Item 1. Business
General
The Company was originally incorporated as the Gould Electric Company in April, 1917 by a special act of the Maine legislature. Its name was changed to Maine Public Service Company in August, 1929. Until 1947, when its capital stock was sold to the public, it was a subsidiary of Consolidated Electric & Gas Company. Maine and New Brunswick Electrical Power Company, Limited, the Company’s wholly-owned Canadian subsidiary (the “Canadian Subsidiary” or “Me&NB”) was incorporated in 1903 under the laws of the Province of New Brunswick, Canada. Energy Atlantic, LLC (EA), the Company’s unregulated marketing subsidiary, formally began operations in January, 1999.
The Company, until the generating assets were sold on June 8, 1999, produced and, until March 1, 2000, purchased electric energy for retail and wholesale customers. The Company continues to provide transmission services to former wholesale energy customers and transmission and distribution services to retail customers in the service territory. Geographically, the service territory is approximately 120 miles long and 30 miles wide, with a population of approximately 72,000. Since March 1, 2000, the beginning of retail competition in Maine, customers in the Company’s service territory have been purchasing energy from suppliers other than the Company. This energy comes from competitive electricity providers or, if customers are unable or do not wish to choose a competitive supplier, the Standard Offer Service (SOS) provider.
The Company’s service area features agricultural and wood product customers. Potato growing and processing, as well as the manufacturing of wood products, principally lumber, continue to be the dominant economic forces in the service area. The growing and processing of broccoli has added diversity to the region’s agricultural portfolio. However, the Northern Maine area continues to lag behind National economic trends and is experiencing population losses based on census data and recent projections. Attracting new businesses to Northern Maine and reversing the migration of population from the Company’s service territory is a continuing challenge to the area’s leaders and businesses, including the Company.
The Canadian Subsidiary was primarily a hydro-electric generating company. It owned and operated the Tinker hydro plant in New Brunswick, Canada, until June 8, 1999, when these assets were sold to WPS-PDI. Prior to the generating asset sale, the Canadian Subsidiary sold energy not needed to supply its wholesale New Brunswick customer to the Company. For the period 2000-2002, the Canadian Subsidiary has been inactive and did not have unaffiliated customer revenues.
EA participated in the wholesale power market during 1999 and until March 1, 2000, when it began selling energy in the retail electricity market in Maine. The retail market consists of two pieces, SOS and competitive energy supply (CES), as mentioned above. The Maine Public Utilities Commission (MPUC) requests bids for SOS in each service territory. As a result of this bidding process, EA was the Standard Offer Service (SOS) provider in Central Maine Power Company’s (CMP’s) territory from March 1, 2000 until its contract expired on February 28, 2002. In the Company’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 competitive energy supply (CES) contracts, which expired throughout 2001. EA, along with its energy supplier, was not successful in obtaining any of the SOS in the Company’s service territory starting March 1, 2001 nor CMP’s service territory starting March 1, 2002. 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 reached in May 2001, EA was allowed to purchase energy from sources in addition to Engage. EA has secured several sources of power, enabling it to participate in competitive markets within Maine. EA’s CES sales to retail customers during 2002 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 in that market resulting from an illiquid wholesale market, inability to obtain price differentiated wholesale electric products, and other factors. EA will continue to serve existing contracts in Northern Maine until they expire through February 28, 2004. 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,” incorporated herein by reference.
By regulatory order, on June 4, 1984, the Company entered into a Power Purchase Agreement (PPA) with Sherman Power Company, which assigned its interest in the Agreement to Wheelabrator-Sherman Energy Company (W-S), formerly Signal-Sherman Energy Company, (a cogenerator), for 17.6 MW of capacity which began July, 1986. The original 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. The Company and W-S agreed to amend the PPA with the amendment approved by the MPUC in December, 1997. Under the terms of this amendment, W-S agreed to reductions in the price of purchased power of approximately $10 million over the PPA’s current term. The Company and W-S also agreed to renew the PPA for an additional six years at agreed-upon prices. The Company made an up-front payment to W-S 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 PPA helped relieve the financial pressure caused by the closure of Maine Yankee in 1997, as well as the need for substantial increases in the Company’s retail rates, and also reduced its stranded costs. Every two years, the W-S output is sold via competitive bids, with the bidding process monitored by the MPUC. The sale of the W-S output offsets the W-S costs in determining stranded costs. For the period March 1, 2000 to February 28, 2002, WPS-PDI was the successful bidder. For the period March 1, 2002 to February 28, 2004, EA will be taking delivery of 40% of W-S’s output, while WPS-PDI takes the remainder. The Company records the above-market cost of the W-S contract as stranded costs. As stated above, the Company’s Canadian Subsidiary has been inactive for the period of 2000-2002, as reflected in the table below.
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.
Regulation and Rates
The information with respect to regulation and rates is presented in Item 3, “Legal Proceedings,” which information is incorporated herein by reference.
Franchises and Competition
Except for consumers served at retail by the Company’s wholesale customers, the Company has practically an exclusive franchise to deliver electric energy in the Company’s service area. For additional information on changes to the structure of the electric utility industry in Maine, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Overview,” incorporated herein by reference. For information on the competitive conditions facing EA, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Energy Atlantic Activities,” incorporated herein by reference.
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,” which information is incorporated herein by reference.
Subsidiaries and Affiliated Companies
The Company owns 100% of the Common Stock of Maine and New Brunswick Electrical Power Company, Limited (the “Canadian Subsidiary”). The Canadian Subsidiary owned and operated the Tinker Station located in the Province of New Brunswick, Canada, prior to its sale on June 8, 1999, and has not conducted an active business since the sale.
On August 24, 1998, the MPUC approved the formation of the Company’s unregulated subsidiary, Energy Atlantic, LLC (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 start of retail competition in Maine. As a start-up unregulated subsidiary, the Board of Directors and the MPUC limited the capital contributions to a maximum of $2 million, subsequently amended to $2.5 million during 2002.
The Company 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, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Maine Yankee,” incorporated herein by reference.
The Company 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.
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 maintains an Internet site containing such reports at www.mainepublicservice.com. 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, 2002, the Company had approximately 393 pole miles of transmission lines and the Company owned approximately 1,714 miles of distribution lines. Net electric plant in service was approximately $48.74 million at December 31, 2002.
Substantially all of the properties owned by the Company 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 PCB transformers, the Company 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 two years, the Company has spent approximately $576,000 under the 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 Maine Public Service Company 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 platform for new system planning and asset management initiatives. By creating a condition baseline and increasing focus on system planning, the Company is in the process of developing a long-term capital expenditure plan. By implementing a comprehensive asset management initiative, the corporation is focusing on extending transmission and distribution assets’ lifecycles, while ensuring increasing reliability.
The R.W. Beck audit recommended the need for improvements in the Company’s T&D system and capital expenditure planning processes. Steps have been and are being undertaken to enhance overall planning efforts. As a result of the audit, R.W. Beck suggested a number of short and long-term improvements, such as substation consolidation to reduce costs and increase overall system reliability. Through the development of a comprehensive system plan, the Company is developing a long-term strategy to consolidate substations and increase the use of new technologies. Overall, the goals of these initiatives are to reduce capital expenditure requirements, improve reliability and reduce overall operating costs over a long-term planning horizon (ten to fifteen years).
From a transmission perspective, the 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 woodpecker damage is a problem. The audit suggested that higher maintenance costs could be anticipated in the future for certain older lines due to age, type and life expectancy. As a recommendation of the audit, the Company has begun a regular climbing inspection program to ensure the integrity of all poles, cross arms and pole tops. In addition, expanded thermal infrared inspections were recommended and will be implemented.
Audits of the Company’s substations and substation-related business processes were undertaken. The overall ratings for substations were lower 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. Additionally, a number of minor National Electric Safety Code (NESC) violations were noted and are being corrected, representing a cost impact for compliance of less than $100,000. While certain transformers are beyond their normal life expectancy, the Company has implemented a comprehensive testing program to identify problem transformers, implementing preventive maintenance to extend equipment life expectancies. As part of the system planning process, the Company is developing a plan to replace older transformers, which will focus on consolidating substations where possible, all a part of the Company’s long-term system planning process.
R.W. Beck recommended a more focused renewal and replacement program for certain older three-phase 12.5 kV and single-phase distribution lines, as well as a prioritization of certain urban distribution facilities that were observed to be below acceptable standards. Rural distribution lines were generally found to be in good condition. However, the audit suggested improved distribution line vegetation management, noting the transmission system vegetation management was in good condition.
Aggressive and remedial steps are being undertaken to address the findings of the audit. Management, with input by R.W. Beck, indicate their belief that continued capital expenditures at or near the level of annualized transmission and distribution system asset depreciation rates of approximately $2.5 to $3.0 million per year should be adequate to address concerns raised through the audit. Final long-term capital expenditure plans will be subject to completion of a comprehensive system plan.
In addition to the transmission and distribution system audit, and as a result of the closure of an on-system generation facility and potential closure of other merchant generation facilities, a series of analyses were undertaken by independent consultants to evaluate the voltage support impact of the loss of on-system generation. Through load-flow analysis and utilization of specific contingency or transmission outage scenarios, it was determined that under a single contingency or outage condition and during peak load situations, a system-wide outage was possible if at least 50 MW’s of on-system generation was 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, the Company is using their standards for planning criteria. It should be noted that potential contingencies that were studied focused on situations that could impact the Company’s transmission and distribution systems, even though certain transmission assets are located in Canada and are owned by other companies or organizations. Further, the Company does have contingency plans to mitigate such conditions or events in the case that a major transmission outage or system outage occurred.
Maine Public Service Company, given the actual and potential impact of the loss of on-system generation, is working on planning projects to address the potential impact that may include new transmission interconnections and/or increasing of existing interconnections. The Maine Public Utilities Commission is aware of the Company’s concerns and has opened a Notice of Inquiry (MPUC Docket No. 2003-82) to investigate market conditions within Northern Maine, including overall system security due to the loss of on-system generation. The outcomes of the Notice of Inquiry are not known at this time. However, the Company has suggested certain options to address those issues of inquiry. As a result of conditions that may exist if on-system generation closes, the Company is closely evaluating construction of at least one additional transmission interconnection and/or improving existing interconnections with NB Power. Further information concerning the Notice of Inquiry can be found in the following “Legal Proceedings” section, Item 3
Item 3. Legal Proceedings
(a) WPS Energy Services, Inc., Complaint against Maine Public Service Company, and Petition to Alter or Amend the MPUC’s Order Authorizing the Formation of Energy Atlantic, LLC, MPUC Docket Nos. 98-138 and 00-894
On October 30, 2000, WPS Energy Services (WPS), a Competitive Electricity Provider (CEP) offering retail sales of electricity in the Company’s service territory, filed a Complaint (Docket No. 00-894) against the Company, as well as a Petition to Alter or Amend the MPUC’s September 2, 1998 Order in Docket No. 98-138.
The Complaint alleged that the Company violated various provisions of Chapter 304 of the MPUC’s Regulations governing relations between the Company and all CEPs, including the Company’s own marketing subsidiary, Energy
Atlantic, LLC (EA). According to the Complaint, various of the Company’s employees engaged in conduct that either awarded EA a competitive advantage over other CEPs or burdened WPS with an unfair disadvantage relative to EA. These allegations included such practices as denying WPS information made available to EA, or providing EA with information about WPS’s customers that was not available publicly. The Company did not believe it in any way violated any provisions of Chapter 304 and so argued to the MPUC.
In its September 2, 1998 Order in Docket No. 98-138 authorizing the formation of EA, the Commission allowed the Company and EA to share the services of certain employees under certain conditions on the grounds that such sharing was in the public interest and would not have any anti-competitive effect on the retail market for electricity. WPS claimed that the sharing did not conform to the conditions set forth in the Order and that, in any event, the Commission should find such sharing not in the public interest, thereby amending its original September 2, 1998 Order.
The Complaint and Petition to Amend the September 2, 1998 Order, in addition to requesting a prohibition on the sharing of certain employees, particularly Maine Public Service Company’s General Counsel, also sought a formal investigation of the Complaint, penalties for any violations of the Commission’s rules and certain specific relief for violations of Chapter 304.
In its response, the Company strongly denied the allegations in the WPS Complaint and asked the Commission to dismiss the Complaint and for Summary Judgment in its favor.
