfolio as a part of its acquisition of a real estate development and management company. The targeted real estate portfolio would ideally consist of non-operating and non-retail properties within second and third tier growth markets within the target region, with an increasing focus on the development of public facilities with long-term leases matching financing terms. The Company’s entry and timing of such an entry into this market is primarily dependent upon market conditions and the availability of an acquisition on economically acceptable terms. The Company cannot warrant that it can or will succeed in achieving such an acquisition.
Financing of the Company’s growth strategy, depending on the specific acquisition target, may take the form of a number of different financing structures involving cash, equities and/or debt. Financing may include, without limitation, the issuance of additional common or preferred stock, vendor take backs, senior debt, private mezzanine debt securities, tax-exempt government bonds, cash or acquisition earn-outs. In addition to its compatibility with the Company’s growth strategy, each acquisition target is also being evaluated based on its individual economic and strategic merits relative to long-term shareholder value. As the Company implements its growth strategy, a more definitive stock dividend policy may be adopted. Such a policy, if adopted by the Board of Directors, would be
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intended to provide guidance relative to a definitive dividend payout range. The Company, however, remains committed to maintaining a market competitive dividend yield with an increasing focus on a combination of yield and stock value growth. However, the Company cannot warrant or define future dividends or share value.
As a first step in implementing the Company’s growth strategy, in November 2003, MAM formed MAMES and its Canadian subsidiary, Maricor in Canada. MAMES and Maricor provide facilities-based mechanical and electrical engineering services, asset lifecycle management services and solutions, energy efficiency, energy reliability, and emissions reduction services. Maricor’s first strategic acquisition, Eastcan Consultants, Inc, (“Eastcan”) took place on December 1, 2003. Eastcan is a regional, mechanical and electrical engineering firm, focused on the Atlantic Canada markets and headquartered in Moncton, New Brunswick, Canada, with an office in Saint John, New Brunswick, Canada. The acquisition represents an initial platform acquisition from which to build and/or acquire additional capabilities. MAMES, dba “The Maricor Group” intends to continue to evaluate engineering company acquisitions that provide market entry points into key markets within the target regions of New England, the U.S. and Atlantic Canada.
Description of Maine Public Service Company and Maine and New Brunswick Electrical Power Company, Limited
MPS was originally incorporated in the United States as the Gould Electric Company (“Gould”) in April, 1917 by a special act of the Maine legislature in connection with the purchase and lease of all of the assets of the Maine and New Brunswick Electrical Power Company, Limited, a Canadian company. Me&NB, currently a wholly-owned Canadian subsidiary of MPS, was incorporated in 1903 under the laws of the Province of New Brunswick, Canada. Following the sale of its assets to Gould, Me&NB remained a subsidiary of Gould, and subsequently MPS. Me&NB was primarily a hydro-electric generating company. It owned and operated the Tinker hydro-electric station in New Brunswick, Canada, until June 8, 1999, when these assets were sold by MPS to WPS Power Development, Inc. (“WPS-PDI”), a subsidiary of WPS Resources Corporation (“WPS”). Prior to the generating asset sale, Me&NB sold energy not needed to supply its wholesale New Brunswick, Canada customers, to MPS. For the period 2000-2003, Me&NB has been inactive and did not have unaffiliated customer revenues.
Following its incorporation in the United States, Gould changed its name to Maine Public Service Company in August, 1929. MPS was a privately held subsidiary of the Consolidated Electric & Gas Company until 1947, when its capital stock was sold as a result of Consolidated Electric & Gas Company’s forced divestiture. From 1947 until its corporate reorganization in 2003, MPS was the corporate parent and traded under the stock symbol “MPS” on the AMEX. MPS, until its generating assets were sold on June 8, 1999, produced and, until March 1, 2000, purchased electric energy for retail and wholesale customers. MPS continues to provide transmission services to former wholesale energy customers and transmission and distribution services to retail customers in the service territory. Geographically, its service territory is located in a region of northern Maine comprised of all of Aroostook County and a portion of Penobscot County. The service area covers a region approximately 120 miles long and 30 miles wide, with a population of approximately 72,000. Since March 1, 2000, the date retail electric competition in Maine commenced, customers in MPS’s service territory have been purchasing energy from suppliers other than MPS. This energy comes from Competitive Electricity Providers (“CEP”) or, if customers are unable or do not wish to choose a competitive supplier, the Standard Offer Service (“SOS”) provider. SOS providers are determined through a bid process conducted by the MPUC.
By regulatory order, on June 4, 1984, MPS entered into a Power Purchase Agreement (“PPA”) with the Sherman Power Company, which assigned its interest in the agreement to the Wheelabrator-Sherman Energy Company (“WS”), formerly Signal-Sherman Energy Company, for 17.6 megawatts of capacity, the delivery of which began on July, 1986. As stated above, the WS facility is a NUG and qualifying facility as that term is defined by PURPA. This PPA formed the basis of what was to become the Wheelabrator-Sherman NUG Contract. The stated legislative intent of PURPA was to encourage more energy-efficient and environmentally-friendly commercial energy production. PURPA defined a new class of energy producer called a qualifying facility (“QF”). QFs are small-scale producers of commercial energy who normally self-generate energy for their own needs and/or may sell the output under a PPA to a regulated utility. When a facility of this type meets the FERC’s requirements for ownership, size and efficiency, utility companies are obligated under PURPA to purchase energy from these facilities based on a pricing structure referred to in a regulatory context as avoided cost rates. In the case of WS, the avoided cost rates were defined by the MPUC at the avoided cost rate of another facility, the Seabrook nuclear facility’s fully embedded production cost, making these rates highly favorable to the producer. The difference between these avoided costs rates and the market rate that would result
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from an arms length negotiation for the producer’s electric capacity is an important component of MPS’s WS stranded costs.
The original Wheelabrator-Sherman NUG Contract was scheduled to expire at the end of 2000; however, either party had the option to renew the contract for an additional fifteen years. MPS and WS agreed to amend the Wheelabrator-Sherman NUG Contract with the amendment approved by the MPUC in December, 1997. Under the terms of this amendment, WS agreed to reductions in the price of purchased power of approximately $10 million over the contract’s current term. MPS and WS also agreed to renew the contract for an additional six years at agreed-upon prices. MPS made an up-front payment to WS of $8.7 million on May 29, 1998, with the financing provided by the Finance Authority of Maine (“FAME”). This payment has been reflected as a regulatory asset, as determined by the MPUC in its December, 1997 order and, based on an MPUC order, included in stranded costs and recovered in the rates of the transmission and distribution utility, beginning January 1, 2001. The amended contract helped relieve the financial pressure caused by the closure of Maine Yankee in 1997, as well as the need for substantial increases in MPS’s retail rates, and also reduced MPS’s stranded costs.
Every two years, the WS output is sold via competitive bids, with the bidding process monitored by the MPUC. The sale of the WS output offsets the WS costs in determining this component of MPS’s stranded costs. For the period March 1, 2000 to February 28, 2002, and from March 1, 2004 to the end of the Wheelabrator-Sherman NUG Contract, December 31, 2006, WPS-PDI was the successful bidder. For the period March 1, 2002 to February 29, 2004, EA took delivery of 40% of WS’s output, while WPS-PDI took the 60% remainder. MPS records the above-market cost of Wheelabrator-Sherman NUG Contract as a stranded cost.
As stated above, MPS’s Canadian Subsidiary, Me&NB has been inactive for the period of 2001-2003, as reflected in the table below.
MPS’s research and analyses of its service area indicate that MPS’s service area’s economy, once heavily influenced by a significant military presence, continues to be dependent upon agricultural and the forest products industries. Potato farming and processing and the manufacturing of forest products, principally lumber, plywood, and oriented strand board, continue to be dominant economic forces within MPS’s service area. The growing of broccoli has added diversity to the region’s agricultural economic base. Tourism, particularly related to snowmobiling and skiing, appears to be playing an increasingly significant role in the area’s economy. The medical industry represents a significant positive and growing economic force within the region, serving as a leading employer and job creation sector. However, data appears to suggest that the northern Maine economy continues to lag behind national economic trends and is experiencing population losses based on census data and recent projections, particularly among the service area’s youth and young adults. Attracting new businesses and jobs to northern Maine in an effort to reverse out-migration trends appears to be a continuing challenge to the area’s leaders and businesses, including MPS. As a result of its service area’s economic challenges, MPS has taken a lead role in forming a public/private partnership for economic progress in cooperation with the Northern Maine Development Commission. Managed by a private-sector investors’ council, MPS and its staff are serving as a private sector leader in helping to execute a rational and results-oriented economic development program. The Aroostook Partnership for Progress’s (“APP’s”) efforts are intended to increase the area’s emphasis on economic development through improved focus and funding for economic development.
Energy Atlantic, LLC
EA participated in the wholesale power market during 1999 and until March 1, 2000, when it began selling energy in the retail electricity market within the state of Maine. The retail market consists of two sectors, Standard Offer Service (“SOS”) and Competitive Energy Supply (“CES”), as mentioned above. The MPUC requests bids for SOS in each utility service territory. As a result of this bidding process, EA was the SOS provider in Central Maine Power Company’s (“CMP’s”) territory from March 1, 2000, until its contract expired on February 28, 2002. Within MPS’s service territory, EA provided 20% of the medium non-residential SOS from March 1, 2000 until February 28, 2001.
EA also provided energy to several large commercial customers in CMP’s territory under one-year CES contracts, which expired throughout 2001. EA, along with its wholesale energy supplier, was not successful in obtaining any of the SOS in MPS’s service territory starting March 1, 2001, nor CMP’s service territory starting March 1, 2002.
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Originally, power for the sales noted above was obtained under an exclusive wholesale power sales agreement with Engage Energy America, LLC, (“Engage”), which expired February 28, 2002.
As part of a contract settlement between Engage and EA reached in May 2001, EA was allowed to purchase energy from additional sources. EA secured several wholesale sources of power, enabling it to participate in competitive markets within Maine. EA’s CES sales to retail customers during 2003 produced far less operating margin than EA had previously earned from SOS in CMP’s territory. On February 24, 2003, EA announced its intent to withdraw from the northern Maine market due to the lack of profitability and perceived risk profile in that market resulting from an illiquid wholesale market, inability to obtain price differentiated wholesale electric products, and other factors. EA continued to serve its existing contracts in northern Maine until their February 27, 2004, expiration date. In addition, EA has not renewed its wholesale agreement for southern Maine supply and has not renewed retail contracts within this region. Management has ceased active retail CES within the state of Maine until market conditions, the availability of supply, the mandate for stringent credit requirements and risk environment improve. Management will continue to monitor both U.S. and Canadian deregulated markets to determine the appropriate timing for possible re-entry into the deregulated retail market. For further information regarding EA, its contract settlement with Engage and its future business plans, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Energy Atlantic Activities,” such information is incorporated in this section by this reference.
Maine & Maritimes Energy Services Company (dba “The Maricor Group”) and Maricor Ltd
In November 2003, MAM formed the wholly-owned subsidiaries MAMES in the United States (dba “The Maricor Group”), and its Canadian subsidiary, Maricor. MAMES and Maricor are businesses organized to provide, among other things, energy efficiency, energy reliability, air emissions reduction, fee-for-service mechanical and electrical engineering and lifecycle asset management services primarily within eastern Canadian provinces and New England. MAMES is headquartered in Presque Isle, Maine with offices in Portland, Maine and Rockland, Massachusetts.
Maricor’s first strategic acquisition, Eastcan Consultants, Inc, (“Eastcan”) took place on December 1, 2003. Eastcan, now an operating division of Maricor, is a regional, mechanical and electrical engineering firm headquartered in Moncton, New Brunswick, Canada, with an office in St. John, New Brunswick, Canada. Eastcan was formed in 1978, in connection with the amalgamation of several engineering firms in the Moncton, New Brunswick area. Eastcan’s combined historical experience is well in excess of five thousand building projects. Eastcan’s clients generally include architectural firms, municipal, provincial and federal governments, private institutional, commercial facility owners and industrial or manufacturing operations. Mechanical and electrical engineering service disciplines provided by the Eastcan Division of Maricor include, without limitation, the following:
Mechanical Engineering Services:
• Plumbing
• Heating
• Ventilation
• Air Conditioning
• Energy Conservation Studies and Audits
• Reports & Investigations
• Process Piping
• Fire Protection Systems
• Boiler Plants
• Petroleum Storage and Handling Systems
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Electrical Engineering Services:
• Lighting Calculations and Layouts
• Power Distribution (Buildings, Industrial Plants, Process Equipment)
• Power Quality (Emergency generators, UPS systems, Harmonic cancellations)
• Fire Alarm Systems
• Intrusion Alarm System Integration
• Public address system
• Power Factor Correction
• Reports & Investigations
To complement Maricor’s service and product offerings, MAM and MAMES have partnered with Delinea Corporation of Dallas, Texas, a leading software application and business process outsourcing company focused on the energy industry, and acquired exclusive marketing rights to their Strategic Asset Management (“SAM”) technology-based solutions for select markets within the U.S. and Canada.
Delinea’s SAM offerings are industry-leading solutions for organizations that are seeking to preserve and maintain the value of their investments in infrastructure, facilities and fixed assets. SAM provides the technology and services required to effectively manage the total lifecycle of capital assets, as well as the daily operations of facilities and fixed assets. Its strategic planning capabilities are used to quantify, prioritize and optimize the capital investments required to maintain and preserve facilities and assets, while providing decision-making support to effectively manage these critical requirements in accordance with capital budgets and available funding.
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Financial Information about Foreign and Domestic Operations
(In Thousands of U.S. Dollars)
The identifiable assets, by company, are those assets used in each company’s operations, excluding intercompany receivables and investments. For 2003 and 2002, identifiable assets reflects the reclassification of accrued removal obligations as a liability from accumulated depreciation.
* The term “Subsidiaries Canada” above includes all applicable financial information for Me&NB and Maricor.
Regulation and Rates
The information with respect to regulation and rates is presented in Item 3 below, “Legal Proceedings,” such information is incorporated in this section by this reference.
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Franchises and Competition
Except for consumers served at retail by municipal electric utilities within MPS’s service area, MPS has a nearly exclusive franchise to deliver electric energy in its service territory. For additional information on changes to the structure of the electric utility industry in Maine, see Item 7 below, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Overview,” incorporated herein by this reference. For information on the competitive conditions facing EA, MAMES and Maricor see also Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Energy Atlantic Activities,” such information is incorporated in this section by this reference.
MAMES and Maricor operate in competitive markets and do not have exclusive franchises. Competition comes primarily from other local or regional mechanical and electrical engineering firms, as well as local, regional or national energy services companies. Public policies related to energy, energy efficiency, asset lifecycle management, and air emissions may impact the overall market. The Company has observed that increasing interest rates generally tend to negatively impact the market for fee-for-service mechanical and electrical engineering services. However, increasing interest rates also appear to increase the demand for energy efficiency and asset lifecycle management services. The Company cannot warrant or predict these economic effects and makes no predictive statement as to future market or competitive trends.
Employees
The information with respect to employees is presented in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Employees,” such information is incorporated in this section by this reference.
Subsidiaries, Affiliated and Associated Companies
As stated above, MAM became a holding company effective June 30, 2003. All 1,574,582 shares of MPS common stock were converted on the books on that date into an equal number of MAM common stock, which are listed and traded on the AMEX. MAM owns 100% of the common stock of MPS.
MPS owns 100% of the common stock of Me&NB. Me&NB owned and operated the Tinker hydro-electric station located in the Province of New Brunswick, Canada, prior to its sale on June 8, 1999, and has not conducted active business since the sale.
On August 24, 1998, the MPUC approved the formation of what was then MPS’s unregulated subsidiary, EA. EA began formal operations on January 1, 1999, performing various non-core activities, such as wholesale marketing of electric power and the sales of energy-related products and services. EA began retail sales activity on March 1, 2000, the date retail electric competition commenced in Maine. As a start-up unregulated subsidiary, the MPS Board of Directors and the MPUC limited MPS’s capital contributions to a maximum of $2 million, subsequently amended to $2.5 million during 2002. With the formation of MAM, MPS’s interest in EA was transferred to the new holding company. EA is currently an inactive subsidiary of MAM.
MPS owns 5% of the common stock of Maine Yankee, which operated an 860 MW nuclear power plant (the “Plant”) in Wiscasset, Maine. On August 6, 1997, the Board of Directors of Maine Yankee voted to permanently cease power operations and to begin decommissioning the Plant. The Plant experienced a number of operational and regulatory problems and did not operate after December 6, 1996. The decision to close the Plant permanently was based on an economic analysis of the costs, risks and uncertainties associated with operating the Plant compared to those associated with closing and decommissioning it. The Plant’s operating license from the Nuclear Regulatory Commission (“NRC”) was due to expire on October 21, 2008. For further information regarding Maine Yankee and its decommissioning progress, see Item 7 below, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Maine Yankee,” such information is incorporated in this section by this reference.
MPS also owns 7.49% of the common stock of Maine Electric Power Company, Inc., (“MEPCO”). MEPCO owns and operates a 345-KV (kilovolt) transmission line about 180 miles long, which connects the New Brunswick Power (“NB Power”) system with the New England Power Pool (“NEPOOL”).
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In November 2003, MAM formed MAMES in the United States, now dba “The Maricor Group,” and MAMES’ Canadian subsidiary, Maricor. MAM owns 100% of the stock in MAMES. MAMES has a 100% ownership interest in Maricor. In December 2003, Maricor acquired Eastcan Consultants, Inc., which is a regional mechanical and electrical engineering firm headquartered in Moncton, New Brunswick, Canada with an office in St. John, New Brunswick, Canada. Eastcan is currently an operating division of Maricor. An organizational diagram illustrating the various corporate relationships described in this section is provided above in Part 1, Item 1, Business, “General” and is incorporated in this section by this reference.
Company Financial Information
The public may read and copy any materials the Company files with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, N.W. Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
The Company is an electronic filer and the SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. The Company also maintains an Internet site containing such reports at www.maineandmaritimes.com. All such reports, including annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, may be downloaded from such site without charge. Also listed at the Company’s site under Investor Relations, Corporate Governance, is the Code of Ethics for Senior Financial Officers and all other Principal Executive Officers and Managers, as well as the Company’s policy regarding Insider Trading and Dissemination of Inside Information.
Item 2.
Item 2. Properties
As of December 31, 2003, MPS had approximately 380 circuit miles of transmission lines and MPS owned approximately 1,730 miles of distribution lines, all in Aroostook County and a portion of Penobscot County in northern Maine. There are no material physical assets held, owned or controlled by any of the Company’s other subsidiaries.
Substantially all of the properties owned by MPS are subject to the liens of the First and Second Mortgage Indentures and Deeds of Trust.
In response to a Maine environmental regulation to phase out Poly Chlorinated Bi-phenol (“PCB”) transformers, MPS has implemented a program to eliminate transformers on its system that do not meet the new state environmental guidelines. The program will test the almost 13,000 distribution transformers over a ten-year period. In addition, transformers that pass the inspection criteria will be refurbished and refitted with lightning arrestors and animal guards. The initial cost of the ten-year program was estimated to be $5 million. After three years, MPS has spent approximately $1,033,000 under the program. MPS is currently in its fourth year of this ten-year program.
System Security and Reliability
During 2002, the engineering consulting firm of R.W. Beck, Inc. (“R.W. Beck”), was retained to undertake a comprehensive facilities evaluation and engineering audit of the MPS transmission and distribution systems. The purpose of the evaluation and audit were to provide a comprehensive condition baseline of the transmission and distribution systems as a beginning basis for development of new transmission and distribution system plans and the implementation of asset management initiatives. As a result of the condition baseline and increasing focus on system planning, MPS has implemented a continuous in-the-field inspection program for transmission and distribution. The inspection program has been facilitated by the investment in new mobile equipment allowing for “top down” inspections versus traditional pole climbing or “bottom up” processes. Further, MPS has begun development of twenty-year distribution and transmission planning processes. These planning processes are intended to focus on means to improve overall system reliability, while minimizing lifecycle asset management costs and reducing future required capital expenditures.
From a transmission perspective, the R.W. Beck audit noted that transmission lines appeared to be in good condition and reasonably maintained. However, they did note on a relative basis that certain lines were older, but in good condition with the exception of some of the oldest wood pole lines and areas where bird (woodpecker) damage is a problem. Through MPS’s in-the-field transmission inspection program, structures in need of repair or replacement are
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being identified and repaired or replaced. Current plans are to undertake complete inspections of MPS’s transmission system every two years.