On May 1, 2001, the Commission issued its Order in this matter, finding that some counts in the WPS Complaint should be dismissed, but that others raised factual issues that could be resolved only through a more formal hearing process. The Commission declined, however, to take initial jurisdiction over the Complaint. Instead, the Commission ordered the parties to submit their dispute to the informal dispute resolution process set forth in MPS’s Chapter 304 Implementation Plan. Under this Plan, the dispute was submitted to an independent law firm, which issued its decision within 30 days of the Commission’s Order. The Commission’s Order stated that the Commission would take jurisdiction over the dispute only if the matter was not resolved to both parties’ satisfaction. The Commission also stated that it would open an investigation into the issues of whether MPS’s General Counsel’s dual role with MPS and EA was inherently problematic and what standards should govern any MPS employees who also provide services to EA.
The parties submitted the dispute to an independent arbitrator who issued his proposed findings on June 29, 2001. The arbitrator found that MPS did not violate any provisions of Chapter 304, except for the Company’s unintentional failure to identify WPS as a Standard Offer Service provider on its March and April 2000 bills to customers. The arbitrator recommended that MPS refund to WPS its billing fees for these two months, approximately $18,000. On July 5, 2001, the Company and WPS informed the Commission of their acceptance of the arbitrator’s findings. As a result, the Commission, in its July 13, 2001 Order, stated that it would not be necessary for it to further address the allegations in the WPS complaint, even though it would continue its investigation into the sharing of employee services.
On March 6, 2002, the Company, WPS and the Public Advocate filed with the MPUC a Stipulation resolving all remaining issues in the investigation. The Stipulation contained several provisions that clarified the extent to which the Company’s senior management could become involved in the affairs of EA and included restrictions and requirements governing the direct contact between the Company’s senior management and EA personnel for all but one designated executive. The Stipulation also specifically prohibited one employee, (the “designated executive”) from being involved in certain types of Company activities, knowledge of which could gain EA a competitive advantage in the retail market. Finally, the Stipulation gave the MPUC the right to conduct an annual audit to determine whether EA and the Company are complying with Chapter 304. The costs of this audit, up to $10,000, shall be paid for by the Company. This Stipulation was approved by the MPUC in an Order dated April 29, 2002. On February 24, 2003, EA announced its intent to withdraw from the Northern Maine market due to the lack of profitability in that market and other wholesale market factors. EA will continue to serve its existing contracts in Northern Maine until they expire through February 28, 2004. EA believes that this action substantially relieves the underlying concerns that gave rise to the WPS Complaint, particularly regarding the sharing of employees in connection with EA’s energy marketing within the Company’s service territory. On February 21, 2003 the Company
filed with the MPUC an “Application for Exemption of Chapter 304” (MPUC Docket No. 2003-122) and expects a ruling on the application during calendar year 2003.
(b) Maine Public Utilities Commission Investigation of Maine Public Service Company’s Stranded Cost Revenue Requirement in MPUC Docket No. 01-240
On May 8, 2001, the MPUC issued a notice of investigation to determine whether the Company’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, the Company 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 the Company’s receipt of a $1,005,000 insurance refund associated with Maine Yankee. As of December 31, 2001, the Company reflected the refund as a miscellaneous deferred credit. A Stipulation approved by the MPUC on January 7, 2002, with the appropriate order issued on February 27, 2002, included annual stranded cost recovery of $11,540,000 and a 15% sharing of the Maine Yankee insurance refund with the Company’s shareholders, thereby leaving the rates charged to core retail customers unchanged.
(c) Maine Public Utilities Commission, Investigation of Rate Design of Transmission and Distribution Utilities, MPUC Docket No. 01-245.
On May 8, 2001, the MPUC issued a Notice of Investigation into certain common fundamental issues regarding the rates for the State’s three major electric utilities: the Company, Central Maine Power Company (CMP) and Bangor Hydro-Electric Company (BHE). These issues have been defined by the MPUC as follows:
(i) The extent to which stranded cost recovery should be shifted from variable KWH and kw charges to a fixed charge;
(ii) The redefinition of time of use periods for rate design; and
(iii) The elimination or reduction of seasonal rates.
The Company originally believed stranded costs should be recovered through fixed charges that its customers cannot avoid by reducing or eliminating their usage. The Company, together with CMP and BHE, filed testimony in support of its position on April 16, 2002. The Company recommended that 50% of the stranded costs allocable to residential and small to medium commercial customers and 25% of the stranded cost allocable to large industrial customers be immediately collected through a fixed charge, with all remaining stranded costs to be phased in during the Company’s next rate case. The Company also recommended immediate elimination of its seasonal rates. After further review of the impact of these proposed changes, which had no overall revenue impact, the Company filed a motion to be permitted to withdraw or be released from this proceeding. The Company stated that its service territory was located in a retail energy market that was distinct from that of CMP or BHE. Because, unlike CMP and BHE, the Company had not yet filed an Alternative Rate Plan (ARP), management, when it became aware of the MPUC Docket No. 01-245, to reconsider its rate design options and, at the same time, avoided the promotion of any billing structures that might limit or conflict with these options. The Company filed an ARP (MPUC Docket 2003-85) on March 6, 2003. On July 30, 2002, the Company filed a Stipulation with the Commission, signed by the parties to the proceeding, to withdraw, without prejudice from the investigation in MPUC Docket No. 01-245. The Commission approved the Company’s petition on August 20, 2002.
(d) Federal Energy Regulatory Commission (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, the Company notified the MPUC of its intention to implement the associated transmission component of its retail transmission and distribution (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%. The Company has increased its transmission rates subject to refund and issuance of a final order by FERC. Although the Company expects FERC’s final order to support the rate increase without any further adjustments, it cannot predict the final outcome of this proceeding.
(e) Maine Public Utilities Commission, Request for Approval of Reorganization of the Company Into a Holding Company Structure, Docket No. 02-676
On October 31, 2002, the Company filed a request for Commission approval of the formation of a Maine-based holding company structure. Under this structure, the Company, Energy Atlantic, as well as other affiliates which might be created at a later date, will become subsidiaries of a holding company (HoldCo). In its application, the Company stated that the corporate restructuring will be accomplished through a “reverse triangular merger,” similar to the one employed in Central Maine Power Company Application for Approval of Reorganization, of Transactions with Affiliated Interests, and Transfer of Assets, Docket No. 97-930.
The proposed restructuring constitutes a reorganization requiring Commission approval pursuant to the provisions of 35-A M.R.S.A. § 708. In addition to the proposed reorganization, the Company also requested the approval of certain stock issuances and affiliated interest transactions.
Specifically, the Company requested Commission approval of the following transactions and arrangements:
1. the creation of a corporation (HoldCo) that will become the parent company of MPS through its ownership of all outstanding company stock of MPS;
2. the creation of a corporation (MergeCo) whose only purpose will be to facilitate the corporate reorganization and which, when organized, will be a wholly-owned subsidiary of HoldCo and which will cease to exist once it has served its purpose;
3. the conversion and exchange of all the outstanding shares of the Company’s common stock into an equal number of shares of HoldCo’s common stock (to the degree that the conversion and exchange of MPS stock to be effected in that transaction is deemed to constitute an issuance of utility stock within the meaning of 35-A M.R.S.A. §§ 901and 902);
4. the merger of MergeCo into the Company, with the Company as the surviving corporation, and the resulting conversion of the outstanding shares of MergeCo common stock into a number of shares of the common stock of the Company equal to the number of shares of the Company’s common stock outstanding immediately prior to the share conversion described in item 3 above, which will be deemed issued by the Company for this purpose;
5. the dividend by Maine Public Service of its limited liability company interests in Energy Atlantic to HoldCo pursuant to 35-A M.R.S.A. §§ 708, 901 and 902;
6. the execution and delivery of the Managerial and Support Services Agreement and approval of the cost manual submitted in conjunction therewith pursuant to 35-A M.R.S.A. § 707;
7. the winding up and dissolving of Me&NB at such future time as MPS might deem appropriate pursuant to 35-A M.R.S.A. § 708; and,
8. the transfer, after the merger date, (i) of assets that are not “necessary or useful” within the meaning of Section 1101 of title 35-A, from MPS to any MPS affiliate, and (ii) the transfer of all other assets from MPS to HoldCo or any non-MPS HoldCo subsidiary in the total amount of up to $1,000,000 over the three-year period beginning upon the merger date.
The Company also requested that the Commission authorize the creation of HoldCo and MergeCo within thirty days of the date of its filing. This “interim approval” would be for the limited purpose of making necessary filings with the Securities and Exchange Commission under the Public Utility Holding Company Act and for executing a registration statement under federal securities law. As part of this request for interim approval, the Company also represented that should the Commission deny its petition for reorganization, or if for any other reason their organization does not occur, it will dissolve both HoldCo and MergeCo.
Subsequent to its filing, the Company received and responded to several requests for information from the MPUC and 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 March 26, 2003. Please see the text of the MPUC Order, Docket No. 2002-676 on Pages O-1 to O-21 of this Form 10-K. The Company has 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 filing is reviewable on the SEC’s website at “http://www.sec.gov/edgar” or on the MPS Investor Relations page at “http://www.mainepublicservice.com/ corporate/1373T04_CP.PDF.”
(f) Maine Public Utilities Commission, Request for Approval of Alternative Rate Plan
On March 6, 2003, following a series of informal meetings with the Office of Public Advocate and the MPUC, the Company submitted its formal “Request for Approval of Alternate Rate Plan” (MPUC Docket 2003-85). The proposal (ARP) is a seven-year rate plan for its distribution delivery services with 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. The ARP has numerous components, all of which have been designed to fit together as an integrated whole that will allow the Company to continue to meet the unique needs of its Northern Maine customers. Its key components include: an inflation index and productivity offset; an adjustment for the treatment of extraordinary costs the Company may incur; an interest expense adjustment; an economic conditions adjustment; a shareholder earnings sharing mechanism; pricing flexibility; reliability safety and service quality indices; and a sharing mechanism for non-core revenues. The Company believes that the ARP will benefit customers by: (1) ensuring that customer’s electric service does not suffer under the plan through the use of the above-described mechanisms; (2) providing predictable and stable rates; (3) providing an acceptable risk sharing environment; and (3) encouraging the Company to minimize its costs wherever possible. At this time the Company cannot predict the nature or the outcome of any decision or ruling by the MPUC in this proceeding.
(g) Maine Public Utilities Commission Notice of Inquiry
On February 11, 2003, the MPUC initiated a formal Notice of Inquiry (NOI) into the status of the competitive market for electricity supply in Northern Maine (MPUC Docket No. 2003-82). The NOI is not directed at the Company or any specific party or entity but is a general inquiry designed to gather information about the adequacy of existing market structures, rules and laws in light of the limited number of supplier/generator participants in the region. The MPUC’s inquiry is for the purpose of identifying potential concerns related to Northern Maine’s supply and market situation, and to explore possible solutions. In contrast to the rest of Maine, which is part of the Independent System Operator - New England (ISO-NE) region, Northern Maine is electrically interconnected to the Canadian Maritimes region, which also includes the electric loads and generation of New Brunswick, as well as Nova Scotia and Prince Edward Island. Load and generation in Northern Maine, which comprises the Company’s service territory, are interconnected to the rest of Maine and New England only by transmission through New Brunswick. The Northern Maine Independent System Administrator (NMISA) operates the bulk power and transmission systems for the region. The divestiture of generation assets in connection with the Maine Electric Industry Restructuring Act eliminated rate regulation for the production and sale of electricity supply as of March 1, 2000. During the subsequent period of time, the retail and wholesale markets have experienced a limited number of participants. In furtherance of the MPUC’s inquiry, it requested comments on a number of issues related to these unique market conditions. The Company has provided comments for the MPUC’s consideration. At this time the Company cannot predict the nature or the outcome of any finding, decision or ruling by the MPUC in this proceeding.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
At the Company’s Annual Meeting of Stockholders, held on May 14, 2002, two matters were voted upon. First was the uncontested election of the following directors to serve until the 2005 Annual Meeting of Stockholders, each of whom received the votes shown:
Second was the approval of the stock option plan reported in Item 5
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
The Company’s Common Stock is listed and traded on the American Stock Exchange. As of December 31, 2002, there were 934 holders of record of the Company’s Common Stock. As of December 31, 2002 and 2001, Common Stock shares issued and outstanding were 1,574,115 and 1,573,510, respectively.
Dividend data and market price related to the Common Stock are tabulated as follows for the two most recent calendar years:
Dividends declared within the quarter are paid on the first day of the succeeding quarter.
See Item 15, Financial Statements, Note 7 to the Consolidated Financial Statements, “Common Shareholders’ Equity,” incorporated herein by reference, concerning restrictions on payment of dividends on Common Stock.
The Company has determined that the Common Stock dividends paid in 2002 are fully taxable for federal income tax purposes. These determinations are subject to review by the Internal Revenue Service, and shareholders will be notified of any significant changes.
Securities Authorized for Issuance Under Equity Compensation Plans.
Item 6.
Item 6. Selected Financial Data
A five-year summary of selected financial data (1998-2002) is as follows:
Five-Year Summary of Selected Financial Data
(1) As noted below in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Overview,” incorporated herein by reference, results for periods ending after March 1, 2000 are not comparable to those for periods ending before that date, which was the effective date of deregulation in Maine, after which the Company no longer sold (as opposed to delivered) energy to its customers.
See Item 7a, Quantitative and Quantitative Disclosures about Market Risk incorporated herein by reference, concerning material risks and uncertainties which could cause the data reflected here in not to be indicative of the Company’s future financial condition or results of operations.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Company’s Consolidated Financial Statements, Item 15 (a) of this Form 10-K.
This Management’s Discussion and Analysis contains certain forward-looking statements, as defined by the Securities and Exchange Commission (the “SEC”), such as forecasts and projections of expected future performance or statements of management’s plans and objectives. These forward-looking statements may be contained in filings with the SEC and in press releases and oral statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe” and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. These statements are based on the current expectations, estimates or projections of management and are not guarantees of future performance. Some or all of these forward-looking statements may not turn out to be what the Company expected. Actual results could potentially differ materially from these statements. Therefore, no assurance can be given that the outcomes stated in such forward-looking statements and estimates will be achieved.
Factors that could cause actual results to differ materially from our projections include, among other matters, electric utility restructuring; future economic and demographic conditions; changes in tax rates; interest rates or rates of inflation; and developments in our legislative, regulatory, and competitive environment.
Maine Public Service Company (the “Company”) is an energy delivery company serving approximately 35,000 retail electric customers in Northern Maine. The Company is subject to the regulatory authority of the Maine Public Utilities Commission (the “MPUC”) for its distribution rates and the Federal Energy Regulatory Commission (the “FERC”) for its transmission rates. Current rates are determined using traditional rate base, and rate of return ratemaking principals used by the regulatory agencies. Future rates may be based on performance based rates, subject to approval of the Company’s alternative rate plan filing with the Maine Public Utilities Commission. (See “Legal Proceedings,” Item 3 (f)).
The Company has two wholly-owned subsidiaries. The accompanying consolidated financial statements include the financial results of its wholly-owned Canadian subsidiary, Maine and New Brunswick Electrical Power Company, Limited, and its wholly-owned marketing subsidiary, Energy Atlantic, LLC (EA).
This section explains 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.
Electric restructuring in Maine began on March 1, 2000, with the Company providing only transmission and distribution (T & D) or delivery services. Prior to March 1, 2000, the Company provided electric power to its customers by operating its own generating facilities or purchasing the power. The MPUC allowed the recovery of stranded costs from our customers, beginning March 1, 2000. Although the Company’s sales in MWH’s are comparable to pre-March 1, 2000 sales since the new T&D delivery rates are still applied to MWH’s delivered, financial results for periods before March 1, 2000, reflect revenues and associated expenses for delivery charges and electric power provided to our customers. After March 1, 2000 the Company’s revenues do not reflect revenues associated with electric power. After considering the differences above, comparisons of financial results for periods prior to March 1, 2000 to periods after that date are difficult.
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
The Company records an estimate for revenue for electricity delivered, but not yet billed to customers. This estimate requires the Company to make certain assumptions. A change in those assumptions could cause the amounts reported as revenues to change. Energy Atlantic’s 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. For Standard Offer Service, 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. For CES sales, EA negotiates the price directly with the customer, maintains customer service responsibility and has collection risk. 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.
Pension and Other Postretirement Benefit Plans
The Company has pension and other postretirement benefit plans, principally healthcare benefits, covering substantially all of its employees. 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 postretirement benefit costs. As of December 31, 2002, the Company decreased the discount rate from 7.0% to 6.5%. For additional information on the Company’s benefit plans, see Item 15 (a) of this Form 10-K, Notes to the Consolidated Financial Statements.
Utility Regulation
The Company 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. Approximately 71% of the Company’s 2002 revenues, as depicted in the “Operating Revenues and Energy Deliveries” section below, derived from 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. The Company’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
Net income and earnings per share for the Company’s core transmission and distribution (T&D) services business, as well as for its wholly-owned unregulated marketing subsidiary, Energy Atlantic, are as follows for the three-year period:
Net income above is allocated based upon the segment allocation as presented in Item 15(a) of this Form 10-K, Note 4 of the Notes to Consolidated Financial Statements, “Segment Information.” Core T & D earnings for 2002 were $1,241,000 less than 2001. Although 2002 sales were 1.4% more than 2001 sales, earnings were impacted by the incremental charges, for the Company’s Voluntary Early Retirement Program (VERP) of $242,000, net of income taxes ($.15 per share), and expenses associated with seeking approval for the formation of the holding company of $105,000, net of income taxes ($.07 per share). The Company incurred additional expenses for employee benefits, principally pension and medical costs, and insurance costs resulting in a reduction in earnings of $723,000, net of income taxes ($.46 per share). In addition, consulting fees for evaluating business processes in the Company and legal expenses for regulatory affairs and compliance with provision of the Sarbanes-Oxley Act of 2002 reduced net income by $575,000, net of income taxes ($.37 per share). Offsetting these additional expenses was a reduction of the Company’s borrowing costs increasing earnings by $362,000, net of income taxes ($.23 per share).
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 and was the principal reason for the decrease in EA’s 2001 earnings, as compared to 2000.
Although 2001 sales for the retail regulated T&D business were 1.8% less than 2000 sales, as more fully explained in the “Operating Revenues and Energy Deliveries” section below, 2001 net income increased by $727,000 to $4,340,000 compared to net income in 2000 of $3,613,000. T&D Operation and Maintenance expenses, as noted in the “Operating Expenses” section below, were $255,000, net of income taxes, less in 2001 than 2000, resulting in an increase in earnings per share of $.16. In addition, interest expenses in 2001 were approximately $720,000, net of income taxes, less than 2000, reflecting the significant reductions in short-term interest rates and the variable interest rates on the tax-exempt bonds used by the Company to fund its construction program, and the reduction in debt as a result of the use of cash proceeds from the generation asset sale, providing an increase in earnings per share of $.44. The reductions in short-term interest rates follow the National trend of lower interest rates as a result of the Federal Reserve’s interest rate cuts to spur the economy.
The Company’s return on equity (net income divided by average common shareholders’ equity) for 2002 was 14.6% compared to 12.7% for 2001 and 13.8% for 2000. The core T&D business earned a return on equity of 7.6% in 2002 compared to 10.5% and 9.5% for 2001 and 2000, respectively. In determining rates at the beginning of deregulation on March 1, 2000, the MPUC authorized a return of equity of 10.7% for the core T&D business. In 2002, as explained above, the Company recorded incremental charges for its VERP, additional consulting fees for
evaluating business processes in the Company and expenses associated with seeking approval for the formation of the holding company, which impact the 2002 return on equity. In addition, the Company incurred additional expenses for employee benefits, insurance costs, and legal expenses associated with regulatory affairs and Sarbanes- Oxley compliance. As explained in Item 3, “Legal Proceedings” of this Form 10-K, the Company is seeking to increase its distribution rates in order to cover the increase in additional operating costs.
Your Board of Directors increased the quarterly dividend from $.30 per share to $.32 per share effective October 1, 2000. On an annual basis, the increase was from $1.20 per share to $1.28 per share. On October 1, 2001, the quarterly dividend was increased by $.03 per share to $.35 per share, or $1.40 per share per year. Effective October 1, 2002, the quarterly dividend was once again increased by $.02 per share to $.37 per share, or $1.48 per share per year.
Operating Revenues and Energy Deliveries
Consolidated revenues and Megawatt Hours (MWH) delivered for the years 2002, 2001 and 2000 are as follows:
(Dollars in Thousands)
The year 2001 was the first full year after Maine’s electric industry restructuring which, as discussed above, began on March 1, 2000. The Company provides transmission and distribution (T&D) delivery services, regulated by the Maine Public Utilities Commission (MPUC), but no longer supplies electric energy. The Company’s wholly-owned marketing subsidiary, Energy Atlantic, LLC, (EA), provides retail electricity as a competitive energy supplier within Maine Public Service Company’s and Central Maine Power’s service areas in Maine. As noted earlier, EA has withdrawn from providing retail electricity services to new customers within Maine Public Service Company’s service territory, but will serve existing customers throughout the term of their contracts, which expire in February, 2004. Comparisons of the regulated retail revenues for the years 2000 through 2002, as evidenced by the chart above, are difficult, but MWH deliveries continue to be comparable. The following discussion on both the T&D and EA segments of the Company, therefore, focus on MWH deliveries.
Regulated retail sales for 2002 were 530,267 MWH, an increase of 1.4% over 2001 and a decrease of .3% over 2000. Residential sales increased by 2.1% over sales in 2001 and 2000, with the 2002 winter months colder than either 2001 or 2000. Large commercial sales were 4% higher than 2001 sales but 2.4% lower than 2000 sales. Sales to McCain Foods, the Company’s largest customer, increased in 2002 to 66,301 MWH, an increase of 7,672 MWH over 2001 and 7,613 MWH over 2000. Sales in 2002 to other food processor customers, other than McCain Foods, decreased by 7,394 MWH and 11,440 MWH over 2001 and 2000, respectively, due principally to the closing of Maine Frozen Foods.
Sales to wood product customers in 2002 were 4,573 MWH more than 2001 but 2,432 MWH less than 2000. Sales in 2002 to other large customers other than food processing and wood product customers increased by 1,528 MWH and 2,190 MWH over sales in 2001and 2000, respectively. Medium commercial sales in 2002 were comparable to 2000, but 3,367 MWH less than 2001. Sales to small commercial customers were 86,639 MWH, as compared to 85,005 MWH in 2001 and 87,867 MWH in 2000.
The MPUC, with jurisdiction over retail rates, approved rates for the Company’s T&D utility as of March 1, 2000, exclusive of energy supply. On October 1, 2002, the Company’s T&D rates were increased by 2% for an increase in transmission rates. The Federal Energy Regulatory Commission (FERC) has jurisdiction over transmission rates. As more fully explained in Item 3, “Legal Proceedings,” section of this Form 10-K, the Company has requested an increase in its distribution rates.
EA’s business is comprised of Standard Offer Service (SOS) and Competitive Energy Supply (CES) activity, as more fully explained in the “Energy Atlantic Activities” section below. EA’s CES activity in 2002 produced sales of 148,072 MWH and $6.9 million in revenues. In 2001, CES sales of 375,768 MWH produced $15.8 million in revenues. In 2000, based on only ten months of activity, CES sales were 824,845 MWH’s and $37.1 million of revenue. The dramatic decline in sales over the three-year period reflects EA’s difficulties in procuring competitive energy supplies at a level of risk consistent with the Company’s conservative fiscal policies, requiring minimal credit coverage. In 2000, with its arrangement with Engage Energy America, LLC (Engage), EA was able to reach an agreement with several large industrial customers in CMP’s service territory. However, these contracts expired during 2001 resulting in the reduction in sales and revenues. The SOS margin represents the net margin on sales of SOS service to approximately 525,000 residential and small commercial customers in CMP’s service territory from March 1, 2000 through February 28, 2002. The SOS margin in 2002 includes the final account settlement with Engage of approximately $4.6 million, before taxes, as more fully explained in the “Energy Atlantic Activities” section below. In 2001, SOS margin reflects a $1.8 million before-tax charge for a contract settlement with Engage.