Audits of the Company’s substations and substation-related business processes were also undertaken by R.W. Beck. The overall ratings for substations were lower than desired, due to the fact that almost half of the distribution substations rely on power transformers that have exceeded their useful lives or are within five years of exceeding their useful lives. While certain transformers are beyond their normal life expectancy, MPS has implemented a comprehensive testing program to identify problem transformers, implementing preventive maintenance to extend equipment life expectancies, or replacing such transformers. As part of the system planning process, MPS is developing a plan to replace older transformers, which will focus on consolidating substations where possible, all a part of MPS’s long-term system planning process.
MPS had planned to reduce its annual capital expenditures to a level approximately equal to its rate of depreciation. Due to MPS’s desire to consolidate facilities and ensure increased system reliability, management believes that renewal and replacement capital expenditures for the next two to three years may remain at more recent historical levels of $4.0 million to $6 million annually. Such expenditure levels do not include the possible construction of additional transmission as later described.
As a result of the closure of an on-system generation facility and uncertainty concerning other merchant and non-merchant generation facilities within the Maritimes and northern Maine regions, MPS continues to evaluate system security, particularly from an on-peak generation resource perspective. Through load-flow analysis and utilization of specific contingency or transmission outage scenarios, it has been determined that under a single contingency or outage condition and during peak load situations, a system-wide outage is possible if at least 50 MW’s of on-system generation are not operating. Additionally, under certain conditions, the analyses noted that a second contingency or transmission line outage could not be survived within a thirty-minute time frame when similar conditions existed after a single contingency. Although Maine Public Service Company does not have a bulk delivery transmission system as defined by the Northeastern Power Coordinating Council (“NPCC”), MPS is using NPCC’s standards for planning criteria. It should be noted that potential contingencies that were studied focused on situations that could impact MPS’s transmission and distribution systems, even though certain transmission assets are located in Canada and are owned by other companies or organizations. MPS has contingency plans to mitigate such conditions or events in the case that a major transmission outage or system outage occurred.
As a result of internal and external transmission system security studies in the fall of 2002, a unique risk to the MPS system was identified due to a condition on an NB Power breaker at the Beechwood 138 kV substation in Canada. The risk was that for a single breaker malfunction at Beechwood substation, MPS could lose two of its three main interconnections with NB Power. The loss of these interconnections, coupled with the uncertainty of on-system merchant generation levels, required MPS to act to prevent conditions that could result in an outage. Consequently, MPS paid NB Power $125,900 in December of 2003, for installing a series breaker, which eliminated this risk to the MPS transmission system.
In order to address system security and reliability needs, MPS is also evaluating the construction of additional interconnections with NB Power. Such projects, subject to further analysis and regulatory approvals, would increase available and total transmission capacities. In addition, MPS is evaluating the merits of joining a new Independent System Operator (“ISO”) or Regional Transmission Organization (“RTO”). At this time it is unclear as to the potential outcome of these efforts. Further, due to shortages of peaking generation capacity within the Maritimes region, MPS is evaluating other non-transmission options to ensure system reliability. Such alternative options may require legislative or regulatory approvals.
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Item 3.
Item 3 (ii)(a) above). However, management believes that implementation of PBR’s under an ARP could result in detrimental financial impacts due to the lack of growth within MPS’s service area. Typically, ARP’s with PBR’s require productivity offsets to achieve allowed rates of return and management believes such productivity offsets will not be achievable in the absence of economic growth.
MAMES, and its wholly-owned Canadian subsidiary, Maricor, offer mechanical and electrical engineering services, including asset development, energy efficiency services, air emissions reduction services, and lifecycle asset management services. In addition, MAMES and Maricor offer a range of solutions to reduce facility lifecycle costs, identify and reduce deferred maintenance liabilities and improve environmental performance. MAMES’ and Maricor’s value proposition encompasses the development, management, operation and modernization of physical assets for environmental and financial sustainability.
Target markets within the eastern Canadian provinces and Atlantic Canada primarily include, but are not necessarily limited to, governments, universities and colleges, hospitals and other health care facilities, schools, commercial retail and office facilities. While not a target market, MAMES and Maricor can and do provide engineering-related services to the industrial sector. MAMES and its subsidiary, Maricor currently have offices in Presque Isle and Portland, Maine; Rockland, Massachusetts; and Moncton and Saint John, New Brunswick, Canada.
The Maricor Group’s services categories generally include:
• Planning & Efficiency Services - facility audit and condition assessments, asset modernization and development planning, energy and environmental performance analysis, capital budgeting and planning services and a web site-based planning advisor;
• Operational Services - asset operations management and asset information management;
• Modernization Services - mechanical and electrical engineering, energy engineering, air emissions reductions, project management and commissioning services; and
• Development Services - energy asset ownership, design and build services, project management and commissioning services, such as central utility or district energy projects.
This section and the accompanying text explain the general financial condition of the Company and its subsidiaries and their results of operations. This explanation includes:
• factors that affect our business;
• the sources of our revenues and changes between years;
• our operating expenses and changes between years;
• the sources of our operating capital; and
• the impact of the above on our financial condition.
Critical Accounting Policies
In preparing the financial statements in accordance with generally accepted accounting principles, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. The Company’s most critical accounting policies include the determination of the appropriate accounting for its pensions and other post-retirement benefits, the recognition of its revenues, the effects of utility regulation on its financial statements and its risk management activities.
Revenue Recognition
MPS records an estimate for revenue for electricity delivered, but not yet billed to customers. This estimate requires MPS to make certain assumptions. A change in those assumptions could cause the amounts reported as revenues to change. EA’s previous sales can be classified into two general categories: SOS in CMP’s service territory which
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expired February 28, 2002, and CES sales to individual retail customers within the state of Maine, all of which expired by February 27, 2004. For SOS, revenues were received and expenses were paid directly by an escrow agent which was controlled by Engage Energy America, LLC (“Engage”). EA received a percentage of the net profit from the sale of energy. CMP bore SOS account collection risks, as they were required to remit the amounts billed 26 days after the billing date to the escrow account mentioned above and maintain the billing and customer service relationship. EA recorded the accrued net margin of the SOS activity as revenue in the financial statements. For CES sales, EA negotiated the price directly with the customer, maintained customer service responsibility and had collection risk. EA has withdrawn from the market until market conditions improve and no longer serves CES or SOS customers. CES activity is recorded on a gross basis to include the related revenues and purchased power expenses. Additionally, EA’s activity has been accounted for as non-trading since management has determined it does not meet the definition of a trader as defined in EITF 98-10 which was amended by EITF 02-03. Refer to Item 16(a) of this Form 10-K, Note 3 to the Consolidated Financial Statements, “Energy Atlantic” for further discussion.
Pension and Other Post-retirement Benefit Plans
The Company has pension and other post-retirement benefit plans, principally healthcare benefits, covering substantially all of its employees and retirees. In accordance with Statement of Financial Accounting Standards No. 87, “Employer’s Accounting for Pensions,” and Statement of Financial Accounting Standards No. 106, “Employer’s Accounting for Post-retirement Benefits Other Than Pensions,” the valuation of benefit obligations and the performance of plan assets are subject to various assumptions. The primary assumptions include the discount rate, expected return on plan assets, rate of compensation increase, health care cost inflation rates, expected years of future service under the pension benefit plans and the methodology used to amortize gains or losses. Changes in those assumptions could also have a significant effect on the Company’s non-cash pension income or expense or the Company’s post-retirement benefit costs. For additional information on the Company’s benefit plans, see Item 16(a) of this Form 10-K, Note 10 to the Consolidated Financial Statements, “Benefit Plans,” which is incorporated in this section by this reference.
Utility Regulation
MPS is subject to the regulatory authority of the MPUC and the FERC. As a result of the ratemaking process, the applications of accounting principles by MPS differ in certain respects from applications by non-regulated businesses. Approximately 84% of the Company’s 2003 revenues, as depicted in the “Operating Revenues and Energy Deliveries” section below, derived from MPS’s regulated operations are accounted for pursuant to Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulations.”
Prior to the start of deregulation in Maine on March 1, 2000, the MPUC determined the amount of stranded costs to be recovered via rates. MPS’s annual amortization of its stranded costs represents the amounts allowed by the MPUC in the determination of revenue requirements.
Results of Operations
Earnings and Dividends
Earnings per share and net income for 2003, along with the corresponding information for 2002 and 2001 are as follows:
* Due to the immateriality of elimination amounts, they have been grouped with appropriate line items
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Net income above is allocated based upon the segment allocation as presented in Item 16(a) of this Form 10-K, Note 4 of the Notes to Consolidated Financial Statements, “Segment Information.”
As a part of the formation of the holding company, certain MPS staff were transferred to MAM. Also, certain administrative, legal, professional, governance, and professional costs were assigned to MAM, following MPUC approved cost allocation process. In addition, certain costs associated with merger and acquisition due diligence activities were included in MAM costs. In December, 2003, MAM formed MAMES and MAMES’ Canadian subsidiary, Maricor. In addition, during the same time frame Maricor purchased Eastcan Consultants, a mechanical and electrical engineering firm headquartered in Moncton, New Brunswick, Canada, with an office in Saint John, New Brunswick.
MPS core T & D earnings were $3,378,000 for 2003, compared to $3,099,000 and $4,340,000 in 2002 and 2001, respectively. Earnings for 2003 increased by $239,000 over earnings in 2002. Sales in 2003 increased by 1.9% over 2002, contributing an additional $203,000, net of income taxes. As more fully explained in the “Legal Proceedings” section of this Form 10-K, the MPUC allowed recovery, over seven years, of the VERP expenses charged to 2002 earnings, resulting in an increase in 2003 net income of $236,000, net of income taxes, after considering two months of amortization. In addition, reductions in transmission and distribution expenses of $131,000, net of income taxes, and in interest costs of $192,000, net of income taxes, also contributed to the increase in earnings. Offsetting these increases in earnings were additional expenses of $245,000, net of income taxes, associated with the approval of the holding company and increases in depreciation and amortization of $122,000, net of income taxes. Earnings for 2002 compared to 2001 were impacted by incremental charges for MPS’s Voluntary Early Retirement Program (“VERP”) of $242,000, net of income taxes, and expenses associated with seeking approval for the formation of the holding company of $105,000, net of income taxes. MPS incurred additional expenses for employee benefits, principally pension and medical costs, and insurance costs, resulting in a reduction in earnings of $723,000, net of income taxes. In addition, consulting fees for evaluating business processes at MPS and legal expenses for regulatory affairs and compliance with provisions of the Sarbanes-Oxley Act of 2002, further reduced net income by $575,000, net of income taxes. Offsetting these additional expenses was a reduction of MPS’s borrowing costs of $361,000, net of income taxes, and increased operating revenues for MPS of $235,000, net of income taxes, as 2002 sales were 1.4% more than 2001 sales.
In 2003, EA incurred a loss of $116,000 with the reduction in 2003 CES sales, compared to the two previous years, and with the termination of SOS service in CMP’s territory after February 28, 2002. EA earnings for 2002 were $3,444,000, or $2.19 per share. As more fully explained in the “Energy Atlantic Activities” section below, EA’s earnings include $1.89 per share representing the recognition in September 2002, of the final settlement between EA and Engage Energy America, LLC (“Engage”) and the reversal of regulatory assessments associated with power arrangements. EA earnings in 2001 reflect a $1.08 million charge in accordance with a settlement agreement with EA’s supplier for Standard Offer Service in Central Maine Power Company’s service territory, Engage Energy America, LLC. This charge reduced earnings per share by $.69.
Return on equity (net income divided by average shareholders’ equity) for 2003 was 6.0% compared to 14.6% for 2002 and 12.7% for 2001. The core T&D business earned a return on equity of 8% in 2003 compared to 7.6% and 10.5% for 2002 and 2001, respectively. As explained in the “Legal Proceedings” section of this Form 10-K, the MPUC authorized a return on equity of 10.25% starting November 1, 2003, compared to 10.7% prior to that date.
Effective October 1, 2001, the Board of Directors increased the quarterly dividend by $.03 per share from $0.32 per share to $0.35 per share, or $1.40 per share per year. The quarterly dividend was increased by $0.02 per share to $0.37 per share effective October 1, 2002, for an annual dividend payment of $1.48 per share. Effective January 1, 2004, the Board of Directors increased the quarterly dividend by $0.01 per share to $0.38 per share, for an annual dividend of $1.52 per share.
Off-Balance Sheet Arrangements
Except for operating leases used for office and field equipment, vehicles and computer hardware and software, accounted for in accordance with Financial Accounting Standards No. 13 (“FAS 13”), “Accounting for Leases” and
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noted in Footnote 12 to these financial statements, the Company has no other off-balance sheet arrangements. See Item 16(a) of this Form 10-K, Note 12 to Consolidated Financial Statements, “Commitments, Contingencies and Regulatory Matters,” under “Off-Balance Sheet Arrangements” for a summarization of payments for leases for a period in excess of one year for the years ended December 31, 2003 and 2002.
Operating Revenues and Energy Deliveries
Consolidated revenues and Megawatt Hours (“MWH”) delivered for the years 2003, 2002 and 2001 are as follows:
* Due to the immateriality of elimination amounts, they have been grouped with appropriate line items.
For 2003, regulated retail sales for MPS were 540,214 MWH compared to 530,267 MWH and 522,708 MWH in 2002 and 2001, respectively. 2003 retail sales were 1.9% higher than sales in 2002 and 3.3% higher than sales in 2001. Residential sales in 2003 were 3.5% higher than 2002 sales and 5.7% higher than 2001. This increase is believed to be attributable to a colder than normal winter in 2003, as compared to 2002.
Sales to MPS’s large commercial customers in 2003 were 0.9% less than 2002, but 3.0% higher than 2001 sales. Sales to MPS’s largest customer, McCain Foods, were 65,814 MWH, 0.7% less than 2002 sales of 66,301 MWH, but 12.3% higher than 2001 sales of 58,629 MWH. Sales to food processing customers, other than McCain Foods, in 2003 were 15,858 MWH compared to 15,831 MWH in 2002 and 23,225 MWH in 2001. The closing of Maine Frozen Foods in 2002 was the principal reason for the reduction in sales. Sales to wood product customers in 2003 were 76,248 MWH, 1.6% less than 2002 sales of 77,495 MWH, but 4.6% more than 2001 sales of 72,922 MWH. These customers have benefited from the historically low interest rates and the increased demand for new homes and home remodeling projects.
Sales to MPS’s medium commercial customers increased by 2,233 MWH to 106,073 MWH in 2003, as compared to 103,840 MWH in 2002, but were 1,134 MWH less than 2001 sales of 107,207 MWH. Small commercial customer sales were 89,882 MWH, compared to sales in 2002 and 2001 of 86,639 MWH and 85,605 MWH, respectively. The increase in sales to these two classes of customers reflects the colder than normal weather in 2003, as well as the general improvement of overall regional economic conditions, including the retail sector.
The MPUC has jurisdiction over MPS’s retail rates. On November 1, 2003, and on October 1, 2002, MPS’s rates were increased by approximately 3% and 2% respectively. These retail rate increases included the retail portion of previously FERC approved transmission increases. The FERC has jurisdiction over MPS’s transmission rates,
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including the rates charged for wheeling revenues, as discussed below. For more information on the regulatory orders approving the recent rate increases, see Item 3, “Legal Proceedings,” Item 3 (ii) (c) and (d) of this Form 10-K.
As more fully explained in the “Energy Atlantic Activities” section below, EA provided CES and SOS during the three-year period. In 2001, CES sales of 375,768 MWH produced $15.8 million of revenues. In 2000, with its arrangement with Engage Energy America, LLC (“Engage”), EA provided CES service to several large customers, principally in southern Maine. However, these contracts expired in 2001, resulting in reduced sales and revenues for 2002 and 2003. In addition, EA had difficulties procuring competitive energy supplies, given MPS’s conservative fiscal policies regarding risk tolerance and credit coverage. As a result, sales in 2002 were 148,072 MWH and $6.9 million, further dropping to 2003 sales of 114,405 MWH and $6.1 million in revenues. The SOS margin represents the net margin sales of SOS to approximately 525,000 residential and small commercial customers in Central Maine Power Company’s service territory from March 1, 2000 through February 28, 2002. As more fully explained in the “Energy Atlantic Activities” section below, EA was not the successful bidder for providing SOS after March 1, 2002, and received a final account settlement with Engage in 2002. This final account settlement with Engage, of approximately $4.6 million, before income taxes, is reflected in the 2002 SOS margin of $5.8 million. In 2001, the SOS margin of $2.15 million reflects a $1.8 million before-tax charge for a contract settlement with Engage. As noted herein, EA has now ceased operations and no longer serves customers in Maine. Its inactive status will remain under review by management, and the Company intends to maintain certain licenses in order to preserve the option of returning to the market should market conditions and other risk factors improve.
Other operating revenues in 2003 were $1,262,000 compared to $1,901,000 in 2002 and $2,711,000 in 2001. Wheeling revenues in 2003 were $318,000 less than 2002 and $448,000 less than 2001, reflecting the reduction in use of MPS’s transmission system by on-system generators. As more fully explained in Item 3 “Legal Proceedings,” Item 3(ii) (b) of this Form 10-K, the MPUC, in its stranded cost review, adjusted the treatment of certain customer discounts through flexible pricing adjustments, effective March 1, 2002. As a result, the revenues recognized from flexible pricing adjustments in 2003 were $335,000 less than 2002 and $1,096,000 less than 2001.
Operating Expenses
For the three-year period 2001 to 2003, unregulated energy supply, regulated operation and maintenance expenses and unregulated operation and maintenance expenses and stranded costs are as follows:
*Due to the immateriality of elimination amounts, they have been grouped with appropriate line items.
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The unregulated energy supply expenses represent EA’s purchases of energy to supply their CES customers. As more fully explained in the “Energy Atlantic Activities” section below, EA was purchasing power from Engage Energy America, LLC (“Engage”) for a two-year period that ended on February 28, 2002. Beginning March 1, 2002, for a two-year period, EA was awarded a contract by the MPUC for 40% of the output (55,000 MWH) from the Wheelabrator-Sherman facility to be used for CES sales in northern Maine. In addition, EA has a power supply arrangement with Duke Energy Trading & Marketing (“DETM”) to provide power to CES customers in southern and central Maine. The reduction in purchases of energy supply from $14,984,000 in 2001 and $5,533,000 in 2002 to $5,220,000 in 2003 reflects the reduction in sales achieved by EA, as presented in the “Operating Revenues and Energy Deliveries” section above. During 2000, the first year of deregulation in Maine, several large industrial customers purchased power from EA under one-year agreements, which expired at various times during 2001.
Transmission and distribution expenses in 2003 were $3,114,000, a reduction of $220,000 from expenses in 2002 and $229,000 from expenses in 2001. The reduction in tree-trimming expenses due to the “in-sourcing” of vegetation management, was the primary reason for the decrease in expenses in 2003 compared to 2002 and 2001.
In 2003, customer service expense was $1,452,000 compared to $1,635,000 and $1,452,000 for 2002 and 2001, respectively. In 2002, MPS’s charge-offs for bad debts increased by $191,000 over 2001, reflecting the bankruptcies and plant closings of several customers during 2002, while 2003 approximated 2001. The implementation of automatic meter reading in 2003, for approximately one third of our customers, helped to further reduce customer service costs compared to expenses in 2002.
Administrative and general expenses in 2001 were $5,616,000 increasing to $8,076,000 in 2002 and $7,857,000 in 2003. As more fully explained in the “Employee” section below, employees representing approximately 7% of the workforce participated in a voluntary early retirement program (“VERP”) in 2002. The cost of the program was $402,000 which was charged to fourth quarter 2002 earnings. As more fully explained in the “Legal Proceedings” section above, in early 2003 MPS filed for a rate increase. One of the elements in the rate request was recovery of these VERP costs. However, recovery of these costs was not approved by the MPUC when the program was instituted in 2002. When the MPUC issued its rate orders in the fall of 2003, thereby assuring MPS of the recovery of the $402,000 in VERP costs, MPS reduced 2003 administrative and general expenses. After adjusting for the impact of the VERP discussed above, employee benefits, principally employee and retiree medical expenses and pension expenses were $2.1 million in 2003 compared to $2.3 million in 2002 and $1.5 million in 2001. The increases in pension expenses in 2002 and 2003 reflect the lower discount rates used to determine pension liabilities and lower returns realized in pension investments with the sluggish investment markets in 2002 and 2001. Medical costs continue to escalate comparable to national trends. As mentioned in the “Employee” section below, employee contributions have increased and retirees began contributing to help offset escalating costs. In 2003, regulatory, consulting and legal expenses totaled $2.1 million compared to $1,598,000 in 2002 and $824,000 in 2001. The dramatic increase in these expenses in 2003, and 2002 over 2001, reflect costs associated with compliance with the Sarbanes-Oxley Act of 2002; legal and rate consulting assistance in the preparation, filing and advocacy of MPS’s rate plan filed with the MPUC during the first quarter of 2003 and approved by the MPUC in the fourth quarter of 2003; legal services associated with the preparation, filing and advocacy concerning MPS’s federal Open Access Transmission Tariff (“OATT”) filed in the second quarter of 2003 with a final FERC rate order in the first quarter of 2004; the completion of transmission and distribution, as well as information systems benchmarking audits, enabling increased asset management, increased prioritization of capital expenditures, increased productivity and improved reliability; and finally, review of financial strategies and financing options. MPS’s insurance expenses in 2003 increased by $168,000 over 2002 and were $289,000 more than 2001. These increases have followed the national trends of increased premiums for property and casualty insurance after the terrorist attacks on September 11, 2001, and increased Directors’ and Officers’ liability insurance costs following corporate scandals at several major corporations.