Other operating revenues in 2002 were $1,901,000 compared to $2,711,000 in 2001 and $2,774,000 in 2000. Wheeling revenues in 2002 were approximately $130,000 less in 2002 compared to 2001 and 2000. The revenues recognized from flexible pricing adjustments from customer discounts as approved by the MPUC were $761,000 less in 2002 compared to 2001 and $180,000 less than 2001. The MPUC in its stranded cost rate review, as more fully described in Item 3, “Legal Proceedings,” of this Form 10-K, adjusted customers rates on March 1, 2002, for these customer discounts.
Operating Expenses
Energy Supply, Transmission and Distribution (T&D) Operation and Maintenance expenses and stranded costs for the three-year period 2000 to 2002 are as follows:
With the advent of deregulation, March 1, 2000, the Company no longer supplies electricity to our retail customers under regulated rates and no longer was required to purchase power for its customers. As discussed above, the Company’s wholly-owned unregulated marketing subsidiary, Energy Atlantic, began providing power to retail markets within the State of Maine. On March 1, 2000, EA’s sales and purchased power expenses for competitive energy supply (CES) were recognized on a gross basis, while its Standard Offer Service (SOS) sales were recognized based on net margin.
Energy supply expenses of $7,160,000 in 2000 represent the Company’s expenses for the first two months of 2000. EA purchases were $36,433,000 in 2000 compared to $14,984,000 in 2001, and $5,533,000 in 2002. As discussed in the “Energy Atlantic Activities” section below, starting March 1, 2000, EA was purchasing power from Engage Energy America, LLC (Engage) for a period of two years for SOS and CES. During 2000, several large industrial customers purchased power from EA under one-year agreements. The decrease in purchases in 2001 as compared to 2000 for EA reflects the expiration of several of these large contracts during 2001. As previously stated in the “Operating Revenues and Energy Deliveries” section above, EA’s CES sales during 2002 produced less revenue than prior years and, correspondingly, required reductions in purchased power.
Transmission and distribution (T&D) expenses in 2002 were $3,334,000, which were slightly lower than 2001 expenses of $3,343,000 and $115,000 higher than 2000 expenses of $3,219,000. Additional tree trimming expense was the primary reason for the increase of expenses for 2001, compared to 2000. For 2002 compared to 2001, reduction in tree trimming expenses were offset by increases in labor costs.
Customer accounting and general administrative expenses were $7,198,000 in 2001, a decrease of $295,000 from 2000, principally due to decreases in regulatory, legal expenses and other employee benefits, which were partially offset by increased medical insurance costs. In 2002, customer accounting and general administrative expenses were $9,710,000, an increase of $2,512,000 over 2001. Approximately $402,000 of the increase was associated with a Voluntary Early Retirement Program (VERP) instituted by the Company in late 2002. As more fully explained in the “Employee” section below, employees representing approximately 7% of the workforce participated in the program. Employee and retiree medical expenses and pension expenses increased by $711,000 in 2002 over 2001. The increase in pension expenses reflects the lower discount rates used to determine pension liabilities and returns that the Company has realized on its pension investments with the sluggish investment markets over the past few years. The Company’s medical costs continue to escalate comparably with National trends. As mentioned in the “Employee” section below, employee contributions will increase and retirees will begin contributing to help offset these escalating costs. Regulatory, consulting and legal expenses increased by $774,000 reflecting costs associated with initial compliance with the Sarbanes-Oxley Act of 2002; increased regulatory activity with the Federal Energy Regulatory Commission concerning the Company’s Open Access Transmission Tariff; legal and rate consulting assistance related to preparation for an alternative rate plan filed with the MPUC during the first quarter of 2003; additional regulatory assessments; legal costs associated with the Company’s proposed migration to a holding company structure, and the undertaking of transmission and distribution and information systems benchmarking audits enabling increased asset management, decreases in overall capital expenditures, increased productivity, improved reliability, and improved prioritization of capital expenditures.
The Company’s charge-offs for bad debts increased $191,000 in 2002 compared to 2001, reflecting the bankruptcies and plant closings of several customers. The Company’s insurance expenses increased by $104,000, following the National cost trend for property and casualty insurance after the terrorist attack on September 11, 2001 and increased Directors’ and Officers’ liability insurance costs following corporate scandals of a number of major corporations.
Energy Atlantic’s 2002 operating expenses increased $348,000 to $1,445,000 over 2001 expenses of $1,097,000, principally due to an increase in bad debt expense, legal expenses associated with the Engage settlement and consulting fees. Operating Expenses for 2000 were $1,351,000, $94,000 less than 2002 operating expenses.
Beginning on March 1, 2000, the Company began recovering stranded costs from its retail customers. As discussed in Item 3(b) of the “Legal Proceedings” section, the MPUC reviewed the Company’s stranded costs and adjusted the Company’s recovery effective March 1, 2002. For 2002, the Company recognized stranded costs of $8,761,000 compared to $9,260,000 for 2001 and $8,906,000 for 2000. The reduction of stranded costs in 2002 reflects the reduction in revenue requirements as discussed in Item 3(b) of the “Legal Proceedings” section. The stranded costs for Wheelabrator-Sherman and Maine Yankee represent actual cash expenses during the year, while the 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 15(a) of this Form 10-K, reflects the Company’s liquidity and sources of operating capital. In 2000, net cash flows provided by operations were $4.7 million. Although net income was $5.3 million, the recognition of $5.4 million of the gain from the 1999 sale of the generating assets, an element of stranded costs, and increases in Energy Atlantic accounts receivable for SOS significantly reduced net cash flows from operations. During 2000, the Company withdrew asset sale proceeds from the trustee of $19 million, using $15 million for the redemption of the 9.775% Series of first mortgage bonds and $2.1 million for the associated redemption premium on that debt. In addition, the Company paid taxes on the generating asset sale of approximately $7.9 million. During 2000, as more fully explained in “Capital Resources,” below, the Maine Public Utilities Financing Bank issued $9 million of its tax-exempt bonds, the 2000 Series, on behalf of the Company to be drawn for the reimbursement of issuance costs of $.3 million and for qualifying expenditures for distribution property. During 2000, $1.6 million was drawn from the trust account. As of December 31, 2000, the Company had approximately $7.5 million remaining in the tax-exempt bond trust fund for the 2000 Series to be used for the construction of qualifying property. As more fully explained in “Capital Resources” below, the Company reinstated a stock buy back program during 2000 and spent $.9 million for 45,000 shares of Common Stock. In 2000, the Company paid $1.9 million in dividends and spent $4.7 million for electric plant. During 2000, an additional $1.3 million was borrowed under the Company’s short-term credit facilities.
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, as more fully discussed in the “Energy Atlantic Activities” section below. In 2001, the Company paid $2.1 million in dividends while reducing short-term borrowings and long-term debt by $2 million. During 2001, the Company received $1.05 million from a settlement with Central Maine Power concerning the 1999 sale of Wyman Unit No. 4, as well as $.5 million for a partial stock redemption from Maine Yankee. As mentioned above, the Company has available proceeds from the issuance of tax-exempt bonds in 2000. During 2001, $2 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.
In 2002, net cash flows 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 recognized while regulatory assets increased by $1.9 million to reflect the rate treatment of stranded costs, which both reduced cash flows. During 2002, the Company 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 the electric plant with $3.7 million withdrawn from the trust account for the tax-exempt bonds. In addition, the Company received approximately $0.4 million for the partial redemption of its Maine Yankee Common Stock. As of December 31, 2002, approximately $2.1 million remains in the tax-exempt trust fund to be used for the construction of qualifying property through October 2003.
For additional information regarding construction expenditures for 2000 to 2002 and anticipated construction expenditures for 2003, see Items 15(a) of this Form 10-K, Note 13 of Notes to Consolidated Financial Statements, “Commitments, Contingencies, and Regulatory Matters - Construction Program.”
To satisfy working capital requirements, the Company 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, 2004. At the end of 2002, the Company had $2.8 million of short-term debt compared to $3.95 million and $4.9 million at the end of 2001, and 2000, respectively. During 2000 to 2002, 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 15(a) of this Form 10-K, Note 6 of the Notes to Consolidated Financial Statements, “Short-Term Credit Arrangements.” Based on current projections for 2003, the Company estimates that operating cash flows and short-term borrowings will be sufficient to cover its 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. The Company is authorized to issue up to 3,000,000 shares of Common Stock. In addition, the Company’s articles of incorporation authorize the issuance of 200,000 shares of Preferred Stock with the par value of $100 per share and 200,000 shares of Preferred Stock with the par value of $25 per share. The Company can also issue second mortgage bonds of $14.3 million without bondable property additions. As more fully explained in the “Holding Company Reorganization” section below, the Company is seeking approvals to reorganize into a Holding Company.
It is anticipated that Maine Public Service Company and Energy Atlantic will become subsidiaries of the Holding Company. The above-mentioned capabilities would continue for Maine Public Service Company, while a newly formed Holding Company, if approved, will seek its own authority for capital formation.
Effective March 1, 2000, in accordance with a Stipulation approved by the MPUC on December 1, 1999, for ratemaking purposes, the Company is required to maintain a capital structure for ratemaking purposes with 51% common equity for the determination of its delivery rates. In anticipation of this requirement, the Company sought approval, which the MPUC granted on November 17, 1999, to repurchase up to 500,000 shares of its Common Stock over a five-year period through an open market program, which began in February 2000. During 2000, the Company purchased 45,000 shares under this program at a cost of $922,000. With the market price of the Company’s stock exceeding its book value during most of 2002 and, in accordance with previous repurchase programs, the Company did not acquire any stock during 2002 and 2001.
With the sale of the generating assets and the use of sale proceeds to redeem debt, the Company’s long-term debt has dramatically decreased. As reflected in Item 6 of this Form 10-K, on January 1, 1999, the Company had $47.2 million of long-term debt compared to $33.8 million at the end of 2002. The Company’s long-term debt currently consists of a 7.95% Series of first mortgage bonds in the amount of $1.8 million due to be redeemed in 2003, two series of tax-exempt bonds issued on behalf of the Company by the Maine Public Utility Financing Bank (MPUFB) totaling $22.6 million, and a series of bonds issued by FAME of $9.4 million, which provided the Company with the funds necessary for the up-front payment to restructure the W-S PPA, as mentioned above.
The MPUFB has issued its tax-exempt bonds on behalf of the Company for the construction of qualifying distribution property. Originally issued for $15 million and reduced with generating asset sale proceeds, the 1996 Refunding Series has $13.6 million outstanding at December 31, 2002 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 and, as of December 31, 2002, approximately $2.1 million is available until October, 2003. For both tax-exempt bond series, a long-term note was issued under a loan agreement between the Company and the MPUFB with the Company 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 (LC’s) for the benefit of the holders of each series of bonds. Both LC’s are due to expire in June 2004. To secure the Company’s obligations under the letter of credit and reimbursement agreement for the 1996 Refunding Series, the Company issued second mortgage bonds in the amount of $14.4 million in June 2002. For the 2000 series, the Company issued first and second mortgage bonds, in the amounts of $5 million and $4.525 million, respectively, to secure the Company’s obligation under the letter of credit and reimbursement agreement for this series. For both series, the Company has the option of selecting weekly, monthly, annual or term interest rate periods. For both series, the Company has continued to use the weekly interest rate period. Since issuance, the average of these weekly rates was 3.28% and 2.35% for the 1996 Refunding Series and the 2000 Series, respectively. On November 17, 2000, the Company purchased an interest rate cap of 6%, expiring in November 2003 to cover both series at a cost of $36,386. At the end of 2002, the cumulative effective interest rate, which includes the weekly interest rate, LC fees and cost of issuance, were 5.14% for the 1996 Refunding Series and 4.96% for the 2000 Series.
On May 29, 1998, FAME issued $11,540,000 of its Taxable Electric Rate Stabilization Revenue Notes, Series 1998A (Maine Public Service Company) (the “Notes”) on behalf of the Company. 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 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 the Company and the Capital Reserve Fund held by the Trustee. The Company issued $4 million of its first mortgage bonds and $7.54 million of its second mortgage bonds as collateral for its performance under the Loan Note issued pursuant to the Loan Agreement. The Notes will bear interest at a Floating Interest Rate and will be adjusted weekly. Since issuance, the average of these weekly rates is 4.52%. On June 1, 1998, the Company 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 2002, the cumulative effective interest rate, including issuance costs and credit enhancement fees, since issuance for this Series was 5.57%.
Energy Atlantic Activities
Energy Atlantic’s 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. Except as stated below, the electricity for those sales within ISO New England was provided entirely under a Wholesale Power Sales Agreement (the “Agreement”) with Engage Energy America, LLC (Engage), which also expired on February 28, 2002. Under this Agreement, all revenues from both SOS and CES sales were paid directly to an Escrow Agent that disbursed funds in accordance with instructions from Engage. For SOS sales, EA received reimbursement for certain expenses and a portion of the net profit that was reported as SOS margin.
On May 24, 2001, the Maine Public Utilities Commission (MPUC) issued an Order authorizing a comprehensive settlement of the dispute between EA and Engage. In connection with the MPUC Order, EA, Engage, CMP, and other parties entered into a comprehensive settlement which included the following:
(i) Engage continued to supply EA with all energy required to perform outstanding retail contracts and the SOS commitments, until the expiration of the Agreement.
(ii) Engage and EA released one another from liabilities arising on or before May 24, 2001, with limited exceptions.
(iii) EA was no longer required to purchase power exclusively from Engage.
(iv) Before its expiration on February 28, 2002, the Wholesale Agreement could not be terminated by EA or Engage except upon the willful and material misconduct of the other party.
(v) The order waives the requirement that EA provide a performance bond. Frontier Insurance Company (Frontier) was released from liability under its bond and Frontier released EA and the Company from any and all claims for indemnification, subrogation or contribution under the bond and associated indemnification agreement.
(vi) Westcoast Energy, Inc., (Engage’s then current parent company) provided CMP a $33 million guarantee of Engage’s performance, and Coastal Corporation (a former affiliate of Engage) was released from its prior guarantee of Engage’s performance.
(vii) Engage received $8 million over the remaining term of the Wholesale Power Agreement consisting of the following: $1 million received from Frontier; a $4.5 million offset from amounts Engage was otherwise obligated to pay to CMP for entitlements; a total of $1.0 million of payments from EA in monthly increments through March, 2002; and a $1.5 million payment from EA in April, 2002. Under the Order, CMP was allowed to recover the $4.5 million from ratepayers instead of from Engage.
In connection with this settlement, EA recognized a charge against second quarter 2001 earnings (after-tax) of approximately $1.08 million, or $.69 per share.
During a scheduled audit of the revenue and expenses accruing under the Agreement conducted by Engage’s auditors in August of 2001, a discrepancy was identified between the reconciliation of kilowatt-hours (KWH) settled by CMP with ISO New England and transferred by ISO New England to Engage, and the KWH revenues achieved by Engage and EA through customer billing derived from actual meter readings. The August 2001 audit noted that this discrepancy was negative in some months and positive in others during the preceding year. As a precautionary measure, on January 21, 2002, EA and Engage agreed to instruct the Escrow Agent to maintain $1.5 million in the escrow account until the completion of the scheduled final audit of the contract activity, the expiration of the Escrow Agreement, and the release of EA from further obligations pertaining to the Agreement. When final billing information for the month following the February 28, 2002 expiration of the SOS activity in CMP’s service territory was received, EA determined that SOS megawatt-hours (MWH) billed to residential and small commercial customers by CMP exceeded the MWH allocated to the SOS activity by ISO New England by approximately 152,000 MWH, or approximately 2% of the total load charged to the SOS over the two-year period. The associated $6.1 million represents additional cash and revenue distributed to and shared by EA and Engage, with EA’s share being $4.8 million. Management believes the difference in MWH was a result of the difference between estimated and actual line loss or the estimating process the utility and ISO New England uses to report the amount of energy transferred to individual energy providers. Management also believes the SOS customers were billed only for the energy delivered according to their meters as read by CMP. Through August 31, 2002, EA recognized revenues based on the MWH allocated to the SOS by ISO New England, thereby excluding the impact of the discrepancy. During the third quarter of 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. In addition to the SOS revenue adjustment, EA reversed $321,000 ($.12 per share) of expenses previously accrued for EA’s share of possible regulatory assessments under the Agreement with Engage. This assessment was imposed on Engage by FERC during the course of the Engage/EA Agreement. Engage has indicated that due to a change in regulation, FERC has notified Engage that it will not be making any further assessments in connection with this matter. A further adjustment in the fourth quarter reduced the
settlement by approximately $105,000, after taxes, or $.07 per share. As a result, the total impact of the settlement increased earnings per share by $1.89.
EA has entered into a contract for 40% of the output of the Wheelabrator-Sherman (W-S) energy facility for the two years beginning March 1, 2002. The output from this take-or-pay contract amounts to approximately 55,000 MWH annually and is being used to provide electricity for additional CES sales within MPS’s service territory. This is EA’s first take-or-pay contract, which carries more counterparty risk than others entered into to date. To mitigate this risk, EA has entered into a contract with NB Power, whereby NB Power will buy W-S output in excess of load requirements in the Company’s service territory at a rate indexed to the price of 3% Sulphur Max No. 6 residential oil into New York Harbor, which is intended to reflect NB Power’s avoided cost, subject to a floor and ceiling. Currently, all output has been sold to CES customers, therefore limiting the risk that energy will be sold to NB Power. In addition, NB Power will sell electricity to EA when load exceeds W-S output at a fixed on and off-peak rate.
In addition, EA has 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 has agreed to waive this credit requirement in lieu of EA’s commitment to maintain a $1 million ($1,000,000) minimum bank account balance.
The following illustrates the type of EA’s risk exposure related to these contracts for supply and sales:
• Counterparty risk includes 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 the 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 occur (1) if energy is not available from W-S, 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 W-S, as contracted.
• Forecasting risk exposure includes possible inaccuracy in the estimation of energy supply requirements. One of EA’s suppliers requires a 24-month forecast of load for each commitment to a 1 MW block of energy. Although there is no penalty for not using all of the energy, EA is 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 W-S power to NB Power at a current market-indexed rate.
With the expiration of the SOS arrangement in CMP’s service territory, EA will be 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. The Company continues to review EA’s current and future business model, which may include a possible exit from the CES market in part or
in whole, a refinement of its market area, and/or expansion into other product and service lines. 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 factors. EA will continue to serve existing contracts in Northern Maine until they expire by February 28, 2004. CES sales in Northern Maine were approximately $5 million in 2002. EA believes that, in addition to minimizing its risk profile, this action will substantially relieve any underlying concerns that may exist in connection with the issue of employee sharing and EA’s energy marketing activities within the Company’s service territory. On February 21, 2003 the Company 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 and expects a ruling on the application during calendar year 2003. (See Item 3 “Legal Proceedings,” paragraph (a)).
Holding Company Reorganization
On October 4, 2002, the Company’s Board of Directors authorized the Company to reorganize into a holding company structure. The intended result would be that Maine Public Service Company (the “Company”) would become a wholly-owned subsidiary of a new holding company. Maine and New Brunswick Electrical Power Company, Ltd., will remain a subsidiary of the Company until all obligations have terminated, at which time it is proposed the subsidiary may be dissolved. The ownership of Energy Atlantic, LLC, now a subsidiary of the Company, would be transferred to the holding company. To achieve this corporate structure, stock in the Company will be exchanged for stock in the new holding company through a “reverse triangular merger.” The reorganization will not go forward without an opinion of counsel that the transaction does not cause federal income tax liability to the Company’s shareholders, whose stock is exchanged in the reorganization. The Company will be undertaking the reorganization in order to maintain its focus on its core regulated business, while at the same time positioning the Company for more diversified growth.
The reorganization will require the approval of the Maine Public Utilities Commission, the U.S. Securities and Exchange Commission under the Public Utilities Holding Company Act, and from the Federal Energy Regulatory Commission 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 must also be obtained, and will be sought, in connection with the Company’s outstanding indebtedness.
After regulatory approvals have been obtained, the Company will request shareholder approval for the reorganization. Prior to the Company’s Annual Shareholder Meeting, specific details concerning the holding company will be provided to shareholders. Investor tours and a web-cast will be held prior to the 2003 Annual Shareholders Meeting to detail plans and answer specific shareholder questions. Management’s goal is to have the necessary regulatory approvals in place prior to the date of our annual meeting. Subsequent to its filing, the Company received and responded to several requests for information from the MPUC and Office of Public Advocate, an intervenor in the proceeding, and met on several occasions with these and other interested parties. The parties settled all issues in the proceeding and entered a signed Stipulation to that effect that was formally approved by the MPUC on March 26, 2003. The MPUC Order in Docket No. 2002-676, authorizing the Company to form a holding company structure is included on Pages O-1 to O-21 of this Form 10-K. The Company filed, on March 11, 2003, a Form S-4 Registration Statement with the Securities and Exchange Commission for the “Maine & Maritimes Corporation,” the entity designated as “HoldCo” in this disclosure. The filing is reviewable on the SEC’s website at http://www.sec.gov/edgar or on the MPS Investor Relations page at http://www.mainepublicservice.com/corporate/ 1373T04_CP.PDF. For additional information on the strategic vision for the Maine & Maritimes Corporation, please refer to the Form S-4 mentioned above and Exhibit 99(ao) of this Form 10-K, Letter to Shareholders and Q&A with the President from the 2002 Maine Public Service Company Annual Report, incorporated herein by reference.
Employees
At the end of 2001, the Company had 145 full-time employees and 146 at the end of 2002. As of March 1, 2003, the Company’s employment was 136. The Canadian subsidiary, Maine and New Brunswick Electrical Power Company, Ltd., has had no employees since the generating asset sale on June 8, 1999. Energy Atlantic, the unregulated marketing subsidiary, had 9 and 11 full-time employees at the end of both 2002 and 2001, respectively. As of March 1, 2003, EA had a total of 8 employees. Consolidated payroll costs were $7.3 million for 2002 and $7.0 million for 2001.
Local 1837 of the International Brotherhood of Electrical Workers ratified a three-year contract with the Company, effective on 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 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. As further discussed in the “Earnings” and “Operating Expenses” sections above, a charge of approximately $402,000, before income taxes, was taken in the fourth quarter of 2002. In an effort to control medical insurance costs, employee contributions will increase by approximately 45%, effective January 1, 2003, and plan deductibles will increase. In addition, all retirees began contributing toward retiree medical coverage.
Maine Yankee
The Company 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 the Company’s 5% share would be approximately $46.5 million. In December 1998, June 1999, September 2000, February 2001, December 2001, March 2002, May 2002, and again in September, 2002, Maine Yankee updated its estimate of decommissioning costs based on the Settlement. Legislation enacted in Maine in 1997 calls for restructuring the electric utility industry and provides 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, the Company believes that it is entitled to recover substantially all of its share of such costs from its customers and, as of December 31, 2002, is carrying on its consolidated balance sheet a regulatory asset and a corresponding liability in the amount of $22.15 million, which reflects the Company’s 5% share of Maine Yankee’s September 2002 revised estimate of the remaining decommissioning costs, less actual decommissioning payments made since then.
The MPUC, on January 27, 2002, approved a Stipulation providing for the recovery of stranded investment, for a two-year period March 1, 2002 until February 29, 2004, which includes the Company’s share of Maine Yankee decommissioning expenses, Maine Yankee replacement power costs, and the remaining Maine Yankee investment. As of December 31, 2002, deferred fuel of $13.1 million is reflected as a regulatory asset, which includes the Maine Yankee replacement power costs, as well as deferred Wheelabrator-Sherman fuel costs.
In May 2000, Maine Yankee terminated its decommissioning operations contract with Stone & Webster Engineering Corporation (Stone & Webster) pursuant to 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.
Upon the contract termination, Maine Yankee temporarily assumed the general contractor role and entered into interim agreements with Stone & Webster and obtained assignments of several subcontracts in order to allow decommissioning work to continue and to avoid the adverse consequences of an abrupt or inefficient demobilization from the Plant site. Decommissioning of the Plant site continued with major emphasis directed to maintaining the schedule on critical-path projects such as construction of an independent spent fuel storage installation (ISFSI) and preparation of the Plant’s reactor vessel for eventual shipment to an off-site disposal facility. After assessing its long-term alternatives for safely and efficiently completing the decommissioning, including evaluating proposals from prospective successor general contractors, on January 26, 2001, Maine Yankee announced that it would continue to manage the project itself.
In June 2000, Federal Insurance Company (Federal), which had provided performance and payment bonds in the amount of approximately $38.5 million each in connection with the decommissioning operations contract, filed a declaratory-judgment complaint against Maine Yankee in the Bankruptcy Court in Delaware, which was subsequently transferred to the United States District Court in Maine.