Unregulated operation and maintenance expenses were $2,353,000 in 2003 compared to $1,654,000 in 2002 and $1,226,000 in 2001. In late 2002, and for the first six months of 2003, MPS incurred expenses associated with the formation of the new holding company, MAM, of $209,000 and $639,000, respectively. During 2003, EA’s
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operating expenses were $1,018,000 compared to $1,445,000 in 2002 and $1,226,000 in 2001. Expenses in 2002 were higher due to an increase in bad debt expense, legal expenses associated with the Engage settlement and consulting fees. During 2003, EA reduced costs with the reduction in business activity. In July 2003, MAM began formally assessing business opportunities and potential acquisition targets. During the last six months of 2003, MAM and MAMES collectively spent $696,000 on these activities.
Beginning on March 1, 2000, MPS began recovering stranded costs from its retail customers. As discussed in Item 3 “Legal Proceedings” section, the MPUC reviewed MPS’s stranded costs and adjusted MPS’s recovery effective March 1, 2002. MPS recognized stranded costs of $8,761,000 for 2003 and 2002 and $9,260,000 for 2001.
The reduction of stranded costs in 2003 and 2002 reflects the reduction in revenue requirements as discussed in Item 3 of the “Legal Proceedings” section. The stranded costs for WS and Maine Yankee represent actual cash expenses during the year, while other costs reflect the amortization or recognition of regulatory assets and regulatory liabilities.
Operating Capital and Liquidity
The Company’s “Statements of Consolidated Cash Flows,” of the Company’s Consolidated Financial Statements as presented in Item 16(a) of this Form 10-K, reflects the Company’s liquidity and sources of operating capital. Net income of $2.8 million for 2003 generated $3.9 million in cash flow provided by operating activities. The change in deferred regulatory and debt issuance costs of $6.8 million, principally the deferral of additional WS stranded cost, which was partially offset by an increase in deferred income taxes of $3.6 million, and accounted for the biggest charge on cash flow compared to prior years. Net cash flow used for financing activities totaled $2.7 million. During 2003, $2.9 million was paid in dividends and $3.1 million was used for sinking fund payments to retire long-term debt. The dividend payment amount reflects five quarters of dividends paid during 2003 due to timing of funding requirements. These payments were offset by short-term borrowings of $3.35 million. In 2003, $2.8 million of net cash flow was used for investing activities. The Company invested $4.9 million in electric plant and an additional $527,000 in MAMES, principally its purchase of Eastcan Consultants, Inc. During 2003, the final $2.1 million was withdrawn from the trust account for the 2000 series of tax-exempt bonds for the construction of qualifying distribution property, and $525,000 was received for the partial redemption of Maine Yankee common stock.
In 2002, net cash flows of MPS provided by operating activities were $6.9 million, while net income for the year was $6.54 million. In 2002, $3 million of the gain from the 1999 sale of the generating assets was amortized, while regulatory assets increased by $1.9 million to reflect the rate treatment of stranded costs, which both reduced cash flows. During 2002, MPS paid $2.2 million in dividends, retired $1.2 million of long-term debt and reduced short-term borrowings by $1.2 million, for a total of $4.6 million used for financing activities. In 2002, $5.9 million was invested in electric plant with $3.7 million withdrawn from the trust account for the tax-exempt bonds. In addition, MPS received approximately $375,000 for the partial redemption of its Maine Yankee common stock. As of December 31, 2002, approximately $2.1 million remained in the tax-exempt trust fund to be used for the construction of qualifying property through October 2003.
Net cash flows provided by operating activities were $10.1 million in 2001. Net income for the year was $5.24 million. The collection of accounts receivable, principally the collection by EA of the SOS service receivable from the escrow agent, accounted for most of the increase in cash flows from operating activities. In 2001, MPS paid $2.1 million in dividends while reducing short-term borrowings and long-term debt by $2 million. During 2001, MPS received $1.05 million from a settlement with CMP concerning the 1999 sale of Wyman Unit No. 4, as well as $0.5 million for a partial stock redemption from Maine Yankee. As mentioned above, MPS has available proceeds from the issuance of tax-exempt bonds in 2000. During 2001, $2.0 million was withdrawn from the trust account for the construction of qualifying distribution property. As of December 31, 2001, approximately $5.7 million remained in the tax-exempt bond trust fund to be used for the construction of qualifying property. In 2001, $4.7 million was spent for electric plant.
For additional information regarding construction expenditures for 2001 to 2003 and anticipated construction expenditures for 2004, see Items 16(a) of this Form 10-K, Note 12 of Notes to Consolidated Financial Statements, “Commitments, Contingencies and Regulatory Matters - Construction Program.”
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To satisfy working capital requirements, MPS uses short-term borrowings from its revolving credit agreement of $6 million. The agreement is secured by $6 million of first mortgage bonds and its due date has been extended to June 6, 2004. In addition, on October 1, 2003, MPS executed an additional $3 million line of credit with the Bank of New York. This new facility is unsecured and will expire on March 29, 2004. MPS is currently seeking extensions of these facilities and management believes this effort will be successful. Interest rates on this new facility are comparable to the rates on the existing revolving credit agreement. The additional facility provides an additional source of short-term borrowings in the event required borrowings exceed the existing revolving credit agreement. At the end of 2003, MPS had $6.2 million of short-term debt compared to $2.8 million and $3.95 million at the end of 2002 and 2001, respectively. This short-term debt increase is a result of the long-term repayments described above. During 2001 to 2003, the interest rates on these short-term borrowings were below the existing prime rate. For additional information on the short-term credit facility, see Item 16(a) of this Form 10-K, Note 6 of the Notes to Consolidated Financial Statements, “Short-Term Credit Arrangements.” Based on current projections for 2004, the Company estimates that operating cash flows and short-term borrowings via available credit facilities will be sufficient to cover MPS’s other sinking fund payments, construction activities, and other financial obligations.
Capital Resources
The Company has the ability to raise capital through the issuance of common and preferred stock, as approved by the stockholders at the May 30, 2003, Annual Meeting. The Company is authorized to issue up to 5,000,000 shares of common stock. In addition, the Company’s Articles of Incorporation authorize the issuance of 500,000 shares of preferred stock with the par value of $0.01 per share. MPS can also issue $2.5 million of first mortgage bonds and $14.3 million of second mortgage bonds without bondable property additions.
With the sale of the generating assets and the use of sale proceeds to redeem debt, MPS’s long-term debt has decreased. On January 1, 1999, MPS had $47.2 million of long-term debt compared to $30.68 million at the end of 2003. MPS’s long-term debt currently consists of two series of tax-exempt bonds issued on behalf of MPS by the Maine Public Utility Financing Bank (“MPUFB”) totaling $22.6 million, and a series of bonds issued by FAME of $8.08 million, which provided MPS with the funds necessary for the up-front payment to restructure the WS PPA, as mentioned above.
The MPUFB has issued its tax-exempt bonds on behalf of MPS for the construction of qualifying distribution property. Originally issued for $15 million and reduced with generating asset sale proceeds, the 1996 Refunding Series had $13.6 million outstanding at December 31, 2003 and is due in 2021. On October 19, 2000, the 2000 Series of bonds was issued in the amount of $9 million, with these bonds due in 2025. The proceeds of the 2000 Series were placed in trust to be drawn down for the reimbursement of issuance costs and for the construction of qualifying distribution property. For both tax-exempt bond series, a long-term note was issued under a loan agreement between MPS and the MPUFB, with MPS agreeing to make payments to the MPUFB for the principal and interest on the bonds. Concurrently, pursuant to a letter of credit and reimbursement agreement, the Bank of New York has separately issued its direct pay letter of credit (“LOC”) for the benefit of the holders of each series of bonds. Both LOC’s are due to expire in June 2004. Management is currently seeking an extension of this facility and believes the effort will be successful. To secure MPS’s obligations under the letter of credit and reimbursement agreement for the 1996 Refunding Series, MPS issued second mortgage bonds in the amount of $14.4 million in June 2002. For the 2000 series, MPS issued first and second mortgage bonds, in the amounts of $5 million and $4.525 million, respectively, to secure MPS’s obligation under the letter of credit and reimbursement agreement for this series. For both series, MPS has the option of selecting weekly, monthly, annual or term interest rate periods. For both series, MPS has continued to use the weekly interest rate period. Since issuance, the average of these weekly rates was 2.99% and 1.97% for the 1996 Refunding Series and the 2000 Series, respectively. As more fully explained in the “Legal Proceedings” section of this Form 10-K, in September 2003, MPS executed an interest rate swap agreement with Fleet National Bank for the remaining terms of the issues with an effective fixed rate of 4.57% for the 1996 series and 4.68% for the 2000 series. By its rate order in Docket No. 2003-85, the MPUC approved the execution of the agreements and allowed recovery of the additional interest costs.
On May 29, 1998, FAME issued $11,540,000 of its Taxable Electric Rate Stabilization Revenue Notes, Series 1998A (MPS) (the “Notes”) on behalf of MPS. The Notes were issued pursuant to, and are secured under, a Trust Indenture by and between FAME and Peoples Heritage Bank, Portland, Maine, as Trustee (“the Trustee”), for the purpose of: (i) financing the up-front payment to Wheelabrator-Sherman of approximately $8.7 million, as required
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under an amended purchase power agreement; (ii) for the Capital Reserve Fund, as required by FAME under their Electric Rate Stabilization Program; and (iii) for issuance costs. The Notes are limited obligations of FAME, payable solely out of the trust estate available under the Indenture, principally the Loan Note and Loan Agreement with MPS and the Capital Reserve Fund held by the Trustee. MPS issued $4 million of its first mortgage bonds and the MPUC also approved the execution of an interest rate swap agreement with Fleet National Bank for the remaining term of the issue with an effective fixed rate of 2.79%.
In accordance with rate stipulations approved by the MPUC, for ratemaking purposes, MPS is required to maintain a capital structure not to include more than 51% common equity for the determination of delivery rates.
In the order approving the reorganization of MPS and the formation of the new holding company, Maine & Maritimes Corporation, parties stipulated to several conditions. The following relate to the availability of capital resources for MAM via its relationship with MPS:
• MPS will not make any loan to, or guarantee or assume any obligation of, MAM or any of its affiliates without prior MPUC approval.
• The MPUC will not place additional restrictions, in advance, on the dividend policy of MPS. The Board of Directors of MPS will continue to set dividend policy for MPS with due regard for the financial performance, needs and health of MPS and the maintenance of a safe, efficient and reasonable capital structure. Commencing on July 1, 2003, if at any time MPS’s common dividend payout ratio (dividends per share divided by earnings per share) exceeds 1.0 (i.e. 100%) on a two-year rolling average basis, MPS will notify the MPUC in writing within thirty (30) days of the end of the calendar quarter (assuming a dividend is paid July 1, 2003, the initial two year period shall be April 1, 2001 through March 31, 2003.) The required notification should explain the circumstances (extraordinary or not) of this event and the financial condition of MPS. Moreover, the MPUC reserved the right in the future, should financial circumstances warrant, to impose limitations on the dividend policy of MPS.
• Securities issuances by MPS will be done independently of MAM and subject to such MPUC approvals as required. The proceeds of any securities issued by MPS will be used exclusively by MPS for its business.
• MAM’s total non-utility investment, excluding accumulated unregulated retained earnings, will not exceed fifty million dollars (US$50,000,000) and such amount will exclude retained earnings from EA, provided that MPS may at any time seek an enlargement of this limitation for good cause shown.
• Without prior MPUC approval, MAM will not sell, pledge or otherwise transfer any common stock of MPS.
• To protect and maintain the financial integrity of the regulated utility, MPS and MAM agreed to maintain the common equity ratio of MPS at a level of not less than forty eight percent (48%) of the total capital at all times, provided that the MPUC may establish, for good cause shown, a lower ratio in connection with its authorization of a future debt issuance proposed by MPS. Total capital is defined as the sum of the following components: common equity, preferred equity, long-term debt, current maturities long-term debt (“CMLTD”), long-term capital leases, current maturities long-term capital leases, and short-term debt.
Energy Atlantic Activities
EA’s net loss for 2003 was $116,000 compared to net income of $3,444,000 and $897,000 for 2002 and 2001, respectively. EA’s loss in 2003 reflects the gradual termination of service as contracts expire in northern Maine. The current standard offer pricing in Maine, the lack of wholesale choices and liquidity within northern Maine, and the increased credit requirements associated with acquiring wholesale electricity supply have hampered EA in competing for sales. The Company maintains a conservative risk management philosophy and has limited the transactions that EA can undertake as a buyer or seller in order to limit and mitigate potential transaction risk exposures. EA earnings for 2002 and 2001 were impacted by settlements with its energy provider.
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Energy Atlantic’s historical energy sales can be classified into two general categories: Standard Offer Service (“SOS”) in CMP’s service territory which expired February 28, 2002, and Competitive Energy Supply (“CES”) sales to individual retail customers within the state of Maine. Effective February 27, 2004, EA no longer serves CES or SOS retail customers and has discontinued service. Originally, EA obtained power for the sales in CMP’s territory under an exclusive wholesale power sales agreement with Engage Energy America, LLC.
During the third quarter 2002, EA and Engage concluded their business relationship pursuant to the terms of their agreement. Following completion of the final scheduled audit, the final escrow disbursements were made to EA and Engage on September 30, 2002. As a result of the final account settlement, EA recognized the $4.8 million of additional standard offer service SOS revenue during the third quarter of 2002 with an after-tax impact of $2.9 million, or $1.84 per share.
EA previously entered into a contract for 40% of the output of the WS energy facility for the two years beginning March 1, 2002 and expiring on February 29, 2004. The output from this take-or-pay contract amounted to approximately 55,000 MWH annually and was being used to provide electricity for additional CES sales within MPS’s service territory. This contract was a take-or-pay contract, which carried more counterparty risk than others entered into by EA. To mitigate this risk, EA entered into a contract with NB Power, whereby NB Power committed to buy WS output in excess of load requirements in the MPS service territory at a rate indexed to the price of 3% Sulphur Max No. 6 residential oil into New York Harbor, which was intended to reflect NB Power’s avoided cost, subject to a floor and ceiling. All output was sold to CES customers, therefore limiting the risk that energy would be sold to NB Power. In addition, NB Power committed to sell electricity to EA when load exceeded WS output at a fixed on and off-peak rate.
In addition, EA had a power supply relationship with Duke Energy Trading and Marketing (“DETM”) for electricity in CMP’s service area. In connection with this relationship, and certain transactions between EA and DETM, MPS provided a contractual guarantee on behalf of EA in an aggregate amount of one million dollars ($1,000,000). This guarantee was related specifically to the delivery and/or receipt of electric power between EA and DETM. This guarantee was renewed in September of 2002 for an additional year. Effective March 21, 2003, DETM agreed to waive this credit requirement in lieu of EA’s commitment to maintain a $1 million ($1,000,000) minimum bank account balance. On January 27, 2004, EA notified DETM in writing of the impending expiration of the Master Service Agreement between EA and DETM on March 1, 2004. This correspondence was to notify DETM of EA’s expiration of its commitment to maintain a $1 million ($1,000,000) minimum account balance as credit coverage.
The following illustrates the types of risk EA was exposed to in connection with the contracts for supply and sales:
• Counterparty risk including the possibility of the other parties’ failure to fulfill their contractual obligations to EA such as:
a) Deliverability risk, referring to EA not being able to serve contracted load due to the supplier’s failure to provide energy.
b) Transmission risk, indicating EA’s reliance on utilities, such as the Company, Central Maine Power and Bangor Hydro-Electric, to physically transport energy to EA’s customers.
c) Credit risk exposure, depending on EA’s customers’ ability to pay, which may deteriorate during a general economic downturn or when a commercial customer experiences financial difficulty.
• Market liquidity risk encompasses the risk of being forced to buy or sell energy on the open market. This would have occurred (1) if energy had not been available from WS, NB Power or other energy supply arrangements, while the contracted customer load must still be satisfied or (2) if the existing customer load deteriorated and NB Power could not buy the excess power from WS, as contracted.
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• Forecasting risk exposure includes possible inaccuracy in the estimation of energy supply requirements. One of EA’s suppliers required a 24-month forecast of load for each commitment to a 1 MW block of energy. Although there was no penalty for not using all of the energy, EA could have been assessed a penalty for using more than the amount contracted.
• Market-based cost risk is exposure to transactions tied to market indexes, such as the arrangement to sell excess WS power to NB Power at a current market-indexed rate.
With the expiration of the SOS arrangement in CMP’s service territory, EA has been adversely impacted by the decrease in revenues and correspondingly, earnings. In 2002, EA realized SOS margin in CMP’s service territory of approximately $5.8 million, which included the final account settlement discussed above. EA had no SOS activity in 2003. On February 24, 2003, EA announced its intent to withdraw from the northern Maine market due to the lack of profitability in that market, the lack of price differentiated electric products within the Maritimes and Northern Maine Independent System Administrator markets, and the overall illiquidity of the wholesale power market, as well as other risk factors. EA continued to serve its existing contracts in northern Maine through their expiration on February 27, 2004. CES sales, primarily in northern Maine, were approximately $6.1 million in 2003.
EA’s decision to withdraw from the northern Maine market not only minimized its risk profile, but EA believed this action would substantially relieve any underlying concerns that could exist in connection with the issue of employee sharing and EA’s energy marketing activities within MPS’s service territory. On February 21, 2003 MPS filed with the MPUC an “Application for Exemption of Chapter 304” to exempt the Company and EA from certain management restrictions that have arisen due to this aspect of the corporate relationship. (MPUC Docket No. 2003-122). The proceeding is discussed above in Item 3, “Legal Proceedings” Item 3(iii)(d). In connection with its announced intent to withdraw from the retail electricity markets in northern Maine, EA ceased all of its energy marketing activities in MPS’s service territory as well as the balance of the State, effective March 1, 2003. Currently, EA is an inactive subsidiary and management has ceased all active retail CES activity on behalf of EA within the State of Maine until market conditions, the availability of supply, the mandate for stringent credit requirements and risk environment improve. Management will continue to monitor both U.S. and Canadian deregulated markets to determine the appropriate timing for possible re-entry into the deregulated retail market.
Reorganization Into Holding Company
On October 4, 2002, MPS’s Board of Directors authorized MPS to reorganize into a holding company structure. As a result, MPS became a wholly-owned subsidiary of MAM, the new holding company. Me&NB, remained a subsidiary of MPS, and will remain so until all obligations have terminated, at which time it is proposed the subsidiary may be dissolved. The ownership of EA was also transferred to the holding company, MAM. To achieve this corporate structure, stock in MPS was exchanged for stock in the new holding company through a “reverse triangular merger.” MPS undertook the reorganization in order to maintain its focus on its core regulated business, while at the same time positioning MAM for more diversified growth.
The reorganization required the approval of the MPUC, acceptance of the S-4A registration by the U.S. Securities and Exchange Commission, an application under the Public Utilities Holding Company Act, and approval from the FERC under the Federal Power Act. Among the first steps authorized by the Board was the filing of a petition for MPUC approval on October 31, 2002, and the preparation and filing of documents necessary for other state and federal regulatory approvals. Certain other regulatory and non-regulatory consents were also obtained in connection with MPS’s outstanding indebtedness.
Following the regulatory approval, application and registration process, MPS requested shareholder approval for the reorganization. Prior to MPS’s Annual Shareholder Meeting, specific details concerning the holding company were provided to shareholders. Investor tours and a web cast were held prior to the 2003 Annual Shareholders Meeting to detail plans and answer specific shareholder questions.