The complaint alleged that Maine Yankee had improperly terminated the decommissioning operations contract with Stone & Webster and had failed to give proper notice of the termination to Federal under the contract, and that Federal had no further obligations under the bonds.
After extensive discovery and resolution of certain preliminary issues by the court, in December 2001 Maine Yankee and Federal entered into a settlement agreement pursuant to which Federal paid Maine Yankee $44 million on January 18, 2002. The settlement was reflected on Maine Yankee’s 2001 financial statements. That amount represents full payment under the performance bond, plus an additional amount under the 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.
Maine Yankee has continued to pursue its claim for damages that was originally filed against Stone & Webster and its parent corporations in August 2000 in the Bankruptcy Court in Delaware. After recognizing the payment from Federal, Maine Yankee has asserted a right to recover an additional $21 million in that court from the bankruptcy estates. In February 2002, Stone & Webster filed a claim for approximately $7 million against Maine Yankee in the Bankruptcy Court in Delaware for alleged breaches of contract and to subordinate any Maine Yankee claims. On May 30, 2002, the court concluded extensive hearings and argument by allowing a claim in favor of Maine Yankee under section 502 (c) of the Bankruptcy Code, in the estimated amount of $20.8 million against each of the three principal estates (jointly and severally). The Court’s ruling also effectively precluded approximately $4 million of Stone & Webster’s February 2002 claim against Maine Yankee, while offering no opinion or findings on the remainder, the resolution of which will, if necessary, be the subject of further motions and proceedings. The actual cash amount to be recovered by Maine Yankee on this allowed claim remains contingent on a number of factors beyond Maine Yankee’s control, including without limitation the extent to which the bankruptcy estates ultimately have assets available to pay the claim, the ultimate disposition of Stone & Webster’s February 2002 claim, possible reconsideration of the ruling in the future based on actual expenses of completing the decommissioning, and the effect, if any, of any appeal of the May 30, 2002 decision by the bankruptcy estates. Maine Yankee, therefore, cannot predict the final outcome of the Bankruptcy Court proceeding.
Federal legislation enacted in 1987 directed the 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 of the United States for the development of a nuclear waste repository, and the President then recommended development of the site to the Congress. As provided in the statutory procedure, the State of Nevada formally objected to the site in April 2002, and in July 2002, the 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 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 associate 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. 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 independent spent fuel storage installation (ISFSI), utilizing dry-cask storage, on the Plant site and is in 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 had indicated that it disputes Maine Yankee’s basis for terminating the contract and has served Maine Yankee with a demand to arbitrate the dispute, while at the same time the parties have been in negotiations to resolve the situation. In the meantime, Maine Yankee has entered into contracts with the major subcontractors and resumed the transfer of fuel to the ISFSI under its own management. Maine Yankee believes that its termination of the NAC contract was legally justified, but cannot predict the outcome of the negotiations or arbitration proceeding.
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 a plan approved by the Securities and Exchange Commission, Maine Yankee has started the redemption of its Common Stock periodically through 2008.
New Accounting Pronouncements
The Company has adopted Statement of Financial Accounting Standards No. 144 (SFAS 144), “Accounting for the Impairment or Disposal of Long Lived Assets,” effective January 1, 2002. This Statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS 144 establishes a single accounting model, based on the framework established in Statement 121, for long-lived assets to be disposed of by sale and also resolves significant implementation issues related to Statement 121. The adoption of this statement had no impact on its financial position or results of operations.
In June of 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and associated asset retirement costs. This Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. The Company currently records an asset retirement obligation related to the decommissioning of Maine Yankee in its financial statements. The Company does not expect the adoption of this statement to have a material impact on its financial position or results of operations.
In December 2002, the FASB issued “Accounting for Stock-Based Compensation” (SFAS No. 148). This Statement provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. Additionally, SFAS No. 148 amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company has adopted the additional disclosure provisions of this statement required for the year ended December 31, 2002 and will include the prescribed additional disclosures in future filings on Form 10-Q.
On January 17, 2003, the Financial Accounting Standards Board issued FASB Interpretation No. 46, (FIN 46), “Consolidation of Variable Interest Entities.” The provisions have far-reaching effects and will be the guidance that determines (1) whether consolidation is required under the “controlling financial interest” model of Accounting Research Bulletin No. 51 (ARB 51), “Consolidated Financial Statements” (or other existing authoritative guidance) or, alternatively, (2) whether the variable interest model under FIN 46 should be used to account for existing and new entities. The transitional disclosures are required for financial statements issued after February 1, 2003. FIN 46 is effective and required to be applied to pre-existing entities as of the beginning of the first interim period beginning after June 15, 2003. The Company does not expect the adoption of this statement will have a material impact on the Company based on its current structure.
In November 2002, the FASB issued FIN No. 45, (FIN 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 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. The Interpretation 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.
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
Item 7a.
Item 7a. Quantitative and Qualitative Disclosures about Market Risk
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, 2002.
Regulatory Proceedings
For regulatory proceedings, see Item 3, “Legal Proceedings,” incorporated herein by reference.
(a) The Company has interest rate risk with three variable rate debt issues of the regulated business as of December 31, 2002 for purposes other than trading. One issue, $9 million of tax-exempt bonds as of December 31, 2002, issued on the Company’s behalf by the Maine Public Utility Financing Bank (MPUFB) on October 19, 2000, Public Utility Revenue Bonds, 2000 Series is discussed in detail in Item 15 (a), the Company’s Consolidated Financial Statements, in Note 8 to the Consolidated Financial Statements, “Long-Term Debt,” and is hereby incorporated by reference. The other two variable rate debt issues include the Taxable Electric Rate Stabilization Revenue Notes issued on May 29, 1998 by the Finance Authority of Maine with an outstanding balance of $9.365 million as of December 31, 2002, and the Public Utility Refunding Revenue Bonds, 1996 Series, issued by the MPUFB on behalf of the Company in 1996, with $13.6 million outstanding as of December 31, 2002. As discussed in Note 8 to the Consolidated Financial Statements, the Company purchased interest rate caps for each of these issues. If interest rates on the variable rate debt issues described above increased by 1%, the Company’s interest costs will increase by approximately $320,000.
(b) The Company’s unregulated marketing subsidiary, Energy Atlantic, LLC (EA) is engaged in retail and wholesale energy transactions for purposes other than trading. This activity exposes EA to a number of risks such as market liquidity, deliverability and credit risk. EA seeks to assure that risks are identified, evaluated and actively managed.
(c) As a regulated electric utility, the business is exposed to regulatory and legislative risks. An example of legislative and regulatory risks includes the State of Maine’s deregulation and unbundling of the electric utility industry. The Company cannot predict with certainty the future rules, regulations and mandates that may be imposed by Federal or State regulatory and/or legislative bodies.
Item 8.
Item 8. Financial Statements and Supplementary Data
(a) The following financial statements and supplementary data are included in Item 15(a), the Company’s Consolidated Financial Statements, and are incorporated herein by reference:
Report of Independent Accountants.
Statements of Consolidated Income for the years ended December 31, 2002, 2001 and 2000.
Statements of Consolidated Cash Flows for the years ended December 31, 2002, 2001 and 2000.
Consolidated Balance Sheets as of December 31, 2002 and 2001.
Statements of Consolidated Common Shareholders’ Equity for the years ended December 31, 2002, 2001 and 2000.
Consolidated Statements of Capitalization as of December 31, 2002 and 2001.
Notes to Consolidated Financial Statements.
Item 9.
Item 9. Changes In And Disagreements With Accountants On Accounting and Financial Disclosure
None.
PART III
Item 10.
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 2003 Annual Meeting of Stockholders, which information is incorporated herein by reference. Certain information regarding executive officers is set forth below and also in the proxy statement of the registrant relating to the 2003 Annual Meeting of Stockholders, under “Compliance with Section 16(a) of the Securities and Exchange Act of 1934,” which information is incorporated by 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-Elect on March 1, 2002 to be effective March 18, 2002. He replaced Paul R. Cariani as President on June 1, 2002, and upon Mr. Cariani’s retirement effective September 1, 2002, he also assumed the position of Chief Executive Officer. Immediately prior to joining the Company, 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, a web-based, advanced knowledge management software firm serving 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.
Larry E. LaPlante was elected to the position of Vice President, Treasurer and Chief Financial Officer on June 1, 1999. Mr. LaPlante was appointed Secretary and Clerk of the Company effective February 15, 2002. 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 and Treasurer effective June 1, 1994. Effective June 1, 1996, he was elected to Vice President, Finance, Administration and Treasurer.
William L. Cyr was elected to the position of Vice President, Power Delivery effective June 1, 2000. He has been a full-time employee of the Company since July 1, 1982 in various engineering capacities until his appointment to Assistant Vice President, Power Delivery, effective June 1, 1999.
Michael A. Thibodeau was elected to the position of Vice President, Controller and Chief Risk Officer effective September 2, 2002. He has been an employee of the Company since August 3, 1981, serving in various accounting, finance and human resource capacities. He served as Assistant Treasurer from June 1, 1986 until his appointment to Assistant Vice President, Administration effective April 1, 1991. Effective April 1, 1996, he was appointed Assistant Vice President, Human Resources. Effective December 1, 2000, he was elected Vice President, Human Resources.
Scott L. Sells, Esquire, of the law firm of Curtis Thaxter Stevens Broder & Micoleau, LLC, was elected to the position of General Counsel on July 12, 2002. Mr. Sells has been with Curtis Thaxter for two years. Prior to joining Curtis Thaxter, Mr. Sells was an Assistant General Counsel for Duke Energy in Denver, practiced law with a firm in Denver, CO and served as Assistant Attorney General for the State of Colorado.
Brent M. Boyles was elected to the position of Vice President, Marketing and Customer Service, effective September 2, 2002. He has been an employee of the Company since May 14, 1984 in various positions including Planning Engineer, Supervisor of Power Supply and Planning, Manager of Corporate Planning, and Manager of Planning and System Operations.
Kurt A. Tornquist was elected to the position of Vice President, Corporate Performance and Development, effective September 2, 2002. He has been an employee of the Company since July 1, 1992, joining the Company as Assistant Controller. On June 1, 1994, Mr. Tornquist was appointed Controller and Assistant Treasurer until his election to his current position.
John P. Havrilla was elected to the position of Vice President, Unregulated Businesses, effective November 15, 2002. Mr. Havrilla has over twenty-two 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 Company (NYSEG). During his career he has led the successful acquisition and integration of eight U.S. and Canadian firms. He is a professional engineer licensed in the States of New York and Maine and graduated from Pennsylvania State University with a B.S. degree in Electrical Engineering Technology.
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 30, 2003.
There are no family relationships among the executive officers.
Item 11.
Item 11. Executive Compensation
Information for this item is set forth in the proxy statement of the registrant relating to its 2003 Annual Meeting of Stockholders, which information is incorporated herein by reference.
Item 12.
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 2003 Annual Meeting of Stockholders, which information is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions
Not applicable.
PART IV
Item 14.
Item 14. Controls and Procedures
1) Evaluation of disclosure controls and procedures.
The Company’s President and Chief Executive Officer and Vice President, Treasurer and Chief Financial Officer have implemented new disclosure controls and procedures. Based on their reviews of these disclosure controls and the 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.
Item 15.
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) (1) Financial Statements
Report of Independent Accountants
Statements of Consolidated Income for years ended December 31, 2002, 2001 and 2000
Statements of Consolidated Cash Flows for the years ended December 31, 2002, 2001 and 2000
Consolidated Balance Sheets as of December 31, 2002 and 2001
Statements of Consolidated Common Shareholders’ Equity for the years ended December 31, 2002, 2001and 2000
Consolidated Statements of Capitalization as of December 31, 2002 and 2001
Notes to Consolidated Financial Statements
Report of Independent Accountants
To The Directors and Shareholders of
Maine Public Service Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) on Page 33 present fairly, in all material respects, the financial position of Maine Public Service Company and its Subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 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 15(a)(2) on Page 63 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.
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARIES
Statements of Consolidated Income
See Notes to Consolidated Financial Statements.
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARIES
Statements of Consolidated Cash Flows
See Notes to Consolidated Financial Statements.
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
See Notes to Consolidated Financial Statements.
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARIES
Capitalization and Liabilities
See Notes to Consolidated Financial Statements.
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARIES
Statement of Consolidated Common Shareholder’s Equity
See Notes to Consolidated Financial Statements.
MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
Current Maturities and Redemption Requirements for the Succeeding Five Years and Thereafter Are as Follows:
Long-Term Debt:
* Subject to early redemption premiums as defined in the bond indentures.
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
Regulations
Maine Public Service Company (the “Company”) 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.
Consolidation and Basis of Presentation
The accompanying consolidated financial statements include the accounts of the Company, its wholly-owned Canadian subsidiary, Maine and New Brunswick Electrical Power Company, Limited, (Maine and New Brunswick), and its wholly-owned energy marketing subsidiary, Energy Atlantic, LLC, (EA). All intercompany balances and transactions have been eliminated in consolidation.
Estimates
The preparation of financial statements in conformity with generally accepted accounting principles 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 Maine and New Brunswick is the U.S. dollar. Accordingly, translation gains and losses are included in other income. Income and expenses of Maine and New Brunswick are translated at rates of exchange prevailing at the time the income is earned or the expenses are incurred, except for depreciation which is translated at rates existing on the applicable in-service dates. Assets and liabilities are translated at year-end exchange rates, except for utility plant which is translated at rates existing on the applicable in-service dates.
Deferred Fuel and Purchased Energy Costs
Certain Wheelabrator-Sherman (W-S) fuel costs and the sharing provisions for Maine Yankee replacement power costs were deferred for future recovery as defined in the Company’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 W-S fuel is being deferred. The resulting deferred asset is expected to be collected in future rates as approved by the MPUC.
Revenue Recognition
Operating revenues include the Company’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 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 negotiates the price directly with the customer, maintains customer service responsibility and has collection risk. For Standard Offer Service, revenues were received and expenses were paid directly by an escrow agent which was controlled by 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, the Company 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. During 2002 and 2001, $200,000 and $961,000, respectively, were recognized as revenue as flexible pricing adjustments, as described in Note 13, “Commitments, Contingencies and Regulatory Matters - MPUC Approves Elements of Rates Effective March 1, 2000.”
Utility Plant
Utility plant 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, including the cost of removal less salvage, is charged to accumulated depreciation. The cost of maintenance and repairs, including replacement of minor items of property, are charged to maintenance expense as incurred. The Company’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. The composite depreciation rate, expressed as a percentage of average depreciable plant in service, was approximately 3.10%, 3.37%, and 3.23% for 2002, 2001, and 2000, 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 13, “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.
The Company has deferred investment tax credits and amortizes the credits over the remaining estimated useful life of the related utility plant.
The Company records regulatory assets or liabilities related to certain deferred tax liabilities or assets, representing its expectation that, consistent with current and expected ratemaking, those taxes will be recovered from or returned to customers through future rates.
Investments in Associated Companies
The Company records its investments in Associated Companies (see Note 5, “Investments in Associated Companies”) using the equity method.
Pledged Assets
The Common Stock of Maine and New Brunswick is pledged as additional collateral for the first and second mortgage and collateral trust bonds of the Company. In December, 1999, a liquidating dividend in the amount of $14.8 million, representing after-tax proceeds from the sale of the generating assets, was paid by Maine and New Brunswick to the Company. In accordance with the mortgage indentures, the dividend net of withholding taxes was deposited with the first mortgage trustee.
Inventory
Inventory 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.
Interest Rate Caps
Interest rate caps involve the exchange of cash for a cap on the interest rate the Company can be charged and are considered derivatives. 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 and 138, 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 11, “SFAS No. 133” for required disclosure on these interest rate caps.
Stock Option Plan
At December 31, 2002, 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 2001 and 2000 financial statement amounts in order to conform to the 2002 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, 2002. Options to purchase 5,250 shares of Common Stock at $30.45 per share were outstanding during the second half of 2002, but were not included in the computation of diluted EPS because the options’ exercise price was greater than the average market price of the Common Shares and, therefore, the effect would be anti-dilutive. The options, which expire on May 30, 2012, were still outstanding at the end of year 2002.
Accounting Pronouncements
In June of 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and associated asset retirement costs. This Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. The Company currently records an asset retirement obligation related to the decommissioning of Maine Yankee in its financial statements. The Company does not expect the adoption of this statement to have a material impact on its financial position or results of operations.
In October of 2001, the FASB issued SFAS 144, “Accounting for the Impairment or Disposal of Long Lived Assets.” This Statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets and is effective for fiscal years beginning after December 15, 2001. This Statement supersedes FASB Statement No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,” and the accounting and reporting provisions of APB Opinion No. 30, “Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions,” for the disposal of a segment of a business (as previously defined in that Opinion). This Statement also amends ARB No. 51, “Consolidated Financial Statements,” to eliminate the exception to consolidation for a subsidiary for which control is likely to be temporary. SFAS 144 establishes a single accounting model, based on the framework established in Statement 121, for long-lived assets to be disposed of by sale and also resolves significant implementation issues related to Statement 121. The adoption of SFAS 144 had no material impact on its financial position or results of operations.
In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation” (SFAS No. 148). This statement provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. Additionally, SFAS 148 amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company has adopted the additional disclosure provisions of this statement for the year ended December 31, 2002 and will include the prescribed additional disclosures in future filings on Form 10-Q.
On January 17, 2003, the FASB issued FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities.” The provisions have far-reaching effects and will be the guidance that determines (1) whether consolidation is required under the “controlling financial interest” model of Accounting Research Bulletin No. 51 (ARB 51), “Consolidated Financial Statements” (or other existing authoritative guidance) or, alternatively, (2) whether the variable interest model under FIN 46 should be used to account for existing and new entities. The transitional disclosures are required for financial statements issued after February 1, 2003. FIN 46 is effective and required to be applied to preexisting entities as of the beginning of the first interim period beginning after June 15, 2003. The Company does not expect the adoption of this statement will have a material impact on the Company based on its current structure.
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, with the exception of Energy Atlantic activity, which is above the line and not allowable for ratemaking purposes. 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:
The elements of deferred income tax expense (credit) are as follows (in thousands):
The Company has not accrued U.S. income taxes on the undistributed earnings of Maine and New Brunswick Electrical Power Company, Ltd. (Maine and New Brunswick), 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 Maine and New Brunswick in 2002, 2001 or 2000.
The following summarizes accumulated deferred income tax (assets) and liabilities established on temporary differences under SFAS 109 as of December 31, 2002 and 2001:
3. ENERGY ATLANTIC
In January, 1999, Energy Atlantic, the Company’s wholly-owned unregulated marketing subsidiary, formally began operations. This marketing subsidiary was involved in wholesale energy transactions during 1999 and the first two months of 2000, and began selling to retail customers on March 1, 2000, the commencement of retail competition in the State of Maine.
Energy Atlantic’s 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. Except as stated below, the electricity for those sales within ISO New England was provided entirely under a Wholesale Power Sales Agreement (the “Agreement”) with Engage Energy America, LLC (Engage), which also expired on February 28, 2002. Under this Agreement, all revenues from both SOS and CES sales were paid directly to an Escrow Agent that disbursed funds in accordance with instructions from Engage. For SOS sales, EA received reimbursement for certain expenses and a portion of the net profit that was reported as SOS margin.
On May 24, 2001, the Maine Public Utilities Commission (MPUC) issued an Order authorizing a comprehensive settlement of the dispute between EA and Engage. In connection with the MPUC Order, EA, Engage, CMP, and other parties entered into a comprehensive settlement which included the following:
(i) Engage continued to supply EA with all energy required to perform outstanding retail contracts and the SOS commitments, until the expiration of the Agreement.
(ii) Engage and EA released one another from liabilities arising on or before May 24, 2001, with limited exceptions.
(iii) EA is no longer required to purchase power exclusively from Engage.
(iv) Before its expiration on February 28, 2002, the Wholesale Agreement could not be terminated by EA or Engage except upon the willful and material misconduct of the other party.
(v) The order waives the requirement that EA provide a performance bond. Frontier Insurance Company (Frontier) was released from liability under its bond and Frontier released EA and the Company from any and all claims for indemnification, subrogation or contribution under the bond and associated indemnification agreement.
(vi) Westcoast Energy, Inc., (Engage’s then current parent company) provided CMP a $33 million guarantee of Engage’s performance, and Coastal Corporation (a former affiliate of Engage) released from its prior guarantee of Engage’s performance.
(vii) Engage received $8 million over the remaining term of the Wholesale Power Agreement consisting of the following: $1 million received from Frontier; a $4.5 million offset from amounts Engage was otherwise obligated to pay to CMP for entitlements; a total of $1.0 million of payments from EA in monthly increments through March, 2002; and a $1.5 million payment from EA in April, 2002. Under the Order, CMP was allowed to recover the $4.5 million from ratepayers instead of from Engage.
In connection with this settlement, EA recognized a charge against second quarter 2001 earnings (after-tax) of approximately $1.08 million, or $.69 per share.
During a scheduled audit of the revenue and expenses accruing under the Agreement conducted by Engage’s auditors in August of 2001, a discrepancy was identified between the reconciliation of kilowatt-hours (KWH) settled by CMP with ISO New England and transferred by ISO New England to Engage, and the KWH revenues achieved by Engage and EA through customer billing derived from actual meter readings. The August 2001 audit noted that this discrepancy was negative in some months and positive in others during the preceding year. As a precautionary measure, on January 21, 2002, EA and Engage agreed to instruct the Escrow Agent to maintain $1.5 million in the escrow account until the completion of the scheduled final audit of the contract activity, the expiration of the Escrow Agreement, and the release of EA from further obligations pertaining to the Agreement. When final billing information for the month following the February 28, 2002 expiration of the SOS activity in CMP’s service territory was received, EA determined that SOS megawatt-hours (MWH) billed to residential and small commercial customers by CMP exceeded the MWH allocated to the SOS activity by ISO New England by approximately 152,000 MWH, or approximately 2% of the total load charged to the SOS over the two-year period. The associated $6.1 million represents additional cash and revenue distributed to and shared by EA and Engage, with EA’s share being $4.8 million. Management believes the difference in MWH was a result of the difference between estimated and actual line loss or the estimating process the utility and ISO New England uses to report the amount of energy transferred to individual energy providers. Management also believes the SOS customers were billed only for the energy delivered according to their meters as read by CMP. Through August 31, 2002, EA recognized revenues based on the MWH allocated to the SOS by ISO New England, thereby excluding the impact of the discrepancy. During the third quarter of 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. In addition to the SOS revenue adjustment, EA reversed $321,000 ($.12 per share) of expenses previously accrued for EA’s share of possible regulatory assessments under the Agreement with Engage. This assessment was imposed on Engage by FERC during the course of the Engage/EA Agreement. Engage has indicated that due to a change in regulation, FERC has notified Engage that it will not be making any further assessments in connection with this matter. A further adjustment in the fourth quarter reduced the settlement by approximately $105,000, after taxes, or $.07 per share. As a result, the total impact of the settlement increased earnings per share by $1.89.
EA has entered into a contract for 40% of the output of the Wheelabrator-Sherman (W-S) energy facility for the two years beginning March 1, 2002. The output from this take-or-pay contract amounts to approximately 55,000 MWH annually and is being used to provide electricity for additional CES sales within MPS’s service territory. This is EA’s first take-or-pay contract, which carries more counterparty risk than others entered into to date. To mitigate this risk, EA has entered into a contract with NB Power, whereby NB Power will buy W-S output in excess of load requirements in the Company’s service territory at a rate indexed to the price of 3% Sulphur Max No. 6 residential oil into New York Harbor, which is intended to reflect NB Power’s avoided cost, subject to a floor and ceiling. Currently, all output has been sold to CES customers, therefore limiting the risk that energy will be sold to NB Power. In addition, NB Power will sell electricity to EA when load exceeds W-S output at a fixed on and off-peak rate.
In addition, EA has 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 provides a contractual guarantee on behalf of EA in an aggregate amount of one million dollars ($1,000,000). This guarantee is 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 has agreed to waive this credit requirement in lieu of EA’s commitment to maintain a $1 million ($1,000,000) minimum bank account balance.
The following illustrates the type of EA’s risk exposure related to these contracts for supply and sales:
• Counterparty risk includes 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 the 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 occur (1) if energy is not available from W-S, 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 W-S, as contracted.