Subsequent to its filing, MPS received and responded to several requests for information from the MPUC and the Office of Public Advocate, an intervenor in the proceeding, and met on several occasions with interested parties. The parties settled all issues in the proceeding, and entered a signed Stipulation formally approved by the MPUC on
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March 26, 2003. The text of the MPUC Order, Docket No. 2002-676 may be viewed as Exhibit 99(ao) of this Form 10-K such information is incorporated in this section by this reference. MPS also filed, on March 11, 2003, a Form S-4 Registration Statement with the Securities and Exchange Commission for “Maine & Maritimes Corporation” the entity designated as “HoldCo” in this disclosure. The reorganization became effective June 30, 2003.
At MPS’s Annual Meeting of Shareholders, held on May 30, 2003, shareholders of MPS voted to approve its plan to create a holding company structure, under MAM. Of the shares eligible to vote, 57.07% voted “For” the holding company proposal, 10.19% voted “Against,” and 32.74% abstained or were “broker no votes.” The reorganization was completed by July 1, 2003. No change in beneficial ownership resulted from the reorganization, which is described in more detail in the Form S-4/A of MAM filed with the Commission on April 15, 2003 and is incorporated in this section by this reference. The filing is reviewable on the SEC’s website at “http://www.sec.gov/edgar” or on the MAM Investor Relations page at http://www.maineandmaritimes.com/ corporate/1373T04_CP.PDF.
Under the new holding company corporate structure, MPS became a separate subsidiary of MAM. EA, previously MPS’s unregulated competitive electricity supply company also became a direct subsidiary of, MAM. Me&NB, which is an inactive Canadian company, remained a direct subsidiary of MPS.
Following the July 1, 2003 completion of the reorganization, shares of MPS common stock were converted on the books (with no exchange of certificates) into the same number of shares of common stock of MAM. The MAM common stock shares are currently traded on the AMEX under the ticker symbol “MAM.”
Employees
At the end of 2003, the Company and its subsidiaries had the following full-time employees:
Since the generating asset sale on June 8, 1999, MPS’s Canadian subsidiary, Me&NB has had no employees. The Company’s consolidated payroll costs were $7.1 million for 2003 and $7.3 million for 2002.
Local 1837 of the International Brotherhood of Electrical Workers ratified a three-year contract with MPS, effective October 1, 2002. The agreement included wage increases of 3.25%, 3.35% and 3.5% over the three-year period of the contract.
In November 2002, a Voluntary Early Retirement Program (“VERP”) was offered to employees age fifty-nine and over, with sixteen years or more years of service. Of the thirteen employees eligible for the program, ten accepted the program and retired effective January 1, 2003. In an effort to control medical insurance costs, employee contributions increased by approximately 45%, effective January 1, 2003, and plan deductibles were increased. In addition, all retirees began contributing toward retiree medical coverage.
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Maine Yankee
MPS owns 5% of the common stock of Maine Yankee, which operated an 860 MW nuclear power plant (the “Plant”) in Wiscasset, Maine. On August 6, 1997, the Board of Directors of Maine Yankee voted to permanently cease power operations and to begin decommissioning the Plant.
On September 1, 1997, Maine Yankee estimated the sum of the future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee to be approximately $930 million, of which MPS’s 5% share would be approximately $46.5 million. On nine different occasions dating back to December 1998, Maine Yankee has updated its estimate of decommissioning costs based on the Settlement. Legislation enacted in Maine in 1997 called for restructuring the electric utility industry and provided for recovery of decommissioning costs, to the extent allowed by federal regulation, through the rates charged by the transmission and distribution companies. Based on the Maine legislation and regulation precedent established by the FERC in its opinion relating to the decommissioning of the Yankee Atomic nuclear plant, MPS believes that it is entitled to recover substantially all of its share of such costs from its customers and, as of December 31, 2003, is carrying on its consolidated balance sheet a regulatory asset and a corresponding liability in the amount of $17.8 million, which reflects MPS’s 5% share of Maine Yankee’s September 2003 revised estimate of the remaining decommissioning costs, less actual decommissioning payments made since then, and discounted by a risk-free interest rate.
The MPUC, on January 27, 2002, approved a Stipulation providing for the recovery of stranded investment, for a two-year period from March 1, 2002 until February 29, 2004, which includes MPS’s share of Maine Yankee decommissioning expenses, Maine Yankee replacement power costs, and the remaining Maine Yankee investment.
As of December 31, 2003, deferred fuel of $20.5 million is reflected as a regulatory asset, which includes the Maine Yankee replacement power costs, as well as deferred WS fuel costs.
In accordance with its 1999 FERC rate case settlement, on October 21, 2003, Maine Yankee filed a revised formula rate schedule with the FERC, proposing an effective date of January 1, 2004. The filing contained a revised decommissioning cost estimate and collection schedule to assure that adequate funds are available to safely and promptly decommission the Plant and operate and manage the independent spent fuel storage installation (“ISFSI”). In the filing, Maine Yankee also requested a change in its billing formula and an increase in the level of collection for certain post-retirement benefits. To meet these needs, Maine Yankee proposed to collect an additional $3.77 million per year over current decommissioning collection levels through October 2008, exclusive of any income-tax liability, for the decommissioning and spent-fuel management expense, and to collect from November 2008 through October 2010, the amounts needed to replenish its Spent Fuel Trust for funds previously used for ISFSI construction. On December 19, 2003, the FERC issued an order accepting the new rates effective January 1, 2004, subject to refund pending a hearing. Maine Yankee believes it is entitled to recover the costs underlying the proposed new rates, but cannot predict the outcome of the rate proceeding.
As previously reported, in May 2000, Maine Yankee terminated its decommissioning operations contract with Stone & Webster Engineering Corp. (“Stone & Webster”) pursuant to the terms of the contract. Stone & Webster disputed Maine Yankee’s grounds for the termination. In June 2000, Stone & Webster filed a voluntary petition under Chapter 11 of the United States Bankruptcy Code with the United States Bankruptcy Court for the District of Delaware (see Part 1, Item 3, “Legal Proceedings,” Item 3(iii)(e)). Since the contract termination, Maine Yankee has managed the decommissioning project itself.
In December 2001, Maine Yankee and Federal Insurance Company (“Federal”) entered into a settlement agreement resolving litigation between the parties, pursuant to which Federal paid Maine Yankee $44 million. That amount represented full payment under the performance bond provided by Federal, plus an additional amount under its payment bond reflecting certain payments previously made by Maine Yankee to subcontractors and suppliers who had not been fully paid by Stone & Webster. Maine Yankee deposited the payment in its decommissioning trust fund to offset past and future expenses resulting from the failures of Stone & Webster.
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In addition, Maine Yankee continued to pursue its claim for damages that was originally filed against Stone & Webster and its then parent corporations in August 2000, in the Bankruptcy Court in Delaware. After recognizing the payment from Federal, Maine Yankee asserted a right to recover an additional $21 million in that court from the bankruptcy estates. After extensive interim proceedings and negotiations, in the third quarter of 2003, the major parties agreed to a joint plan of reorganization under which Maine Yankee would have an allowed claim of $20.3 million against the principal bankrupt estate, subject to certain contingencies. Under the plan, Maine Yankee would also have a first lien on any distributions from a related bankrupt estate in the proceeding on any amount needed to increase its actual cash recovery to $18.5 million. On January 13, 2004, Maine Yankee received an initial distribution of $8.4 million, which it deposited in its decommissioning trust fund. The amount of cash that Maine Yankee will actually recover on the balance of its claim remains contingent on a number of factors beyond Maine Yankee’s control that affect the amount of bankrupt estate assets ultimately available to pay the claim. Maine Yankee has settled its litigation claims against Stone & Webster’s bankruptcy estate and Envirocare in connection with Stone & Webster’s bankruptcy proceeding (see Part 1, Item 3, “Legal Proceedings,” Item 3(iii)(e)).
Federal legislation enacted in 1987 directed the Department of Energy (“DOE”) to proceed with the studies necessary to develop and operate a permanent high-level waste (spent fuel) repository at Yucca Mountain, Nevada. The project has encountered delays, and the DOE has indicated that the permanent disposal site is not expected to open before 2010, although originally scheduled to open in 1998.
In accordance with the process set forth in the legislation, in February 2002, the Secretary of Energy recommended the Yucca Mountain site to the President for the development of a nuclear waste repository, and the President then recommended development of the site to Congress. As provided in the statutory procedure, the state of Nevada formally objected to the site in April 2002, and in July 2002, Congress overrode the objection. Construction of the repository requires the approval of the Nuclear Regulatory Commission (“NRC”), upon application of the DOE, and after a public adjudicatory hearing, as well as a second NRC approval after completion of construction to operate the facility. Maine Yankee cannot predict the timing or results of those proceedings.
In November 1997, the U.S. Court of Appeals for the District of Columbia Circuit confirmed the obligation of the DOE under the Nuclear Waste Policy Act of 1982 to take responsibility for spent nuclear fuel from commercial reactors in January 1998. After an unsuccessful effort by Maine Yankee in the same court to compel the DOE to take Maine Yankee’s spent fuel, in June 1998, Maine Yankee filed a claim for money damages in the U.S. Court of Federal Claims for the costs associated with the DOE’s default. In November 1998, the Court granted summary judgment in favor of Maine Yankee, ruling the DOE had violated its contractual obligations, but leaving the amount of damages incurred by Maine Yankee for later determination by the Court. Since then the parties have been engaged in extensive discovery and resolution of pre-trial issues in the damages phase of the proceeding. On June 26, 2003, the Court denied three motions for summary judgment filed by the DOE and indicated in its order that final pretrial submissions were to be due at the end of September 2003, with a trial to follow shortly thereafter. However, at the end of September, the DOE requested an extension of time to complete its discovery, which was later granted, extending the discovery period to February 12, 2004. Maine Yankee is pursuing its claim for determination of damages vigorously, but cannot predict the outcome or timing of the determination.
At the same time, as an interim measure until the DOE meets its contractual obligation to dispose of Maine Yankee’s spent fuel at Yucca Mountain or elsewhere, Maine Yankee constructed an ISFSI, utilizing dry-cask storage, on the Plant site and has completed the process of transferring the spent fuel from the spent-fuel pool to the individual casks and the casks to the ISFSI. Maine Yankee’s total cost of maintaining the ISFSI will be substantially affected by heightened security costs and by the length of time it is required to operate the ISFSI before the DOE honors its contractual obligation to take the fuel from the site. Maine Yankee’s current decommissioning costs estimate is based on an assumption that its operation of the ISFSI will end in 2023, but the actual period of operation and cost may vary.
On January 15, 2003, Maine Yankee notified NAC International (“NAC”), the contractor responsible for providing for the fabrication of the spent-fuel casks and transferring the fuel to the casks and the casks to the ISFSI, that Maine Yankee was terminating its contract with NAC pursuant to the terms of the contract. NAC had been experiencing financial difficulties and had requested relief from the terms of the contract. Maine Yankee believes that NAC had also failed to perform its contractual obligations in accordance with the terms of the contract and provide adequate assurance of its ability to do so in the future. NAC disputed Maine Yankee’s basis for terminating the contract and served Maine Yankee with a demand to arbitrate the dispute and a request for damages. Maine Yankee, in turn, filed
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suit in the U.S. District Court for the District of Maine against NAC, its bonding company, and its parent guarantor, wherein Maine Yankee sought, among other things, damages due to NAC’s failure to perform. Maine Yankee also entered into contracts with the major subcontractors and resumed the transfer of fuel to the ISFSI under its own management.
In April 2003, after extensive negotiations, the parties entered into a comprehensive settlement agreement resolving all the disputed issues and providing for Maine Yankee to replace NAC in managing the completion of the fuel-transfer work. The settlement included a payment for $10.4 million to Maine Yankee to compensate Maine Yankee for higher costs incurred or to be incurred as a result of NAC’s failure to perform its contractual obligations. The payment was reflected in Maine Yankee’s second quarter 2003 results. Although the NAC dispute contributed to a slowdown in the progress of the fuel transfer work in the first quarter of 2003, since then Maine Yankee has implemented additional efficiencies and the pace of work has improved to a point where it has been consistently exceeding the pre-2003 pace. The transfer of spent fuel to the ISFSI was completed in the first quarter of 2004.
The Federal Low-Level Radioactive Waste Policy Amendments Act, enacted in 1986, required states, either alone or in multi-state compacts, to provide for the disposal of low-level radioactive waste generated within their borders. The states of Maine, Texas and Vermont entered into a compact for the disposal of low-level waste over a 30 year period at a then-planned facility in west Texas.
The terms of the compact provided that the state of Maine would contribute $25 million, payable (1) in two equal installments, the first after ratification by Congress and the second upon commencement of operation of the Texas facility, or (2) alternatively, if agreed by the three states, in accordance with the schedule for repayment of bonds issued for the development or operation of the facility. By statute, those costs were to be initially assessed against Maine Yankee, as the operator of a nuclear power plant in Maine. As required by the 1986 Act, the United States Congress ratified the compact in September 1998. However, in October 1998, the Texas Natural Resource Conservation Commission denied a permit for the proposed west Texas site, and efforts to site such a facility in Texas were suspended. Maine Yankee is shipping its low-level waste to other facilities licensed to accept such material.
At its 2002 session, the Maine legislature enacted legislation providing for the withdrawal of the state of Maine from the Texas compact pursuant to the terms of the compact. The legislation cited the 1997 closure of the Maine Yankee plant and the inability of the state of Texas to cause a disposal facility to be built in a timely manner under the compact as the reasons for initiating the withdrawal process. However, in its 2003 session, the Texas legislature enacted a bill that reactivated the process of siting a disposal facility in Texas and provides for Texas to seek payment from Maine of $12.5 million under the compact. By letter dated September 10, 2003, the Attorney General of Texas requested payment of $12.5 million from the state of Maine, to which the state of Maine responded by denying liability. Maine Yankee believes that withdrawal from the compact by the state of Maine is legally justified, but cannot predict the results of the Texas legislation on the state of Maine or Maine Yankee or of any attempt by any party to challenge the state of Maine’s withdrawal from the compact or to assess Maine Yankee for any payments under the compact.
On February 28, 2003, the Nuclear Regulatory Commission approved Maine Yankee’s License Termination Plan (“LTP”). The LTP was approved without any unexpected conditions. In accordance with the plan accepted by the SEC, Maine Yankee has started the redemption of its common stock periodically through 2008.
New Accounting Pronouncements
In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“Statement 143”). Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement the entity either settles the obligation at its recorded amount or incurs a gain or a loss. For rate-regulated entities, any timing differences between rate recovery and book expense would be deferred as either a regulatory asset or a regulatory liability. The Company’s adoption of Statement 143 as of January 1, 2003 did not have a material effect on its financial position or results of operations. There was no effect on net income. Statement 143 provides that if the requirements of Statement 71 are met, a regulatory liability should be recognized for the difference between removal costs collected in rates and actual costs incurred. As of December 31, 2003, and 2002 accrued removal obligations totaling approximately $4.0 million
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and $3.8 million, respectively, which had previously been embedded within accumulated depreciation were reclassified as a regulatory liability.
In December 2003, the FASB issued FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” (“FIN 46R”). FIN 46R provides guidance on the identification of entities for which control is achieved through means other than through voting rights (“variable interest entities”) and on the determination of when such entities are required to be included in the consolidated financial statements of the business enterprise that holds an interest in the variable interest entity. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity’s activities without receiving additional subordinated financial support from other parties. In addition, FIN 46R requires additional related disclosures. Certain disclosure provisions of FIN 46R apply to all financial statements issued after January 31, 2003, the consolidation provisions apply to variable interest entities created after January 31, 2003 and to variable interest entities in which an enterprise obtains an interest after that date, and the remaining provisions, with the exception of interest in special purpose entities, apply at the end of the first fiscal year or interim period ending after March 15, 2004 to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. Application for interest in special purpose entities is required for periods after December 15, 2003. The adoption of the required provisions of FIN 46R as of December 31, 2003 did not have a material impact on the consolidated financial statements. The adoption of the remaining provisions of FIN 46R is not expected to have a material impact on the consolidated financial statements.
On April 30, 2003, the FASB issued Financial Accounting Standards No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (“FAS 149”). FAS 149 amends and clarifies the accounting guidance on (1) derivative instruments (including certain derivative instruments embedded in other contracts) and (2) hedging activities that fall within the scope of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“FAS 133”). FAS 149 amends FAS 133 to reflect decisions that were made: as part of the process undertaken by the Derivatives Implementation Group (“DIG”), which necessitated amending FAS 133; in connection with other projects dealing with financial instruments; and regarding implementation issues related to the application of the definition of a derivative. FAS 149 also amends certain other existing pronouncements, which will result in more consistent reporting of contracts that are derivatives in their entirety or that contain embedded derivatives that warrant separate accounting. FAS 149 is effective (1) for contracts entered into or modified after September 30, 2003, with certain exceptions, and (2) for hedging relationships designated after June 30. The guidance is to be applied prospectively. The adoption of this statement did not have a material impact on the Company’s financial position or results of operations.
On May 15, 2003, the FASB issued Financial Accounting Standards No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“FAS 150”). FAS 150 changes the accounting for certain financial instruments that, under previous guidance, could be classified as equity or “mezzanine” equity, by now requiring those instruments to be classified as liabilities (or assets in some circumstances) in the statement of financial position. FAS 150 requires disclosure regarding the terms of those instruments and settlement alternatives. FAS 150 affects an entity’s classification of the following freestanding instruments: mandatorily redeemable instruments; financial instruments to repurchase an entity’s own equity instruments; financial instruments embodying obligations that the issuer must or could choose to settle by issuing a variable number of its shares or other equity instruments based solely on (a) a fixed monetary amount known at inception or (b) something other than changes in its own equity instruments. FAS 150 does not apply to features embedded in a financial instrument that is not a derivative in its entirety. The guidance in FAS 150 is generally effective for all financial instruments entered into or modified after May 31, 2003, and is otherwise effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this statement did not have a material impact on the Company.
Regulatory Proceedings
For regulatory proceedings, see Part I, Item 3, “Legal Proceedings,” which is incorporated in this section by this reference.
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PART II
Item 7a. Quantitative and Qualitative Disclosures about Market Risk
(a) The Company had material interest rate risk until MPS fixed interest rates on three variable rate debt issues on September 9, 2003 with a derivative interest rate swap transaction. As discussed in previous Form 8-K and 10-Q quarterly filings, MPS had partially mitigated its risk by purchasing a 6% interest rate cap on its two tax-exempt bonds, the 1996 Series and the 2000 Series, issued on MPS’s behalf by the Maine Public Utility Financing Bank. The interest rate cap on the 1996 and 2000 Series expired in November 2003. MPS also purchased a 7% interest rate cap, which expires in 2008, for MPS’s Taxable Electric Rate Stabilization Revenue Notes issued in 1998 on its behalf by the Finance Authority of Maine (“FAME”). Further discussion on these debt issues and the associated interest rate caps is contained in Item 16(a) of this Form 10-K, Note 8 to the Consolidated Financial Statements, “Long-Term Debt,” and is hereby incorporated by this reference. Upon execution of the interest rate swaps on September 9, 2003, MPS effectively fixed through maturity the rates on the 1996 Series due in 2021 and the 2000 Series due in 2025 at 4.57% and 4.68%, respectively. The rate on the 1998 Notes due in 2008 was also fixed at 2.79% through maturity. As of December 31, 2003, the 1996 and 2000 Series and the 1998 FAME Notes had outstanding balances of $13.9 million, $9.0 million and $8.08 million, respectively. The fixed rates are higher than the previous floating rates and continue to be as of the date of this filing. Although incurring no up-front cost to execute the swaps, MPS is currently incurring increased interest expenses. However, Management believes that the fixing of interest rates over the terms of the debt will serve to protect both shareholders and consumers from what it believes to be inevitable upward variable interest rate pressures. See Item 16(a) of this Form 10-K, Note 7 to the Consolidated Financial Statements, “Accumulated Other Comprehensive Income (Loss),” which is hereby incorporated by this reference, for a discussion on the impact on MPS’s financial statements and further description of the interest rate swaps.
(b) The Company’s unregulated marketing subsidiary, EA was previously engaged in retail and wholesale energy transactions for purposes other than trading. This activity exposed EA to a number of risks such as market liquidity, deliverability and credit risk. Prior to withdrawing from retail marketing activities EA sought to assure that risks were identified, evaluated and actively managed. These risks are summarized above under the section “Energy Atlantic Activities.”
Item 8. Financial Statements and Supplementary Data
(a) The following financial statements and supplementary data are included in Item 16(a), the Company’s Consolidated Financial Statements, and are incorporated herein by this reference:
Report of Independent Auditors.
Statements of Consolidated Income for the years ended December 31, 2003, 2002 and 2001.
Statements of Consolidated Cash Flows for the years ended December 31, 2003, 2002 and 2001.
Consolidated Balance Sheets as of December 31, 2003 and 2002.
Statements of Consolidated Common Shareholders’ Equity for the years ended December 31, 2003, 2002 and 2001.
Consolidated Statements of Long-Term Debt as of December 31, 2003 and 2002.
Notes to Consolidated Financial Statements.
Item 9. Changes In And Disagreements With Accountants On Accounting and Financial Disclosure
None.
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PART III
Item 10. Directors and Executive Officers of the Registrant
Information with regard to the Directors of the registrant is set forth in the proxy statement of the registrant relating to its 2004 Annual Meeting of Stockholders, which information is incorporated herein by this reference. Certain information regarding executive officers is set forth below and also in the proxy statement of the registrant relating to the 2004 Annual Meeting of Stockholders, under “Compliance with Section 16(a) of the Securities and Exchange Act of 1934,” which information is incorporated by this reference.
Executive Officers
The executive officers of the registrant are as follows:
James Nicholas Bayne was elected to the position of President and Chief Executive Officer of MPS effective September 1, 2002. He joined MPS as President-Elect on March 18, 2002, and became President on May 15, 2002. Prior to joining MPS, Mr. Bayne served as an executive consultant to the energy, utilities and energy-software industries. During 2001, he served as the Chief Executive Officer and as a member of the board of directors for Aspect, LP, a Houston, Texas-based energy risk management and FASB 133 ASP software firm, wholly-owned by Koch Ventures/Koch Industries. From 2000 to 2001, he served as Senior Vice President for Strategic Advisory Services for Energy E-Comm.com, providing consulting services to the energy and utilities industries. From 1997 to 2000 he served as a member of executive management and as a member of the board of directors of DukeSolutions, Inc., Duke Energy’s unregulated retail energy services company, serving as Senior Vice President for Energy Sales and Operations. Prior to joining DukeSolutions, Mr. Bayne served as a member of executive management and Vice President of Marketing, Economic Development and Participant Services for MEAG Power, the nation’s largest electric generation and transmission joint action agency headquartered in Atlanta, Georgia. He also served as a member of management of Carolina Power & Light Company in Raleigh, North Carolina and began his electric utility career with Central Electric Power Cooperative, Inc. in Columbia, South Carolina.
Kurt A. Tornquist was elected to the position of Senior Vice President and Chief Financial Officer, Treasurer, effective July 11, 2003. He has been an employee of the Company since July 1, 1992, joining MPS as Assistant Controller. On June 1, 1994, Mr. Tornquist was appointed Controller and Assistant Treasurer. On September 2, 2002, Mr. Tornquist was appointed to the position of Vice President, Corporate Performance and Development. Prior to joining MPS, Mr. Tornquist held the position of Manager of Financial Accounting for a major international paper corporation. Mr. Tornquist is a graduate of the University of Maine and of Wharton’s Advanced Management Program and is a Certified Public Accountant.
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Larry E. LaPlante was elected to the position of Vice President, Chief Accounting Officer, Controller, Clerk, Assistant Treasurer and Assistant Secretary effective July 11, 2003. On June 1, 1999, Mr. LaPlante was elected to the position of Vice President, Treasurer and Chief Financial Officer and on February 15, 2002, appointed Secretary and Clerk of the Company. He has been an employee of the Company since November 4, 1983, starting as Controller. In May 1984, he was also appointed Assistant Secretary and Assistant Treasurer until his election as Vice President, Finance, Administration and Treasurer. Mr. LaPlante is a graduate of the University of Maine and a Certified Public Accountant. Prior to joining the Company, Mr. LaPlante spent ten years in public accounting.
John P. Havrilla was elected to the position of Vice President, Business Development and Unregulated Businesses, effective November 15, 2002. Mr. Havrilla also holds the position of Chief Operating Officer of The Maricor Group, the company’s unregulated subsidiary, as well as Chief Operating Officer of Maricor Ltd, The Maricor Group’s unregulated Canadian subsidiary. Mr. Havrilla has over twenty-three years of regulated and unregulated energy experience having served as Vice President of Strategic and Financial Systems for Duke Energy’s unregulated retail energy services company. Prior to joining Duke Power (ultimately Duke Energy) in their mergers and acquisitions area, he spent sixteen years in positions of increasing responsibility with New York State Electric & Gas (NYSEG). During his career he has led the successful acquisition and integration of nine U.S. and Canadian firms. He is a professional engineer licensed in the states of Maine and New York and graduated from Pennsylvania State University with a B.S. degree in electrical engineering technology.
Scott L. Sells, Esquire, of the law firm of Curtis Thaxter Stevens Broder & Micoleau, LLC, was elected to the position of General Counsel, Secretary and Assistant Clerk on July 11, 2003. On July 12, 2002 Mr. Sells was elected as General Counsel. Mr. Sells has been with Curtis Thaxter for three years, and has been a member for the entire period. Mr. Sells entered the practice of law in 1991 as Assistant Attorney General for the state of Colorado. He then entered private practice, where his practice emphasized energy, environmental and utility matters. Mr. Sells then joined Duke Energy Corporation, in 1998, as Assistant General Counsel. Prior to practicing law, Mr. Sells served as a geophysicist with Mobil Oil Corporation and the Amoco Production Company, where he was involved in both domestic and international oil and gas exploration and development projects. Mr. Sells received a Bachelor of Science degree in Geology from the University of Rhode Island and received a Juris Doctorate degree and a Master’s in Business Administration degree from the University of Denver, where he was an American Jurisprudence Award recipient.
With the exception of Mr. Sells, each executive office is a full-time position and has been the principal occupation of each officer since first elected. All officers were elected to serve until the next annual election of officers and until their successors shall have been duly chosen and qualified. The next annual election of officers will be on May 11, 2004.
There are no family relationships among executive officers.
Item 11. Executive Compensation
Information for this item is set forth in the proxy statement of the registrant relating to its 2004 Annual Meeting of Stockholders, which information is incorporated herein by this reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information for this item is set forth in the proxy statement of the registrant relating to its 2004 Annual Meeting of Stockholders, which information is incorporated herein by this reference.
Item 13. Certain Relationships and Related Transactions
Not applicable.
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Item 14. Controls and Procedures
1. Evaluation of disclosure controls and procedures.
Based on reviews by the Company’s President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of the Company’s disclosure controls and procedures, conducted within 90 days of the filing of this Form 10-K, as evidenced by the certifications appearing at the end of this Form 10-K, the aforementioned officers have concluded that the controls are working effectively.
2. Changes in Internal Controls
There have not been any significant changes in the Company’s internal controls or in other factors that could significantly offset these controls subsequent to the date of their evaluation; there were also no corrective actions with regard to significant deficiencies and material weaknesses.
PART IV
Item 15. Principal Accountant Services and Fees.
Information for this item is set forth in the proxy statement of the registrant relating to its 2004 Annual Meeting of Stockholders, which information is incorporated herein by this reference.
Item 16. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) (1) Financial Statements
Report of Independent Auditors
Statements of Consolidated Income for years ended December 31, 2003, 2002 and 2001
Statements of Consolidated Cash Flows for the years ended December 31, 2003, 2002 and 2001
Consolidated Balance Sheets as of December 31, 2003 and 2002
Statements of Consolidated Common Shareholders’ Equity for the years ended December 31, 2003, 2002 and 2001
Consolidated Statements of Long-Term Debt as of December 31, 2003 and 2002
Notes to Consolidated Financial Statements
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Report of Independent Auditors
To The Directors and Shareholders of
Maine & Maritimes Corporation:
In our opinion, the consolidated financial statements listed in the index appearing under Item 16(a)(1) on Page 50 present fairly, in all material respects, the financial position of Maine & Maritimes Corporation and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 16(a)(2) on Page 82, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Boston, MA
February 28, 2004
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MAINE & MARITIMES CORPORATION AND SUBSIDIARIES
Statements of Consolidated Income
See Notes to Consolidated Financial Statements
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MAINE & MARITIMES CORPORATION AND SUBSIDIARIES
Statements of Consolidated Cash Flows
See Notes to Consolidated Financial Statements
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MAINE & MARITIMES CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
See Notes to Consolidated Financial Statements
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MAINE & MARITIMES CORPORATION AND SUBSIDIARIES
Capitalization and Liabilities
See Notes to Consolidated Financial Statements
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MAINE & MARITIMES CORPORATION AND SUBSIDIARIES
Statement of Consolidated Common Shareholders’ Equity
See Notes to Consolidated Financial Statements.
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MAINE & MARITIMES CORPORATION AND SUBSIDIARIES
Statement of Long-Term Debt
Current Maturities and Redemption Requirements for the Succeeding Five Years and Thereafter Are as Follows:
See Notes to Consolidated Financial Statements.
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NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
Consolidation and Basis of Presentation The accompanying consolidated financial statements include the accounts of Maine & Maritimes Corporation (the “Company” or “MAM”) and the following wholly-owned active subsidiaries and affiliates:
• Maine Public Service Company (“MPS”), regulated transmission and distribution company and its wholly-owned inactive Canadian subsidiary, Maine and New Brunswick Electrical Power Company, Limited, (“Me&NB”);
• Energy Atlantic, LLC (“EA”), unregulated competitive electricity marketing subsidiary, which was owned by MPS until June 30, 2003;
• Maine & Maritimes Energy Services Company (“MAMES”) dba “The Maricor Group” and its wholly-owned Canadian subsidiary, Maricor, Ltd, (“Maricor”) providing energy management and engineering services.
MAM, a holding company organized effective June 30, 2003, owns all of the common stock of MPS. All of the shares of MPS common stock were converted into an equal number of shares of MAM common stock, which are listed on the American Stock Exchange under the symbol MAM. The reorganization was approved by MPS’s shareholders at the annual meeting on May 30, 2003. The U.S. Securities and Exchange Commission (“SEC”) had previously accepted MAM’s S-4A Registration Statement for registration and other appropriate state and federal regulatory agencies issued the necessary approvals on various dates in 2003. Amounts shown for 2002 and 2001 were reported by MPS. MPS also reported amounts in the first three months of 2003.
MAMES and Maricor were organized on November 6, 2003, and November 12, 2003, respectively. On December 1, 2003, Maricor acquired a mechanical and electrical engineering firm located in New Brunswick, Canada.
All inter-company transactions between MAM and it subsidiaries have been eliminated in consolidation.
The financial statements of the Company were prepared in accordance with accounting principles generally accepted in the United States of America.
Regulations
MPS is subject to the regulatory authority of the Maine Public Utilities Commission (“MPUC”) and the Federal Energy Regulatory Commission (“FERC”). As a result of the ratemaking process, the applications of accounting principles by the Company differ in certain respects from applications by non-regulated businesses.
Estimates
The preparation of financial statements in conformity with generally accepted accounting principles asserted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Foreign Currency Translation
The functional currency of Me&NB and Maricor is the U.S. dollar. Accordingly, translation gains and losses are included in other income. Income and expenses are translated at rates of exchange prevailing at the time the income is earned or the expenses are incurred. Assets and liabilities are translated at year-end exchange rates.
Deferred Fuel and Purchased Energy Costs
Certain Wheelabrator-Sherman (“WS”) fuel costs and the sharing provisions for Maine Yankee replacement power costs were deferred for future recovery as defined in MPS’s rate plan until March 1, 2000. All other fuel and purchased power costs were expensed as incurred. These costs are currently being recovered in rates and the related deferred asset is being amortized, accordingly. Beginning March 1, 2002, the excess of the cost over the sales price of WS fuel is being deferred. The resulting deferred asset is expected to be collected in future rates as approved by the MPUC. See Note 12, “Commitments, Contingencies and Regulatory Matters,” regarding MPUC rate orders on the recovery of stranded costs.
Regulatory Assets and Liabilities
Pursuant to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation, the Company capitalizes, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric rates. It also records, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs.
Unfunded future income taxes and deferred income taxes are amortized as the related temporary differences reverse. Unamortized loss on debt re-acquisitions is amortized over the lives of the related debt issues. Nuclear plant obligations, demand-side management program
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costs, gain on sale of generation assets, other regulatory assets and other regulatory liabilities are amortized over various periods in accordance with MPS’s current rate plans. MPS earns a return on substantially all regulatory assets for which funds have been spent.
The Company believes that MPS’s electric transmission and distribution operations continue to meet the requirements of SFAS 71, and that regulatory assets associated with those operations, as well as any generation-related costs that the MPUC has determined to be recoverable from ratepayers, also meet the criteria. At December 31, 2003, $66.0 million of regulatory assets remained on MPS’s books. These assets will be amortized over various periods in accordance with MPUC approved rate orders.
Revenue Recognition
Operating revenues include MPS’s sales billed on a cycle billing basis and estimated unbilled revenues for electric service rendered prior to the normal billing cycle. Operating revenues also include EA’s Competitive Electricity Supply (“CES”) sales, since CES activity is recorded on a gross basis to include the related revenues and purchased power expenses. CES sales are recorded in this manner because EA negotiated the price directly with the customer, maintains customer service responsibility and has collection risk. For Standard Offer Service (“SOS”), revenues were received and expenses were paid directly by an escrow agent which was controlled by Engage Energy America, LLC (“Engage”). EA received a percentage of the net profit from the sale of energy. The utilities bore SOS account collection risk, as they were required to remit the amounts billed 26 days after the billing date to the escrow account mentioned above and maintain the billing and customer service relationship. EA recorded the accrued net margin of the SOS activity as revenue in the financial statements. Additionally, EA’s activity has been accounted for as non-trading since management has determined it does not meet the definition of a trader as defined in EITF 98-10, as modified by EITF 02-03.
In July, 2000, MPS began recording the difference between the approved tariff rate for two large industrial customers and their current special discount rates, under contracts approved by the MPUC, as accrued revenue. The resulting deferred asset will be subsequently collected in rates as approved by the MPUC, and during 2003 and 2002, $280,000 and $233,000 were recognized as stranded costs. During 2002 and 2001, $200,000 and $961,000, respectively, were recognized as revenue as flexible pricing adjustments, as described in Note 12, “Commitments, Contingencies and Regulatory Matters - MPUC Approves Elements of Rates Effective March 1, 2000, and MPUC Approves Stranded Cost Revenue Requirements Effective March 1, 2002.”
Utility Plant
Utility plant for MPS is stated at original cost of contracted services, direct labor and materials, as well as related indirect construction costs including general engineering, supervision, and similar overhead items and allowances for the cost of equity and borrowed funds used during construction (“AFUDC”). The cost of utility plant which is retired is charged to accumulated depreciation. The cost of removal less salvage is charged to Accrued Removal Obligations. The cost of maintenance and repairs, including replacement of minor items of property, are charged to maintenance expense as incurred. MPS’s property, with minor exceptions, is subject to first and second mortgage liens.
Costs which are disallowed or are expected to be disallowed for recovery through rates are charged to expense at the time such disallowance is probable.
Depreciation and Amortization
Utility plant depreciation is provided on composite basis using the straight-line method, based on rates approved by the MPUC and the FERC. The composite depreciation rate, expressed as a percentage of average depreciable plant in service, was approximately 3.20%, 3.10% and 3.37% for 2003, 2002, and 2001, respectively.
Bond issuance costs and premiums paid upon early retirements are amortized over the terms of the related debt. Recoverable Seabrook costs and deferred regulatory expenses are amortized over the period allowed by regulatory authorities in the related rate orders. Recoverable Seabrook costs are being amortized principally over thirty years (See Note 12, “Commitments, Contingencies and Regulatory Matters - Seabrook Nuclear Power Project”).
Income Taxes
Statement of Financial Accounting Standards No. 109 (“SFAS 109”), “Accounting for Income Taxes,” requires an asset and liability approach to accounting and reporting income taxes. SFAS No. 109 prohibits net-of-tax accounting and requires the establishment of deferred taxes on all differences between the tax basis of assets or liabilities and their basis for financial reporting.
MPS has deferred investment tax credits and amortizes the credits over the remaining estimated useful life of the related utility plant.
MPS records regulatory assets or liabilities related to certain deferred tax liabilities or assets, representing its expectation that, consistent with current and expected ratemaking, these taxes will be recovered from or returned to customers through future rates.
Investments in Associated Companies
MPS records its investments in Associated Companies (see Note 5, “Investments in Associated Companies”) using the equity method.
Pledged Assets
The common stock of Me&NB is pledged as additional collateral for the first and second mortgage and collateral trust bonds of MPS.
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Inventory
Inventory for MPS is stated at average cost.
Cash and Cash Equivalents
For purposes of the Statements of Consolidated Cash Flows, the Company considers all highly liquid securities with a maturity, when purchased, of three months or less to be cash equivalents.
Goodwill
The excess of the cost over fair value of net assets of purchased businesses is recorded as goodwill. The Company evaluates the carrying value of goodwill for impairment at least annually and on an interim basis if there are indications that goodwill might be impaired. Any impairments would be recognized when the fair value of goodwill is less than its carrying value.
Financial Instruments
MPS has certain financial instruments, interest rate caps and swaps, on three variable rate long-term debt issues that qualify as derivatives. Interest rate caps involve the exchange of cash for a cap on the interest rate MPS can be charged. Interest rate swaps involve the exchange of cash and the exchange of a variable rate payment for a fixed rate payment. On January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended by SFAS 137, 138 and 149, which establishes accounting and reporting standards for derivative instruments and for hedging activities. SFAS 133 requires that an entity recognize derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. The accounting for changes in the fair value of the derivative depends on the intended use of the derivative and the resulting designation. See Note 7, “Accumulated Other Comprehensive Income (Loss)” for additional disclosure regarding the treatment of these interest rate instruments.
Stock Option Plan At December 31, 2003, the Company had one stock-based employee compensation plan, which is described more fully in Note 9, “Stock Compensation Plan.” The Company accounts for this plan in accordance with the expense provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123 “Accounting for Stock Based Compensation.”
Reclassifications
Certain reclassifications have been made to the 2002 and 2001 financial statement amounts in order to conform to the 2003 presentation.
Earnings Per Share
Basic earnings per share (“EPS”) is determined by dividing net income by the weighted-average number of shares of common stock outstanding during the period. The weighted-average common shares outstanding for diluted EPS include the incremental effect of stock options issued. There was no difference between basic and diluted earnings per share for the three years in the period ended December 31, 2003. Options to purchase shares of common stock of 5,250 shares at $30.45 per share granted June 1, 2002 and 5,250 shares at $32.51 per share granted June 1, 2003. These options to purchase shares were not included in the computation of diluted EPS because the options’ exercise price was approximately equal to the market price of the common shares and, therefore, the effect would be anti-dilutive. The options, which expire on May 30, 2012 and May 30, 2013, respectively, were still outstanding at the end of year 2003.
Accounting Pronouncements
In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“Statement 143”). Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement the entity either settles the obligation at its recorded amount or incurs a gain or a loss. For rate-regulated entities, any timing differences between rate recovery and book expense would be deferred as either a regulatory asset or a regulatory liability. The Company’s adoption of Statement 143 as of January 1, 2003 did not have a material effect on its financial position or results of operations. There was no effect on net income. Statement 143 provides that if the requirements of Statement 71 are met, a regulatory liability should be recognized for the difference between removal costs collected in rates and actual costs incurred. As of December 31, 2003 and 2002, accrued removal obligations totaling approximately $4.0 million and $3.8 million, respectively, which had previously been embedded within accumulated depreciation were reclassified as a regulatory liability.
In December 2003, the FASB issued FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” (“FIN 46R”). FIN 46R provides guidance on the identification of entities for which control is achieved through means other than through voting rights (“variable interest entities”) and on the determination of when such entities are required to be included in the consolidated financial statements of the business enterprise that holds an interest in the variable interest entity. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity’s activities without receiving additional subordinated financial support from other parties. In addition, FIN 46R requires additional related disclosures. Certain disclosure provisions of FIN 46R apply to all financial statements issued after January 31, 2003, the consolidation provisions apply to variable interest entities created after January 31, 2003 and to variable interest entities in which an enterprise obtains an interest after that date, and the remaining provisions, with the exception of interest in special purpose entities, apply at the end of the first fiscal year or interim period ending after March 15, 2004 to variable interest entities in which an
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enterprise holds a variable interest that it acquired before February 1, 2003. Application for interest in special purpose entities is required for periods after December 15, 2003. The adoption of the required provisions of FIN 46R as of December 31, 2003 did not have a material impact on the consolidated financial statements. The adoption of the remaining provisions of FIN 46R is not expected to have a material impact on the consolidated financial statements.
On April 30, 2003, the FASB issued Financial Accounting Standards No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (“FAS 149”). FAS 149 amends and clarifies the accounting guidance on (1) derivative instruments (including certain derivative instruments embedded in other contracts) and (2) hedging activities that fall within the scope of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“FAS 133”). FAS 149 amends FAS 133 to reflect decisions that were made: as part of the process undertaken by the Derivatives Implementation Group (“DIG”), which necessitated amending FAS 133; in connection with other projects dealing with financial instruments; and regarding implementation issues related to the application of the definition of a derivative. FAS 149 also amends certain other existing pronouncements, which will result in more consistent reporting of contracts that are derivatives in their entirety or that contain embedded derivatives that warrant separate accounting. FAS 149 is effective (1) for contracts entered into or modified after September 30, 2003, with certain exceptions, and (2) for hedging relationships designated after June 30. The guidance is to be applied prospectively. The adoption of this statement did not have a material impact on the Company’s financial position or results of operations.
On May 15, 2003, the FASB issued Financial Accounting Standards No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“FAS 150”). FAS 150 changes the accounting for certain financial instruments that, under previous guidance, could be classified as equity or “mezzanine” equity, by now requiring those instruments to be classified as liabilities (or assets in some circumstances) in the statement of financial position. FAS 150 requires disclosure regarding the terms of those instruments and settlement alternatives. FAS 150 affects an entity’s classification of the following freestanding instruments: mandatorily redeemable instruments; financial instruments to repurchase an entity’s own equity instruments; financial instruments embodying obligations that the issuer must or could choose to settle by issuing a variable number of its shares or other equity instruments based solely on (a) a fixed monetary amount known at inception or (b) something other than changes in its own equity instruments. FAS 150 does not apply to features embedded in a financial instrument that is not a derivative in its entirety. The guidance in FAS 150 is generally effective for all financial instruments entered into or modified after May 31, 2003, and is otherwise effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this statement did not have a material impact on the Company.
2. INCOME TAXES
A summary of Federal, Canadian and State income taxes charged (credited) to income is presented below. For accounting and ratemaking purposes, income tax provisions included in “Operating Expenses” reflect taxes applicable to revenues and expenses allowable for ratemaking purposes on MPS regulated activities and unregulated activities for MAM, MAMES, Me&NB and Maricor. The tax effect of items not included in rate base or normal operating activities is allocated as “Other Income (Deductions).”
The effective income tax rates differ from the U.S. statutory rate as follows:
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The elements of deferred income tax expense (credit) are as follows (dollars in thousands):
The Company has not accrued U.S. income taxes on the undistributed earnings of Me&NB, as the withholding taxes due on the distribution of any remaining amount would be principally offset by foreign tax credits. No dividends were received from Me&NB in 2003, 2002 or 2001.
The following summarizes accumulated deferred income tax (assets) and liabilities established on temporary differences under SFAS 109 as of December 31, 2003 and 2002:
3. ENERGY ATLANTIC
EA’s net loss for 2003 was $116,000 compared to net income of $3,444,000 and $897,000 for 2002 and 2001, respectively. EA’s loss in 2003 reflects the gradual termination of service as contracts expire in northern Maine. The current standard offer pricing in Maine, the lack of wholesale choices and liquidity within northern Maine, and the increased credit requirements associated with acquiring wholesale electricity supply have hampered EA in competing for sales. The Company maintains a conservative risk management philosophy and has limited the transactions that EA can undertake as a buyer or seller in order to limit and mitigate potential transaction risk exposures. EA earnings for 2002 and 2001 were impacted by settlements with its energy provider.
Energy Atlantic’s historical energy sales can be classified into two general categories: Standard Offer Service (“SOS”) in CMP’s service territory which expired February 28, 2002, and Competitive Energy Supply (“CES”) sales to individual retail customers within the state of Maine. Effective February 27, 2004, EA no longer serves CES or SOS retail customers and has discontinued service. Originally, EA obtained power for the sales in CMP’s territory under an exclusive wholesale power sales agreement with Engage Energy America, LLC.
During the third quarter 2002, EA and Engage concluded their business relationship pursuant to the terms of their agreement. Following completion of the final scheduled audit, the final escrow disbursements were made to EA and Engage on September 30, 2002. As a result of the final account settlement, EA recognized the $4.8 million of additional standard offer service SOS revenue during the third quarter of 2002 with an after-tax impact of $2.9 million, or $1.84 per share.
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EA previously entered into a contract for 40% of the output of the WS energy facility for the two years beginning March 1, 2002 and expiring on February 29, 2004. The output from this take-or-pay contract amounted to approximately 55,000 MWH annually and was used to provide electricity for additional CES sales within MPS’s service territory. This contract was a take-or-pay contract, which carried more counterparty risk than others entered into by EA. To mitigate this risk, EA entered into a contract with NB Power, whereby NB Power committed to buy WS output in excess of load requirements in MPS’s service territory at a rate indexed to the price of 3% Sulphur Max No. 6 residential oil into New York Harbor, which was intended to reflect NB Power’s avoided cost, subject to a floor and ceiling. All output was sold to CES customers, therefore limiting the risk that energy would be sold to NB Power. In addition, NB Power committed to sell electricity to EA when load exceeded WS output at a fixed on and off-peak rate.
In addition, EA had a power supply relationship with Duke Energy Trading and Marketing (“DETM”) for electricity in CMP’s service area. In connection with this relationship, and certain transactions between EA and DETM, MPS provided a contractual guarantee on behalf of EA in an aggregate amount of one million dollars ($1,000,000). This guarantee was related specifically to the delivery and/or receipt of electric power between EA and DETM. This guarantee was renewed in September of 2002 for an additional year. Effective March 21, 2003, DETM agreed to waive this credit requirement in lieu of EA’s commitment to maintain a $1 million ($1,000,000) minimum bank account balance. On January 27, 2004, EA notified DETM in writing of the impending expiration of the Master Service Agreement between EA and DETM on March 1, 2004. This correspondence was to notify DETM of EA’s expiration of its commitment to maintain a $1 million ($1,000,000) minimum account balance as credit coverage.
The following illustrates the types of risk EA was exposed to in connection with the contracts for supply and sales:
• Counterparty risk, including the possibility of the other parties’ failure to fulfill their contractual obligations to EA such as:
a) Deliverability risk, referring to EA not being able to serve contracted load due to the supplier’s failure to provide energy.
b) Transmission risk, indicating EA’s reliance on utilities, such as the Company, Central Maine Power and Bangor Hydro-Electric, to physically transport energy to EA’s customers.
c) Credit risk exposure, depending on EA’s customers’ ability to pay, which may deteriorate during a general economic downturn or when a commercial customer experiences financial difficulty.
• Market liquidity risk encompasses the risk of being forced to buy or sell energy on the open market. This would have occurred (1) if energy had not been available from WS, NB Power or other energy supply arrangements, while the contracted customer load must still be satisfied or (2) if the existing customer load deteriorated and NB Power could not buy the excess power from WS, as contracted.
• Forecasting risk exposure includes possible inaccuracy in the estimation of energy supply requirements. One of EA’s suppliers required a 24-month forecast of load for each commitment to a 1 MW block of energy. Although there was no penalty for not using all of the energy, EA could have been assessed a penalty for using more than the amount contracted.
• Market-based cost risk is exposure to transactions tied to market indexes, such as the arrangement to sell excess WS power to NB Power at a current market-indexed rate.
With the expiration of the SOS arrangement in CMP’s service territory, EA has been adversely impacted by the decrease in revenues and correspondingly, earnings. In 2002, EA realized SOS margin in CMP’s service territory of approximately $5.8 million, which included the final account settlement discussed above. EA had no SOS activity in 2003. On February 24, 2003, EA announced its intent to withdraw from the northern Maine market due to the lack of profitability in that market, the lack of price differentiated electric products within the Maritimes and Northern Maine Independent System Administrator markets, and the overall illiquidity of the wholesale power market, as well as other risk factors. EA continued to serve its existing contracts in northern Maine through their expiration on February 27, 2004. CES sales, primarily in northern Maine, were approximately $6.1 million in 2003.
EA’s decision to withdraw from the northern Maine market not only minimized its risk profile, but EA believed this action would substantially relieve any underlying concerns that could exist in connection with the issue of employee sharing and EA’s energy marketing activities within MPS’s service territory. On February 21, 2003 MPS filed with the MPUC an “Application for Exemption of Chapter 304” to exempt the Company and EA from certain management restrictions that have arisen due to this aspect of the corporate relationship. (MPUC Docket No. 2003-122). In connection with its announced intent to withdraw from the retail electricity markets in northern Maine, EA has ceased all of its energy marketing activities in MPS’s service territory, as well as the balance of the state, effective March 1, 2003.
Currently, EA is an inactive subsidiary and management has ceased all active retail CES activity on behalf of EA within the state of Maine until market conditions, the availability of supply, the mandate for stringent credit requirements and risk environment improve. Management will continue to monitor both U.S. and Canadian deregulated markets to determine the appropriate timing for possible re-entry into the deregulated retail market.
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4. SEGMENT INFORMATION
For 2003, the Company operated in three segments, with MPS providing regulated transmission and distribution services, EA performing unregulated power marketing services and MAM providing corporate oversight functions. The “Other” column consists primarily of elimination activity. The table below summarizes segment activity for 2003, 2002 and 2001.
The Company’s reportable segments include the electric utility portion of the business---MPS and its inactive wholly-owned Canadian subsidiary, Me&NB; the energy marketing portion of the business---EA; and the holding company - MAM with its other subsidiaries, MAMES and Maricor formed in late 2003. The accounting policies of the segments are the same as those described in Note 1, “Summary of Significant Accounting Policies.” MAM did not have any material assets or operations until it became a holding company on June 30, 2003; however, MPS incurred expenses associated with the formation of MAM, which totaled $639,000 in 2003, and were classified as unregulated operations and maintenance expenses. MAM provides certain administrative support services to MPS and EA, and MPS provides certain support services to MAM and EA, which are billed to the respective entities at cost, based on a combination of direct charges and allocations. The Company is organized based on products and services.
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For 2003 and 2002, total assets reflect the reclassification of accrued removal obligations as a liability from accumulated depreciation.
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5. INVESTMENTS IN ASSOCIATED COMPANIES
MPS owns 5% of the common stock of Maine Yankee Atomic Power Company (“Maine Yankee”), a jointly-owned nuclear electric power company, and 7.49% of the common stock of the MEPCO, a jointly-owned electric transmission company. MPS records its investment in MEPCO and Maine Yankee using the equity method. For additional information, see Note 12, “Commitments, Contingencies and Regulatory Matters - Capacity Arrangements - Maine Yankee” regarding the closing and decommissioning of Maine Yankee.
Dividends received during 2003, 2002, and 2001 from Maine Yankee were $301,050, $99,828 and $206,000, respectively, and from MEPCO $99,205, $7,249 and $7,249, respectively. In 2003, 2002 and 2001, MPS also received Maine Yankee stock redemptions of $524,724, $375,277 and $499,484 respectively. Substantially all earnings of Maine Yankee and MEPCO are distributed to investor companies. Condensed financial information (unaudited) for Maine Yankee and MEPCO is as follows:
In accordance with a plan approved by the Securities and Exchange Commission, Maine Yankee has started the redemption of its common stock periodically through 2008.
6. SHORT-TERM CREDIT ARRANGEMENTS
MPS has a revolving credit arrangement with two banks for borrowings up to $6 million. The revolving credit agreement is subject to extension with the consent of the participating banks and has been extended through June 8, 2004. MPS is currently seeking an extension of this facility and management believes these efforts will be successful. These agreements contain certain restrictive covenants including interest coverage tests and debt-to-equity ratios. As of December 31, 2003, MPS was in compliance with those covenants. MPS can utilize, at its discretion, two types of loan options: A Loans, which are provided on a pro rata basis in accordance with each participating bank’s share of the commitment amount, and B Loans, which are provided as arranged between MPS and each of the participating banks. The A Loans, at MPS’s option, bear interest equal to either the agent bank’s prime rate or LIBOR-based pricing. MPS also pays a quarterly commitment fee of .50% of the unused portion of the A Loans. The B Loans bear interest as arranged between MPS and the participating bank. As of December 31, 2003, A Loans for $5.0 million were outstanding under the revolving credit arrangement at an interest rate of 2.5625%, as well as a B Loan of $200,000 of 2.76%. An A Loan for $2.0 million and a B Loan for $800,000 were outstanding as of December 31, 2002 under the revolving credit arrangement at interest rates of 2.875% and 3.02%, respectively.
On October 1, 2003, MPS executed an additional $3 million line of credit with the Bank of New York. This new facility is unsecured and will expire on March 29, 2004. MPS is currently seeking an extension of this facility and management believes these efforts will be successful. Interest rates on the new facility are comparable to the rates on the existing revolving credit agreement. The additional facility provides an additional source of short-term borrowings in the event required borrowings exceed the existing revolving credit agreement. As of December 31, 2003, $1 million was outstanding on the facility at 2.8125%.
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EA has a revolving line of credit with a bank, for $1.2 million. In May of 2003, the line was extended until March 29, 2004. Interest is based on the bank’s prime lending rate. As of December 31, 2003, EA was in compliance with the covenants set forth by the line of credit agreement. The line was not used during 2003 and 2002 and had no balance outstanding as of December 31, 2003 or December 31, 2002.
7. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
MPS has three issues of long-term debt with variable interest rates. Pursuant to its rate order in MPUC Docket 2003-85, as more fully explained in Note 12, “Commitments, Contingencies and Regulatory Matters, MPUC Approves Rate Increase,” MPS agreed to fix its interest rates and the MPUC allowed recovery of the fixed interest costs in rates. On September 9, 2003, MPS executed swap agreements for the three variable rate issues, locking in the rates over the remaining terms of the issues. For the Finance Authority of Maine (“FAME”) 1998 Taxable Elective Rate Stabilization Revenue Notes due 2008, the effective fixed interest rate has been set at 2.79%. For the two series of tax-exempt bonds issued by the Maine Public Utilities Financing Bank (“MPUFB”), the effective fixed interest rates for the 1996 Series due 2021 and the 2000 Series due 2025 are 4.57% and 4.68% respectively.
At the end of 2003, the fair value of these qualified cash flow hedges was ($1,185,000), reflecting a drop in swap rates since the execution date. Since September 9, 2003, the difference between the fixed rates and the underlying variable rates on the issues of approximately $294,000 was charged to operating income in 2003. The fixed rates are higher than the previous floating rates and continue to be as of the date of this filing. Although the fixed interest rates were higher than the underlying variable rates, a portion of a MPUC approved rate increase effective November 1, 2003, was to cover this difference. Management believes that the fixing of interest rates over the terms of MPS’s debt will serve to protect both shareholders and consumers from what it believes to be inevitable rising interest rates. The loss in fair value on the interest rate swaps noted above less the deferred tax of $473,000 has been recorded as Other Comprehensive Income (Loss), in accordance with SFAS 133, “Accounting for Derivative Instruments and Hedging Activities.” Gains or losses in the fair market value of the interest rate swaps do not impact net income or the revenues of MPS, unless shareholder’s common equity falls below the minimum allowable 48 percent as set by the MPUC.
On November 20, 2000, MPS purchased an interest cap of 6% that applied to the 2000 and 1996 Series of Maine Public Utilities Financing Bank’s (“MPUFB”) bonds issued on behalf of MPS with outstanding balances of $9 million and $13.6 million, respectively. The interest cap expired in November, 2003.
On June 1, 1998, MPS purchased an interest rate cap of 7% at a cost of $172,000, to expire June 8, 2008 on $11,540,000 of FAME’s Taxable Electric Rate Stabilization Notes, Series 1998A, issued on behalf of MPS. In accordance with the rate treatment prescribed by the MPUC, the original cost of the interest rate cap has been amortized along with other issuance costs with $96,000 and $79,000 remaining at the end of 2003 and 2002, respectively, as a regulatory asset. The provider of the cap estimated its value at the end of 2003 as approximately $27,000.
8. LONG-TERM DEBT
On October 19, 2000, the Maine Public Utilities Financing Bank (“MPUFB”) issued $9 million of its tax-exempt bonds due October 1, 2025 (“2000 Series”) on behalf of MPS. The proceeds were placed in trust to be drawn down for the reimbursement of issuance costs and for the construction of qualifying distribution property. As of December 31, 2002, the proceeds in the trust account were $2.1 million. On October 17, 2003, MPS received the final distribution from the trust. Pursuant to the long-term note issued under a loan agreement between MPS and the MPUFB, MPS has agreed to make payments to the MPUFB for the principal and interest on the bonds. Concurrently, pursuant to a letter of credit and reimbursement agreement, MPS caused a Direct Pay Letter of Credit for an initial term of nineteen months, subsequently extended until June, 2004, to be issued by The Bank of New York for the benefit of the holders of such bonds. MPS is currently seeking an extension of the Direct Pay Letter of Credit and management believes these efforts will be successful. To secure MPS’s obligations under the letter of credit and reimbursement agreement, MPS issued first and second mortgage bonds, in the amounts of $5.0 million and $4.525 million, respectively. MPS has the option of selecting weekly, monthly, annual or term interest rate periods for the 2000 Series, and, at issuance, selected the weekly interest period, with an initial interest rate of 4.35%. On November 20, 2000, MPS purchased an interest rate cap of 6% at a cost of $36,000 that expired in November 2003, that applied to the 2000 and 1996 Series, as described below. At the end of 2003, the cumulative effective interest rate of the 2000 Series, including the effective fixed swap rate of 4.68%, issuance costs and credit enhancement fees since issuance was 7.14%.
A similarly structured series of Bonds was issued on behalf of MPS by the MPUFB in 1996 (“1996 Series”), with $13.6 million outstanding due in 2021. A Direct Pay Letter of Credit was issued by The Bank of New York, which has been extended to June 2004, and is secured by $14.4 million of second mortgage bonds. At the end of 2003, the cumulative effective interest rate of the 1996 series, including the effective fixed swap rate of 4.57%, issuance costs and credit enhancement fees was 6.13%.
On May 29, 1998, FAME issued $11,540,000 of its Taxable Electric Rate Stabilization Revenue Notes, Series 1998A (MPS) (“Notes”) on behalf of MPS. The Notes were issued pursuant to, and are secured under, a Trust Indenture by and between FAME and Peoples Heritage Bank, Portland, Maine, as Trustee (“the Trustee”), for the purpose of: (i) financing the up-front payment to Wheelabrator-Sherman of approximately $8.7 million, as required under an amended purchase power agreement; (ii) for the Capital Reserve Fund, as required by
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FAME under their Electric Rate Stabilization Program; and (iii) for issuance costs. The Notes are limited obligations of FAME, payable solely out of the trust estate available under the Indenture, principally the Loan Note and Loan Agreement with MPS and the Capital Reserve Fund held by the Trustee, which was approximately $2.4 million at the end of 2003 and 2002. MPS has issued $4.0 million of its first mortgage bonds and $7.54 million of its second mortgage bonds as collateral for its performance under the Loan Note issue pursuant to the Loan Agreement. The Notes will bear interest at a Floating Interest Rate and will be adjusted weekly. On June 1, 1998, MPS purchased an interest rate cap of 7% at a cost of $172,000, to expire June, 2008, to limit its interest rate exposure to quarterly U.S. LIBOR rates. At the end of 2003, the cumulative effective interest rate, including the fixed swap rate of 2.79%, issuance costs and credit enhancement fees for the Notes was 3.81%.
The MPUFB tax-exempt issues are subject to the same restrictive covenants as those discussed for MPS’s revolving credit arrangement in Note 6, “Short-Term Credit Arrangements.”
9. STOCK COMPENSATION PLAN
Upon approval by MPS’s shareholders in June of 2002, MPS adopted the 2002 Stock Option Plan (the “Plan”). The Plan was subsequently adopted by the Company after its formation. The Plan provides designated employees of the Company and its Subsidiaries with stock ownership opportunities and additional incentives to contribute to the success of the Company, and to attract, reward and retain employees of outstanding ability. The Plan is administered by the members of the Performance and Compensation Committee of the Board of Directors, who are not employees of the Company or its Subsidiaries. The Company may grant options to its employees for up to 150,000 shares of common stock, provided that the maximum aggregate number of shares which may be issued under the plan pursuant to incentive stock options shall be 120,000 shares. The exercise price for shares to be issued under any incentive stock option shall not be less than one hundred percent (100%) of the fair market value of such shares on the date the option is granted. An option’s maximum term is 10 years. Prior to the issuance of options to the Company’s President and Chief Executive Officer, the Board, based on a recommendation of the Performance and Compensation Committee, modified the grant agreement to lessen the economic liability to the Company. As modified, the change of control provisions were eliminated and the three-year vesting schedule will be followed.
The Company accounts for the fair value of its grants under the plan in accordance with the expense provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation.” The effect of the grants on compensation expense for the year ended December 31, 2003 was immaterial.
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants: dividend yield of 4.34 percent; expected volatility of 20 percent, risk-free interest rate of 3.64%; and expected lives of 7 years.
A summary of the status of the Company’s stock option plan as of December 31, 2003, and changes during the year then ended is presented below:
The following table summarizes information about fixed stock options outstanding at December 31, 2003:
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10. BENEFIT PLANS
U. S. Defined Benefit Pension Plan
The Company has an insured non-contributory defined benefit pension plan covering substantially all employees. Benefits under the plan are based on employees’ years of service and compensation prior to retirement.
The Company’s policy has been to fund pension costs accrued. The Company made tax-deductible contributions of $409,000 for the 2003 plan year in December, 2003 and $276,570 for the 2002 plan year in January, 2003.
Health Care Benefits In addition to providing pension benefits, the Company provides certain health care benefits to eligible employees and retirees. All employees and retirees share in the cost of their medical benefits, in addition to plan deductibles and coinsurance payments, totaling approximately 12.2% and 11.26% of medical insurance premiums in 2003 and 2002, respectively. In 2002, certain amendments were made to the plan, including the following. Effective with retirements after January 1, 1995 and employees hired before January 1, 2003, retirees will be eligible for retiree medical coverage after completing twenty years of service, subject to a contribution schedule. Employees hired after January 1, 2003 will be eligible for retiree medical coverage after completing twenty-five years of service; however, their spouse will not be eligible for coverage. For employees hired after December 31, 1999 and prior to January 1, 2003, spousal retiree medical coverage ceases upon the spouse’s attainment of age 65. Retirees who were hired before January 1, 2003 will contribute to the cost of their coverage starting at 60% for retirees with twenty years of service with the contribution declining to $69.33 per month until age 65 and $21.62 per month thereafter for thirty or more years of service. Retirees who were hired after January 1, 2003 will contribute to the cost of their coverage starting at 70% for retirees with twenty-five years of service and declining to the above-mentioned monthly amounts for thirty or more years of service. The above amendments in plan provisions have been incorporated into the calculation of the related actuarial benefit obligation.
Based on prior MPUC accounting orders, the Company established a regulatory asset of approximately $1,061,000, representing deferred post-retirement benefits. As an element of its four-year rate plan, the Company began recovering these deferred expenses over a ten-year period, along with the annual expenses in excess of pay-as-you-go expenses, starting in 1996. The Company made a payment of $354,000 to fund the 401(h) sub-account of the Pension Trust for non-union retiree medical payments on September 14, 2000 and $92,190 on June 19, 2003. On December 28, 1999 and December 27, 2001, the Company made payments of $2.1 million and $641,000, respectively, to a Voluntary Employee Benefit Association (“VEBA”) trust fund, an independent external trust fund for union retiree medical payments. These payments provide funding for future post-retirement health care costs at such time as customers are paying for these costs in their rates. For purposes of determining the accrued post-retirement benefit cost as of December 31, 2003 the health care cost trend rate used was 8% in 2004 and graded down to 4% in 2013, remaining at that level thereafter. These rates have a significant effect on the amounts reported for the health care plan. A one-percentage-point change in the trend rates would have the following effects:
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The following table sets forth the plans’ change in benefit obligation, change in plan assets, funded status and assumptions as of December 31, 2003 and 2002:
The Company uses a December 31 measurement date for its pension and post-retirement benefit plans. The Company’s accumulated benefit obligation for all defined benefit pensions plans was $16.2 million and $15.4 million at December 31, 2003 and 2002, respectively.
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The investment objective is to achieve long-term growth of capital, with exposure to risk set at an appropriate level. This objective shall be accomplished through the utilization of a diversified asset mix consisting of equities (domestic and international) and taxable fixed income securities. The account is to be managed on a fully discretionary basis to obtain the highest total rate of return in keeping with a moderate level of risk. The target rate of return for the portfolio will be 8.5% with the goal of exceeding returns of the S&P 500 on the equity side and the Lehman Brothers Aggregate Bond Index on the fixed income side.
The following table sets forth the plans’ net periodic benefit cost for 2003, 2002 and 2001:
In November, 2002, a Voluntary Early Retirement Program (VERP) was offered to employees age 59 and over with 16 years of service. Of the 13 employees eligible for the program, 10 accepted the program and retired effective January 1, 2003. The impact of the VERP is included in “Additional FAS 88 Termination Benefit,” above.
On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”). The Act introduces a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.
In accordance with FASB Staff Position No. FAS 106-1, any measures of the accumulated pension benefit obligation (“APBO”) or net periodic post-retirement benefit cost in the Company’s financial statements or accompanying notes do not reflect the effects of the Act on its plan. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require a sponsor to change previously reported information. Moreover, the issues of how and when the federal subsidy should be accounted for are not yet resolved by the FASB. The Company has not yet determined the potential effects of the Act on its future post-retirement costs, including the participation rates in its benefit plans, nor whether any amendments to its benefit plans are appropriate given the provisions of the Act.
Retirement Savings Plan
The Company has adopted a defined contribution plan (under Section 401(k) of the Internal Revenue Code) covering substantially all of the Company’s employees. Participants may elect to defer from 1% to 15% of current compensation, and the Company contributes such amounts to the plan. The Company also matches contributions, with a maximum matching contribution of 2% of current compensation. Participants are 100% vested at all times in contributions made on their behalf. The Company’s matching contributions to the plan were approximately $112,000, $117,000 and $114,000 in 2003, 2002, and 2001, respectively.
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11. FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company’s financial instruments consist primarily of cash in banks, receivables, and debt. The carrying amounts for cash, receivables, and short-term debt approximate their fair value due to the short-term nature of these items. At December 31, 2003, the Company’s long term debt had a carrying value and a fair value of approximately $30.7 million.
12. COMMITMENTS, CONTINGENCIES AND REGULATORY MATTERS
MPUC Approves Elements of Rates Effective March 1, 2000
On October 14, 1998, and subsequently amended on February 9, 1999, August 11, 1999, and December 15, 1999, MPS filed its determination of stranded costs, transmission and distribution costs, and rate design with the MPUC. MPS’s amended testimony supported its $95.7 million estimate of stranded costs, net of available value from the sale of the generating assets, when deregulation occurred on March 1, 2000. The major components include the remaining investment in Seabrook, the above-market costs of the amended power purchase agreement and recovery of fuel expense deferrals related to WS, the obligation for remaining operating expenses and recovery of MPS’s remaining investment in Maine Yankee, and the recovery of several other regulatory assets.
On October 15, 1999, MPS filed with the MPUC a Stipulation resolving the revenue requirement and rate design issues for MPS’s transmission and distribution (“T&D”) utility. This Stipulation was signed by the Office of Public Advocate and approval was recommended by the MPUC Staff. Under the Stipulation, MPS’s total annual T&D revenue requirement of $16,640,000, went into effect on March 1, 2000. This revenue requirement includes a 10.7% return on equity with a capital structure based on 51% common equity. The Stipulation further provided that the precise level of stranded cost recovery could not be determined until final determination of all costs associated with the sale of MPS’s generating assets, but did set forth some general principles concerning MPS’s ultimate stranded costs recovery, including agreement that the major components of MPS’s stranded costs are legitimate, verifiable and unmitigable, and therefore subject to recovery in rates.
On January 27, 2000, the MPUC approved a Stipulation in Phase II of Docket No. 98-577 that provided for the recovery in rates of MPS’s stranded investment. The major element of the Phase II Stipulation was the $12.5 million of stranded investment recoverable annually beginning March 1, 2000, with that level of recovery set for two years. This revenue requirement includes a return on un-recovered stranded investment based on the capital structure approved by the MPUC in its December 1, 1999 Order. The approved capital structure consists of 51% common equity with an authorized return on equity of 10.7%. The Phase II Stipulation also allowed MPS to offset its un-recovered stranded investment in Seabrook by approximately $7 million, (details provided in chart in “Capacity Arrangements - Generating Asset Sale,” below) representing an amount equal to 35% of the available value from the sale of the generation assets. The parties to the Phase II Stipulation also resolved several rate design issues, principally the elimination of the inclining block rate for residential customers. In addition, MPS was granted several accounting orders incorporating certain accounting methodologies used in determining the elements of stranded costs. On August 4, 2000, the MPUC authorized MPS to record the difference between the approved contracts for two large industrial customers and their current special discount rates, designed for customer retention, as revenue and a regulatory asset. This flexible pricing adjustment resulted in recognition of $200,000 and $961,000 of revenues and a corresponding regulatory asset in 2002 and 2001, respectively. The annual revenue requirement associated with the recovery of stranded costs will be reviewed at least every three years, and was reviewed in late 2001 and late 2003. See “MPUC Approves Stranded Cost Revenue Requirements Effective March 1, 2002,” and “MPUC Approves Stranded Cost Revenue Requirements Effective March 1, 2004” below, for additional information.
MPUC Approves Stranded Cost Revenue Requirements Effective March 1, 2002
On May 8, 2001, the MPUC issued a notice of investigation to determine whether MPS’s annual recovery of $12.5 million in stranded investment must be changed, effective March 1, 2002, to reflect any changes in its stranded costs. On July 12, 2001, MPS filed its proposal in which it advocated continuing the $12.5 million annual recovery of stranded costs and also proposed to begin the recovery of deferred amounts associated with the discounted rates it had made available to certain industrial customers. Also at issue in the proceeding was an insurance refund associated with Maine Yankee, of which MPS’s share is $1,005,000. As of December 31, 2001, MPS reflected the refund as a miscellaneous deferred credit. In February, 2002, $854,000 of the refund was applied to stranded costs and $151,000 of the refund was applied to other non-operating revenue. A Stipulation placed before the MPUC in January, 2002 included annual stranded cost recovery of $11,540,000 and a 15% sharing of the Maine Yankee insurance refund with MPS’s shareholders, thereby leaving the rates charged to retail customers the same. This Stipulation was approved by the MPUC on January 7, 2002, and the appropriate order was issued on February 27, 2002.
MPUC Approves Stranded Cost Revenue Requirements Effective March 1, 2004
In an Order dated February 27, 2004, MPS received final approval from the MPUC for the stranded cost revenue component of its electric delivery rates, effective March 1, 2004. Under Title 35-A of the Maine Revised Statutes Annotated, Section 3208, the MPUC is required to periodically investigate and adjust the stranded cost charges reflected in the rates of a transmission and distribution utility. In accordance with this provision, on September 16, 2003, in Docket No. 2003-666, the MPUC issued a notice of investigation in order to determine whether MPS’s rates must be changed effective March 1, 2004 to reflect any changes in MPS’s stranded costs. On February 27, 2004, the MPUC issued an order approving a stipulation under which MPS is allowed to recover $11,785,339 per year to satisfy its approved stranded cost revenue requirements for the “rate effective period” beginning March 1, 2004 and ending on December 31, 2006. The approved revenue requirement for the rate effective period ended February 29, 2004 was $11,540,000. Under the approved stipulation MPS’s stranded
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cost rates approved in Docket No. 2003-85 will remain in effect during the rate effective period. The stipulation approved by the MPUC in Docket 2003-666 also approved and reaffirmed each of the elements and associated balances of MPS’s recoverable stranded costs.
As explained more fully below, during the course of Docket 2003-666 the parties reviewed the manner in which MPS was recovering and accounting for its carrying charges associated with the deferred fuel element of its stranded cost. As a result of the stipulation approved in Docket No. 2003-666, MPS will record deferred income tax expense associated with deferred fuel carrying charges during the rate effective period from March 1, 2004 through December 31, 2006, as compared to past treatment where such expense was deferred for future recovery. Because the deferred fuel carrying charge component of MPS’s stranded costs is not expected to fully amortize until 2012, the Company anticipates that deferred income tax expense will be incurred through 2012, subject to future stranded cost filings with the MPUC. In Dockets 98-577 and 2001-240, the parties stipulated that MPS would accrue carrying costs on its unrecovered fuel balance (the “deferred fuel account”) during the respective rate effective period at its net of tax cost of capital rate. Consistent with the stipulation in Docket No. 2001-240, MPS accrued a carrying charge using the net of tax rate of 7.98% through October 31, 2003 applied against its unrecovered deferred fuel balance. From November 1, 2003 to December 31, 2003 MPS accrued its carrying charge using a net of tax rate of 7.06%, based on the cost of capital approved in Docket No. 2003-85 (described in Docket 2003-85 Partial Stipulation filed on September 2, 2003).
During the course of the Docket 2003-666 proceeding, MPS determined that it had not previously recognized accumulated deferred income taxes with respect to the carrying charges on the deferred fuel account and that the recording of a deferred tax liability to its balance sheet pursuant to FAS 109 in the amount of $2.896 million was required, of this, $2.739 million was recorded as of December 31, 2003. The deferred fuel balance as of March 1, 2004 prior to any adjustment is projected to be $18,838,000. Under the stipulation MPS is allowed to adjust its accumulated deferred income tax account and the deferred fuel balance by $2,896,000, as of March 1, 2004, resulting in a total projected deferred balance as of March 1, 2004 of $21,734,000. Under the approved stipulation the parties also agreed that the return component on the deferred fuel balance should be reduced in such a manner that ratepayers were held harmless on a net present value basis as a result of the March 1, 2004 adjustment to the deferred fuel balance. During the rate effective period ending on December 31, 2006, the overall pre-tax return component on the deferred fuel balance will be 8.28%, reflecting a 6.17% return on equity. The return on the deferred fuel balance will be reviewed in future stranded cost rate setting proceedings and will be adjusted as necessary in order that the present value of the revenue requirements of the deferred fuel account without the adjustments described above equals the present value of the revenue requirements of the deferred fuel account with the adjustments. MPS concludes that as a result of this stipulation and the foregoing described adjustment to the deferred fuel balance and the accumulated deferred income tax liability that no further adjustment is necessary under FAS 109 in order to reflect prior unrecorded deferred income taxes.
The decreased cost of capital rate beginning on March 1, 2004 will have an impact on future stranded cost earnings and cash flow, but will not impact future distribution or transmission earnings. In the year 2004, the Company anticipates that it will record deferred income tax expense of approximately $412,000 associated with the deferred fuel carrying charges. The amount of deferred income tax expense recorded in future years will vary depending upon the amount of the accrued carrying charge in any year, and the tax rates then in effect. The Company anticipates that earnings from carrying charges on its stranded costs in 2004 will be approximately $267,000 lower than the amount that would have been recorded had the Company continued to use the original cost of capital on its deferred fuel balance, for a total earnings impact of $679,000 in 2004. The impact on future earnings resulting from the agreed upon lower cost of capital, when compared against the cost of capital used in prior stranded cost filings, will vary. Schedules filed by the Company as part of the stipulation in Docket No. 2003-666 reflect the deferred fuel balance as of March 1, 2003, certain additions to relating to the Wheelabrator-Sherman above-market contract through December, 2006 and the amortization of the deferred fuel balance though 2012. Applying these assumptions, current tax rates and the agreed upon cost of capital, the Company anticipates that the impact on future earnings resulting from recording deferred income taxes on accrued carrying charges and applying a lower cost of capital to the deferred fuel balance could range from $1.0 million in 2005, increasing to $1.2 million in 2007, then gradually decreasing to $17,000 in 2012. These amounts may vary with changes in the deferred fuel balance and other variables which the Company cannot predict with certainty at this time. Management is analyzing means to mitigate the impact of this stipulation on future net income and cash flows.
In addition to the return allowed on its deferred fuel account as set forth above, under the approved stipulation MPS shall be allowed to recover the following pre-tax returns on the applicable stranded cost rate base components during the rate effective period: (i) the pre-tax return on unrecovered balance of the Wheelabrator-Sherman Contract Buydown shall be 2.79% plus its FAME issuance costs; (ii) the pre-tax return on the unrecovered Seabrook Investment and approved special rate contract costs shall be 11.74%; and, (iii) the pre-tax return on the Maine Yankee decommissioning related costs shall be 8.56%.
MPUC Request for Approval of Alternative Rate Plan
On March 6, 2003, MPS submitted its formal “Request for Approval of Alternate Rate Plan” (“ARP”) (MPUC Docket 2003-85). The proposal was a seven-year rate plan for its distribution delivery services and had a target implementation date on or before July 1, 2003. The ARP is an alternative form of regulating MPS’s distribution assets, similar to the performance rate plans the MPUC has adopted for Central Maine Power Company and Bangor Hydro-Electric Company. In accordance with a recently enacted state statute, Maine utilities requesting an ARP must now also file cost of service financial information as part of the ARP proceeding. In connection with this aspect of the ARP review and analysis, MPS has been authorized by, and has received final approval from the MPUC to increase its electric delivery rates. Following the entry of a procedural order, discovery, and a public conference, by an Order dated October 29, 2003, the MPUC approved a final Supplemental Stipulation in connection with this rate increase. As a result, effective November 1, 2003, MPS increased its total electric delivery rate by 3.78%, or a total revenue increase not to exceed $1,126,552. This increase includes $685,037 in distribution revenues and $441,515 in transmission revenues. Following the entry of the order approving the Supplemental Stipulation, the ARP proceeding was
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bifurcated and MPS had until December 31, 2003 to notify the MPUC of its intention to proceed with the remaining elements of the ARP or withdraw the ARP docket. On December 29, 2003, MPS withdrew its request for approval for its ARP from the proceedings.
FERC Approves Increase in Retail Transmission Rates
The FERC approved wholesale transmission rates effective June 1, 2002, in FERC Docket No. ER00-1053, a proceeding related to MPS’s Open Access Transmission Tariff (“OATT”). On August 6, 2002, MPS notified the MPUC of its intention to implement the associated transmission component of its retail T&D rates, with the new rates effective October 1, 2002. The FERC maintains jurisdiction over all transmission rates. This implementation increased overall delivery rates by approximately 2%. MPS increased its transmission rates subject to refund and issuance of a final order by FERC, which was issued in March, 2003.
FERC Open Access Transmission Tariff (“OATT”) Filing
Pursuant to Section 2.4 of the Settlement Agreement filed on September 30, 2000, in Docket No. ER00-1053-000, and accepted by the FERC on September 15, 2000, MPS provided parties and FERC staff on June 10, 2003, the OATT Formula Rate charges that MPS proposed to apply on June 1, 2003, together with back-up materials. On June 1, 2003, the Formula Rate charges became effective subject to a refund that may occur in connection with a settlement stipulation negotiated by the parties to the proceeding. In general, MPS is seeking a slight modification to its rate formula under its transmission tariff, including, among others, changes in certain depreciation rates for transmission property, and allocations of certain operating expenses and revenues. The return on common equity used in determining the rate of return on transmission rate base will remain at 11%. An Order approving the 2003 informational filings and OATT revisions is expected during the first quarter of 2004. MPS is currently engaged in discussions with the parties and FERC staff to resolve all outstanding issues in the filing with the objective of reaching a settlement agreement. In February 2004, the parties executed a settlement which was filed with the FERC on February 11, 2004.
Seabrook Nuclear Power Project
In 1986, MPS sold its 1.46% ownership interest in the Seabrook Nuclear Power Project with a cost of approximately $92.1 million for $21.4 million. Both the MPUC and the FERC allowed recovery of MPS’s remaining investment in Seabrook Units 1 and 2, adjusted by disallowed costs and sale proceeds, with the costs being amortized over thirty years.
Recoverable Seabrook costs at December 31, 2003 and 2002 are as follows:
In March 2000, MPS was allowed to offset $7.0 million of the recoverable Seabrook costs with the available value from its deferred asset sale gain, as detailed in “Capacity Arrangements-Generating Asset Sale,” below. The decrease in recoverable Seabrook costs represents monthly amortization, recorded as amortization expense in January and February, 2000, and then as stranded costs applied to the deferred asset sale gain beginning in March, 2000, as described in “MPUC Approves Elements of Rates Effective March 1, 2000,” above.
Nuclear Insurance
In 1988, Congress extended the Price-Anderson Act for fifteen years and increased the maximum liability for a nuclear-related accident. In the event of a nuclear accident, coverage for the higher liability now provided for by commercial insurance coverage will be provided by a retrospective premium of up to $88.1 million for each reactor owned, with a maximum assessment of $10 million per reactor for any year. Maine Yankee is not liable for “events” or “accidents” occurring after January 7, 1999, when exemption was received from the Nuclear Regulatory Commission. These limits are also subject to inflation indexing at five-year intervals as well as an additional 5% surcharge, should total claims exceed funds available to pay such claims. Based on MPS’s 5% equity ownership in Maine Yankee (see Note 5, “Investments in Associated Companies”), MPS’s share of any retrospective premium would not exceed approximately $2.9 million or $.5 million annually, without considering inflation indexing.
Generating Asset Sale
On July 7, 1998, MPS and WPS Power Development, Inc., (“WPS-PDI”) signed a purchase and sale agreement for MPS’s electric generating assets. WPS-PDI agreed to purchase 91.8 megawatts of generating capacity for $37.4 million, which was 3.2 times higher than the net book value of the assets. The gain from the asset sale reduced stranded cost revenue requirements, as discussed in “MPUC Approves Elements of Rates Effective March 1, 2000,” above.
On June 8, 1999, after receiving all of the major regulatory approvals, MPS completed the sale to WPS-PDI for $37.4 million. MPS’s 5% ownership in Maine Yankee was not part of the sale, since the plant is being decommissioned. After paying Canadian, Federal and State
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income taxes, the remaining proceeds, along with interest in the trust account, were used to reduce MPS’s debt. The gain from the sale was deferred, and recognized according to the MPUC’s decision on MPS’s determination of stranded costs, transmission and distribution costs, and rate design. The components of the deferred gain were as follows:
* Gross proceeds were increased by $1.05 million before tax in September 2001 due to an MPUC approved settlement between CMP and other former owners of Wyman Unit No. 4, including MPS. The proceeds increased the deferred gain and further reduced stranded costs.
With the sale of MPS’s generating assets in June, 1999, MPS purchased energy from the new owners under an agreement that expired February 29, 2000, and these purchases are classified as purchased energy.
As part of the generating asset sale on June 8, 1999, MPS has entered into two indemnity obligations with the purchaser, WPS-PDI. First, MPS will be liable, with certain limitations, for certain Aroostook River flowage damage. This liability will continue for ten years after the sale and shall not exceed $2,000,000 in the aggregate. Second, MPS has warranteed the condition of the sites sold to WPS-PDI, with an aggregate limit of $3,000,000 for two years after the date of sale, and five years after the sale for environmental claims. The Company is unaware of any pending claims under either of these indemnity obligations.
Maine Yankee
MPS owns 5% of the common stock of Maine Yankee, which operated an 860 MW nuclear power plant (the “Plant”) in Wiscasset, Maine. On August 6, 1997, the Board of Directors of Maine Yankee voted to permanently cease power operations and to begin decommissioning the Plant.
On September 1, 1997, Maine Yankee estimated the sum of the future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee to be approximately $930 million, of which MPS’s 5% share would be approximately $46.5 million. On nine different occasions dating back to December 1998, Maine Yankee has updated its estimate of decommissioning costs based on the Settlement. Legislation enacted in Maine in 1997 called for restructuring the electric utility industry and provided for recovery of decommissioning costs, to the extent allowed by federal regulation, through the rates charged by the transmission and distribution companies. Based on the Maine legislation and regulation precedent established by the FERC in its opinion relating to the decommissioning of the Yankee Atomic nuclear plant, MPS believes that it is entitled to recover substantially all of its share of such costs from its customers and, as of December 31, 2003, is carrying on its consolidated balance sheet a regulatory asset and a corresponding liability in the amount of $17.8 million, which reflects MPS’s 5% share of Maine Yankee’s September 2003 revised estimate of the remaining decommissioning costs, less actual decommissioning payments made since then, and discounted by a risk-free interest rate.
The MPUC, on January 27, 2002, approved a Stipulation providing for the recovery of stranded investment, for a two-year period from March 1, 2002 until February 29, 2004, which includes MPS’s share of Maine Yankee decommissioning expenses, Maine Yankee replacement power costs, and the remaining Maine Yankee investment.
As of December 31, 2003, deferred fuel of $20.5 million is reflected as a regulatory asset, which includes the Maine Yankee replacement power costs, as well as deferred Wheelabrator-Sherman fuel costs.
In accordance with its 1999 FERC rate case settlement, on October 21, 2003, Maine Yankee filed a revised formula rate schedule with the FERC, proposing an effective date of January 1, 2004. The filing contained a revised decommissioning cost estimate and collection schedule to assure that adequate funds are available to safely and promptly decommission the Plant and operate and manage the independent spent fuel storage installation (“ISFSI”). In the filing, Maine Yankee also requested a change in its billing formula and an increase in the level of collection for certain post-retirement benefits. To meet these needs, Maine Yankee proposed to collect an additional $3.77 million per year over current decommissioning collection levels through October 2008, exclusive of any income-tax liability, for the decommissioning and spent-fuel management expense, and to collect from November 2008 through October 2010, the amounts needed to replenish its Spent Fuel Trust for funds previously used for ISFSI construction. On December 19, 2003, the FERC issued an order accepting the new rates effective January 1, 2004, subject to refund pending a hearing. Maine Yankee believes it is entitled to recover the costs underlying the proposed new rates, but cannot predict the outcome of the rate proceeding.
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As previously reported, in May 2000, Maine Yankee terminated its decommissioning operations contract with Stone & Webster Engineering Corp. (“Stone & Webster”) pursuant to the terms of the contract. Stone & Webster disputed Maine Yankee’s grounds for the termination. In June 2000, Stone & Webster filed a voluntary petition under Chapter 11 of the United States Bankruptcy Code with the United States Bankruptcy Court for the District of Delaware. Since the contract termination, Maine Yankee has managed the decommissioning project itself.
In December 2001, Maine Yankee and Federal Insurance Company (“Federal”) entered into a settlement agreement resolving litigation between the parties, pursuant to which Federal paid Maine Yankee $44 million. That amount represented full payment under the performance bond provided by Federal, plus an additional amount under its payment bond reflecting certain payments previously made by Maine Yankee to subcontractors and suppliers who had not been fully paid by Stone & Webster. Maine Yankee deposited the payment in its decommissioning trust fund to offset past and future expenses resulting from the failures of Stone & Webster.
In addition, Maine Yankee continued to pursue its claim for damages that was originally filed against Stone & Webster and its then parent corporations in August 2000, in the Bankruptcy Court in Delaware. After recognizing the payment from Federal, Maine Yankee asserted a right to recover an additional $21 million in that court from the bankruptcy estates. After extensive interim proceedings and negotiations, in the third quarter of 2003, the major parties agreed to a joint plan of reorganization under which Maine Yankee would have an allowed claim of $20.3 million against the principal bankrupt estate, subject to certain contingencies. Under the plan, Maine Yankee would also have a first lien on any distributions from a related bankrupt estate in the proceeding on any amount needed to increase its actual cash recovery to $18.5 million. On January 13, 2004, Maine Yankee received an initial distribution of $8.4 million, which it deposited in its decommissioning trust fund. The amount of cash that Maine Yankee will actually recover on the balance of its claim remains contingent on a number of factors beyond Maine Yankee’s control that affect the amount of bankrupt estate assets ultimately available to pay the claim. Maine Yankee has settled its litigation claims against Stone & Webster’s bankruptcy estate and Envirocare in connection with Stone & Webster’s bankruptcy proceeding.
Federal legislation enacted in 1987 directed the Department of Energy (“DOE”) to proceed with the studies necessary to develop and operate a permanent high-level waste (spent fuel) repository at Yucca Mountain, Nevada. The project has encountered delays, and the DOE has indicated that the permanent disposal site is not expected to open before 2010, although originally scheduled to open in 1998.
In accordance with the process set forth in the legislation, in February 2002, the Secretary of Energy recommended the Yucca Mountain site to the President for the development of a nuclear waste repository, and the President then recommended development of the site to Congress. As provided in the statutory procedure, the state of Nevada formally objected to the site in April 2002, and in July 2002, Congress overrode the objection. Construction of the repository requires the approval of the Nuclear Regulatory Commission (“NRC”), upon application of the DOE, and after a public adjudicatory hearing, as well as a second NRC approval after completion of construction to operate the facility. Maine Yankee cannot predict the timing or results of those proceedings.
In November 1997, the U.S. Court of Appeals for the District of Columbia Circuit confirmed the obligation of the DOE under the Nuclear Waste Policy Act of 1982 to take responsibility for spent nuclear fuel from commercial reactors in January 1998. After an unsuccessful effort by Maine Yankee in the same court to compel the DOE to take Maine Yankee’s spent fuel, in June 1998, Maine Yankee filed a claim for money damages in the U.S. Court of Federal Claims for the costs associated with the DOE’s default. In November 1998, the Court granted summary judgment in favor of Maine Yankee, ruling the DOE had violated its contractual obligations, but leaving the amount of damages incurred by Maine Yankee for later determination by the Court. Since then the parties have been engaged in extensive discovery and resolution of pre-trial issues in the damages phase of the proceeding. On June 26, 2003, the Court denied three motions for summary judgment filed by the DOE and indicated in its order that final pretrial submissions were to be due at the end of September 2003, with a trial to follow shortly thereafter. However, at the end of September, the DOE requested an extension of time to complete its discovery, which was later granted, extending the discovery period to February 12, 2004. Maine Yankee is pursuing its claim for determination of damages vigorously, but cannot predict the outcome or timing of the determination.
At the same time, as an interim measure until the DOE meets its contractual obligation to dispose of Maine Yankee’s spent fuel at Yucca Mountain or elsewhere, Maine Yankee constructed an ISFSI, utilizing dry-cask storage, on the Plant site and has completed the process of transferring the spent fuel from the spent-fuel pool to the individual casks and the casks to the ISFSI. Maine Yankee’s total cost of maintaining the ISFSI will be substantially affected by heightened security costs and by the length of time it is required to operate the ISFSI before the DOE honors its contractual obligation to take the fuel from the site. Maine Yankee’s current decommissioning costs estimate is based on an assumption that its operation of the ISFSI will end in 2023, but the actual period of operation and cost may vary.
On January 15, 2003, Maine Yankee notified NAC International (“NAC”), the contractor responsible for providing for the fabrication of the spent-fuel casks and transferring the fuel to the casks and the casks to the ISFSI, that Maine Yankee was terminating its contract with NAC pursuant to the terms of the contract. NAC had been experiencing financial difficulties and had requested relief from the terms of the contract. Maine Yankee believes that NAC had also failed to perform its contractual obligations in accordance with the terms of the contract and provide adequate assurance of its ability to do so in the future. NAC disputed Maine Yankee’s basis for terminating the contract and served Maine Yankee with a demand to arbitrate the dispute and a request for damages. Maine Yankee, in turn, filed suit in the U.S. District Court for the District of Maine against NAC, its bonding company, and its parent guarantor, wherein Maine Yankee sought, among other things, damages due to NAC’s failure to perform. Maine Yankee also entered into contracts with the major subcontractors and resumed the transfer of fuel to the ISFSI under its own management.
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In April 2003, after extensive negotiations, the parties entered into a comprehensive settlement agreement resolving all the disputed issues and providing for Maine Yankee to replace NAC in managing the completion of the fuel-transfer work. The settlement included a payment for $10.4 million to Maine Yankee to compensate Maine Yankee for higher costs incurred or to be incurred as a result of NAC’s failure to perform its contractual obligations. The payment was reflected in Maine Yankee’s second quarter 2003 results. Although the NAC dispute contributed to a slowdown in the progress of the fuel transfer work in the first quarter of 2003, since then Maine Yankee has implemented additional efficiencies and the pace of work has improved to a point where it has been consistently exceeding the pre-2003 pace. The transfer of spent fuel to the ISFSI was completed in the first quarter of 2004.
The Federal Low-Level Radioactive Waste Policy Amendments Act, enacted in 1986, required states, either alone or in multi-state compacts, to provide for the disposal of low-level radioactive waste generated within their borders. The States of Maine, Texas and Vermont entered into a compact for the disposal of low-level waste over a 30 year period at a then-planned facility in west Texas.
The terms of the compact provided that the state of Maine would contribute $25 million, payable (1) in two equal installments, the first after ratification by Congress and the second upon commencement of operation of the Texas facility, or (2) alternatively, if agreed by the three states, in accordance with the schedule for repayment of bonds issued for the development or operation of the facility. By statute, those costs were to be initially assessed against Maine Yankee, as the operator of a nuclear power plant in Maine. As required by the 1986 Act, the United States Congress ratified the compact in September 1998. However, in October 1998, the Texas Natural Resource Conservation Commission denied a permit for the proposed west Texas site, and efforts to site such a facility in Texas were suspended. Maine Yankee is shipping its low-level waste to other facilities licensed to accept such material.
At its 2002 session, the Maine legislature enacted legislation providing for the withdrawal of the state of Maine from the Texas compact pursuant to the terms of the compact. The legislation cited the 1997 closure of the Maine Yankee plant and the inability of the state of Texas to cause a disposal facility to be built in a timely manner under the compact as the reasons for initiating the withdrawal process. However, in its 2003 session, the Texas legislature enacted a bill that reactivated the process of siting a disposal facility in Texas and provides for Texas to seek payment from Maine of $12.5 million under the compact. By letter dated September 10, 2003, the Attorney General of Texas requested payment of $12.5 million from the state of Maine, to which the state of Maine responded by denying liability. Maine Yankee believes that withdrawal from the compact by the state of Maine is legally justified, but cannot predict the results of the Texas legislation on the state of Maine or Maine Yankee or of any attempt by any party to challenge the state of Maine’s withdrawal from the compact or to assess Maine Yankee for any payments under the compact.
On February 28, 2003, the Nuclear Regulatory Commission approved Maine Yankee’s License Termination Plan (“LTP”). The LTP was approved without any unexpected conditions. In accordance with the plan accepted by the SEC, Maine Yankee has started the redemption of its common stock periodically through 2008.
MEPCO
MPS also owns 7.49% of the common stock of Maine Electric Power Company, Inc., (“MEPCO”). MEPCO owns and operates a 345-KV (“kilovolt”) transmission line about 180 miles long which connects the NB Power system with the New England Power Pool.
Wheelabrator-Sherman
MPS was ordered into a Power Purchase Agreement (“PPA”) with Wheelabrator-Sherman (“WS”) in 1986, which required the purchase of the entire output (up to 126,582 MWH per year) of a 17.6 MW biomass plant through December 31, 2000. The PPA was subsequently amended in 1997, with WS agreeing to price reductions of $10 million through the end of the original term in exchange for an up-front payment of $8.7 million in May, 1998. The MPUC’s December, 1997 approval of the amended PPA included a determination that the up-front payment would be treated as stranded cost and, therefore, recovered in rates of the transmission and distribution company, as discussed in “MPUC Approves Elements of Rates Effective March 1, 2000,” above. Total stranded cost included as a regulatory asset under the caption “deferred fuel and purchased energy cost” in the accompanying balance sheet related to this contract is $20.5 million and $13.1 million at December 31, 2003 and 2002, respectively.
MPS and WS also agreed to renew the PPA for an additional six years at agreed-upon prices and an increase of output to 136,982 MW beginning in 2001. Energy supply purchases under this contract through February 29, 2000 were $2.6 million. As described in “MPUC Approves Elements of Rates Effective March 1, 2000,” above, purchases from WS after March 1, 2000 are reflected as stranded costs.
MPS estimates its remaining commitment to purchase power under this contract to be $35.7 million from January 1, 2004 through 2006. MPS has entered a contract whereby WPS-PDI takes delivery of the power through February 28, 2002 at market prices, and beginning March 1, 2002 through February 29, 2004, Energy Atlantic, the Company’s wholly-owned marketing subsidiary, will be taking delivery of 40% of WS’s output and WPS-PDI will take the remainder. MPS estimates that the remaining stranded costs will be $21.6 million through 2006, assuming arrangements similar to the one with WPS-PDI and EA will be in place for that period.
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Construction Program
Expenditures on additions, replacements and equipment for the years ended December 31, 2003, 2002 and 2001, along with 2004 estimated expenditures, and are as follows:
Off-Balance Sheet Arrangements
The Company does not have any variable interest entities as defined by Financial Accounting Standards Board Interpretation No. 46, “Consolidation of Variable Interest Entities,” (“FIN 46”) promulgated on January 17, 2003 and discussed in the Company’s reports on Form 10-Q for the quarters ended June 30, 2003 and September 30, 2003. Except for operating leases used for office and field equipment, vehicles and computer hardware and software, accounted for in accordance with Financial Accounting Standards No. 13, “Accounting for Leases,” (“FAS 13”) the Company has no other form of off-balance sheet arrangements. The following summarizes payments for leases for a period in excess of one year for the years ended December 31, 2003 and 2002:
The future minimum lease payments for the items listed above for the next five years are as follows:
Future Minimum Lease Payments By Year For All Items
13. GUARANTOR ARRANGEMENTS
In November 2002, the FASB issued FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34,” (“FIN 45”). FIN 45 requires that a guarantor recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken by issuing the guarantee. FIN 45 also requires additional disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees it has issued. The accounting requirements for the initial recognition of guarantees are applicable on a prospective basis for guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for all guarantees outstanding, regardless of when they were issued or modified for financial statements for interim or annual periods ending after December 15, 2002. The adoption of the recognition provisions of FIN 45 are not expected to have a material effect on the Company’s consolidated financial statements. The following is a summary of our agreements that management has determined are within the scope of FIN 45.
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As permitted under Maine law, we have agreements whereby we indemnify our officers and directors for certain events or occurrences while the officer or director is, or was serving, at our request in such capacity. The term of the indemnification period is for the officer’s or director’s lifetime. The maximum potential amount of future payments we could be required to make under these indemnification agreements is unlimited; however, we have a Director and Officer insurance policy that limits our exposure and enables us to recover a portion of any future amounts paid. As a result of our insurance policy coverage, we believe the estimated fair value of these indemnification agreements is minimal. All of these indemnification agreements were grandfathered under the provisions of FIN 45 as they were in effect prior to December 31, 2002. Accordingly, we have no liabilities recorded for these agreements as of December 31, 2003.
14. ACQUISITIONS
On December 1, 2003, the Company’s Canadian subsidiary, Maricor acquired all of the outstanding common shares of Eastcan Consultants, Inc., a closely held Canadian corporation. The results of Eastcan’s operations have been included in the consolidated financial statements since that date. Eastcan is a mechanical and electrical engineering service firm headquartered in Moncton, NB, Canada. The acquisition is the Company’s first step towards achieving its stated strategy of gaining entry to the engineering services sector in the Maritime provinces of Canada. The Company expects to increase Eastcan’s revenues by increasing marketing and business development more than Eastcan would have been able to do by itself.
The aggregate purchase price was $718,000, consisting of 5,529 shares of MAM common stock valued at $194,000, $397,000 of cash, $5,000 in unrealized foreign exchange gain from the date of stock valuation to the closing date, and $122,000 in external costs for the acquisition. The value of the 5,529 common shares issued was determined based on the average market price of the Company’s common shares over the 10-day period ending five day before the acquisition and was $35.01 per share.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition. The Company valued the intangible assets as of the date of acquisition and no further refinement is expected.
At December 1, 2003
($000s)
Of the $138,000 of acquired intangible assets, the Company assigned $30,000 to the expected profits in the firm contract backlog which is subject to amortization as the contracts are completed, and should be fully amortized during 2004. The Company assigned $108,000 to the value of the client list and relationships established by Eastcan. The client list amortization is over a three-year life.
The Company assigned the entire goodwill of $415,000 to the unregulated segment. The goodwill is not deductible for tax purposes under Canadian tax rules.
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15. QUARTERLY INFORMATION (unaudited)
Quarterly financial data for the two years ended December 31, 2003, reflecting the beginning of MAM activity in the third quarter and MAMES in the fourth quarter, are as follows:
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Item 16. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(2) Financial Statement Schedules
Included in Part IV of this report:
Schedule II - Valuation of Qualifying Accounts and Reserves
Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto.
(3) Exhibits
Exhibits for Maine Public Service Company are listed in the Index to Exhibits, pages 88 to 94.
Certification of Financial Reports dated March 29, 2004, for the Form 10-K for the year ended December 31, 2003.
(b) The following Forms 8-K were filed for MPS:
• January 23, 2003 - Reporting the election of David N. Felch as a Director, described under Item 5, Other Events.
• February 14, 2003 - Press release dated February 14, 2003 reporting the Company’s financial results for the fourth quarter of 2002 and for the year 2002, under Item 7, Financial Statements and Exhibits.
• February 28, 2003, - Reporting the filing of a new alternative rate plan and performance based rate structure and Energy Atlantic’s focus on Southern Maine markets and the cessation of marketing in northern Maine, under Item 5, Other Events.
• June 2, 2003 - Reporting on the votes at the Annual Meeting of Stockholders held on May 30, 2003, approving the reorganization into a holding company and the election of four directors, as described in Part II, Item 4