• Forecasting risk exposure includes possible inaccuracy in the estimation of energy supply requirements. One of EA’s suppliers requires a 24-month forecast of load for each commitment to a 1 MW block of energy. Although there is no penalty for not using all of the energy, EA is 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 W-S power to NB Power at a current market-indexed rate.
With the expiration of the SOS arrangement in CMP’s service territory, EA will be 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. The Company continues to review EA’s current and future business model, which may include a possible exit from the CES market in part or in whole, a refinement of its market area, and/or expansion into other product and service lines. 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 factors. EA will continue to serve existing contracts in Northern Maine until they expire by February 28, 2004. CES sales in Northern Maine were approximately $5 million in 2002. EA believes that, in addition to minimizing its risk profile, this action will substantially relieve any underlying concerns that may exist in connection with the issue of employee sharing and EA’s energy marketing activities within the Company’s service territory. On February 21, 2003 the Company 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 and expects a ruling on the application during calendar year 2003.
The Company has determined that EA’s activity and related energy contracts are considered non-trading in accordance with EITF 98-10, which was awarded by EITF 02-03.
The Company adopted Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Investments and Hedging Activities” on January 1, 2001. The Company has reviewed EA contracts and determined they are not derivative contracts as defined by SFAS No. 133.
4. SEGMENT INFORMATION
The Company’s reportable segments include the electric utility portion of the business, consisting of Maine Public Service Company (MPS) and Maine and New Brunswick Electrical Power Company, Limited, (Maine and New Brunswick), and the energy marketing portion of the business, consisting of Energy Atlantic. The accounting policies of the segments are the same as those described in Note 1, “Summary of Significant Accounting Policies.” The Company provides certain administrative support services to Energy Atlantic, which are billed to that entity at cost, based on a combination of direct charges and allocations. The Company is organized on the basis of products and services.
5. INVESTMENTS IN ASSOCIATED COMPANIES
The Company 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 Maine Electric Power Company (MEPCO), a jointly-owned electric transmission company. For additional information, see Note 13, “Commitments, Contingencies, and Regulatory Matters - Capacity Arrangements - Maine Yankee” regarding the closing and decommissioning of Maine Yankee.
Dividends received during 2002, 2001, and 2000 from Maine Yankee were $99,828, $206,000, and $470,000, respectively, and from MEPCO $7,249, $7,249, and $9,061, respectively. In 2002 and 2001, Maine Yankee completed a stock redemption of $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:
6. SHORT-TERM CREDIT ARRANGEMENTS
The Company 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. These agreements contain certain restrictive covenants including interest coverage tests and debt-to-equity ratios. As of December 31, 2002, the Company was in compliance with those covenants. The Company 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 the Company and each of the participating banks. The A Loans, at the Company’s option, bear interest equal to either the agent bank’s prime rate or LIBOR-based pricing. The Company also pays a quarterly commitment fee of .50% of the unused portion of the A Loans. The B Loans bear interest as arranged between the Company and the participating bank. As of December 31, 2002, an A Loan for $2.0 million and a B Loan for $800,000 were outstanding under the revolving credit arrangement at 2.875% and 3.02%, respectively. As of December 31, 2001, an A Loan for $2.8 million and a B Loan for $1.15 million were outstanding under the revolving credit arrangement at 3.3125% and 3.37%, respectively.
The unregulated subsidiary, Energy Atlantic, LLC (EA) has a revolving line of credit with a bank, for $1.2 million. In April of 2002, the line was extended until March 30, 2003. Interest is based on the bank’s prime lending rate. The line of credit sets forth two financial covenants. The first covenant requires EA to maintain a minimum net worth of $2.75 million. The second requires the ratio of (i) earnings before interest, taxes, depreciation and amortization less unfunded capital expenditures less cash taxes to (ii) interest expense plus current maturities of long-term debt. This ratio shall not be less than 1.25 times and is tested annually. As of December 31, 2002, EA was in compliance with these covenants set forth by the line of credit agreement. The line was not used during 2002 and had no balance outstanding as of December 31, 2002 or December 31, 2001.
7. COMMON SHAREHOLDERS’ EQUITY
On November 17, 1999, the Maine Public Utilities Commission (MPUC) authorized the repurchase of up to 500,000 shares of the Company’s Common Stock in order to maintain the Company’s capital structure at levels in accordance with the Stipulation approved by the MPUC on December 1, 1999. The Stipulation limits common equity to 51% of the capital structure for the determination of transmission and distribution rates. The shares will be repurchased through an open-market program. During 2000, the Company purchased 45,000 shares at a cost of $922,000.
Under the most restrictive provisions of the Company’s long-term debt indentures and short-term credit arrangements, retained earnings (plus dividends declared on Common Stock) available for the distribution of cash dividends on Common Stock were $40,503,066 at December 31, 2002.
8. LONG-TERM DEBT
The sale of the Company’s generating assets in 1999 significantly impacted long-term debt. Proceeds from the sale were deposited with the first mortgage trustee and subsequently withdrawn to redeem the remaining $2.5 million of 9.6% second mortgage bonds and $1.4 million of the variable rate 1996 Public Utility Refunding Revenue Bonds. On June 14, 2000, the Company redeemed the 9.775% first mortgage bonds in the amount of $15.0 million and paid a related premium on the retirement of $2.1 million.
On October 19, 2000, the Maine Public Utilities Financing Bank (MPUFB) issued $9 million of its tax-exempt bonds due October 1, 2025 (the 2000 Series) on behalf of the Company. The proceeds have been 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 and 2001, the proceeds in the trust account were $2.1 million and $5.7 million, respectively. Pursuant to the long-term note issued under a loan agreement between the Company and the MPUFB, the Company 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, the Company 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. To secure the Company’s obligations under the letter of credit and reimbursement agreement, the Company issued first and second mortgage bonds, in the amounts of $5 million and $4.525 million, respectively. The Company 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, the Company purchased an interest rate cap of 6% at a cost of $36,000, to expire November 2003, that applies to the 2000 and 1996 Series. At the end of 2002, the cumulative effective interest rate of the 2000 Series, including issuance costs and credit enhancement fees since issuance was 4.96%.
A similarly structured series of Bonds was issued on behalf of the Company by the MPUFB in 1996, 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 2002, the cumulative effective interest rate of the 1996 series, including issuance costs and credit enhancement fees was 5.14%.
On May 29, 1998, FAME issued $11,540,000 of its Taxable Electric Rate Stabilization Revenue Notes, Series 1998A (Maine Public Service Company) (the “Notes”) on behalf of the Company. 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 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 the Company and the Capital Reserve Fund held by the Trustee, which was approximately $2.4 million at the end of 2002 and 2001. The Company has issued $4 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. Since issuance, the average of these weekly rates is 4.52%. On June 1, 1998, the Company 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 2002, the cumulative effective interest rate, including issuance costs and credit enhancement fees, since issuance for this Series was 5.57%.
The MPUFB tax-exempt issues are subject to the same restrictive covenants consistent with those discussed for the Company’s revolving credit arrangement in Note 6.
9. STOCK COMPENSATION PLAN
Upon approval by the Company’s shareholders in June of 2002, the Company adopted the 2002 Stock Option Plan (the Plan). 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, who are not employees of the Company or any 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 (SFAS) No. 123, “Accounting for Stock-Based Compensation.” The effect of the grants on compensation expense for the year ended December 31, 2002 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 4.9 percent; expected volatility of 20 percent, risk-free interest rate of 3.33%; and expected lives of 7 years.
A summary of the status of the Company’s stock option plan as of December 31, 2002, and changes during the year then ended is presented below:
The following table summarizes information about fixed stock options outstanding at December 31, 2002:
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 a tax-deductible contribution of $276,570 for the 2002 plan year in January, 2003. No contribution was necessary for the 2001 and 2000 plan years.
Health Care Benefits
In addition to providing pension benefits, the Company provides certain health care benefits to eligible employees and retirees. All employees share in the cost of their medical benefits, in addition to plan deductibles and coinsurance payments, totaling approximately 11.26% in 2002. 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 Maine Public Utilities Commission (MPUC) accounting orders, the Company established a regulatory asset of approximately $1,061,000, representing deferred postretirement 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) subaccount of the Pension Trust for non-union retiree medical payments on September 14, 2000. On December 28, 1999 and December 27, 2001, and 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 postretirement health care costs at such time as customers are paying for these costs in their rates. For purposes of determining the accrued postretirement benefit cost as of December 31, 2002 the health care cost trend rate used was 9% in 2003 and graded down to 4.0% in 2012, 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:
The following table sets forth the plans’ change in benefit obligation, change in plan assets, funded status and assumptions as of December 31, 2002 and 2001:
The following table sets forth the plans’ net periodic benefit cost for 2002, 2001, and 2000:
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.
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, an increase from 1% effective January 1, 2001. Participants are 100% vested at all times in contributions made on their behalf. The Company’s matching contributions to the plan were approximately $117,000, $114,000, and $59,000, in 2002, 2001, and 2000, respectively.
11. SFAS No. 133
The Company has adopted Statement of Financial Accounting Standards No. 133 (SFAS No. 133), “Accounting for Derivative Instruments and Hedging Activities” effective January 1, 2001. The Company has reviewed its business activities and determined that interest rate caps on the three variable rate long-term debt issues qualify as derivatives in accordance with SFAS 133. On June 1, 1998, the Company 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 the Company. On November 20, 2000, the Company purchased an interest cap of 6% at a cost of $36,000 to expire November 2003 that applies to the 2000 and 1996 Series of Maine Public Utilities Financing Bank’s (MPUFB) bonds issued on behalf of the Company with outstanding balances of $9.0 million and $13.6 million, respectively. The Company recorded the cost of the caps as regulatory assets and is amortizing them over their useful lives. SFAS 133 requires companies to
record derivatives on their balance sheet at fair value, with the related changes in fair value recorded as either income/expense or as a component of other comprehensive income, depending on the intended use of the derivative. For regulated entities, the amount the fair value is below the carrying value is recorded as a regulatory asset to the extent the difference is recoverable in the rate base of the Company. The Company has adopted a policy under regulatory accounting that requires any gain on the sale of these regulatory assets to be recorded as regulatory liabilities and returned to rate payers. The issuers of the caps related to the Company’s FAME and MPUFB debt have estimated their fair values as of December 31, 2002 to be $41,590. The corresponding unamortized regulatory assets as of December 31, 2002 are $103,271.
12. 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, 2002, the Company’s long term debt had a carrying value and a fair value of approximately $33.8 million.
13. COMMITMENTS, CONTINGENCIES, AND REGULATORY MATTERS
Industry Restructuring
On May 29, 1997, legislation titled “An Act to Restructure the State’s Electric Industry” was signed into law by the Governor of Maine. The principal provisions with accounting impact on the Company are as follows:
1. Beginning on March 1, 2000, all consumers of electricity have the right to purchase generation services directly from competitive electricity suppliers who will not be subject to rate regulation.
2. By March 1, 2000, the Company, Central Maine Power Company (CMP), and Bangor Hydro-Electric Company (BHE) must divest themselves of all generation related assets and business functions except for:
a) contracts with qualifying facilities, such as the Company’s power contract with Wheelabrator-Sherman (W-S), and conservation providers;
b) nuclear assets, namely, the Company’s investment in the Maine Yankee Atomic Power Company;
c) facilities located outside the United States, i.e., the Company’s hydro facility in New Brunswick, Canada; and
d) assets that the MPUC determines necessary for the operation of the transmission and distribution services. The MPUC can grant an extension of the divestiture deadline if the extension will improve the selling price. For assets not divested, the utilities are required to sell the rights to the energy and capacity from these assets. For more information about the Company’s sale of its generating assets, see “Capacity Arrangements - Generating Asset Sale,” below.
3. The Company will continue to provide transmission and distribution services which will be subject to continued rate regulation by the MPUC.
4. Maine electric utilities will be permitted a reasonable opportunity to recover legitimate, verifiable and unmitigable costs that are otherwise unrecoverable as a result of retail competition in the electric utility industry (so-called “stranded costs”). The MPUC shall determine these stranded costs by considering:
a) the utility’s regulatory assets related to generation, i.e., the Company’s unrecovered Seabrook investment;
b) the difference between net plant investment in generation assets compared to the market value for those assets; and
c) the difference between future contract payments and the market value of the purchased power contracts, i.e., the W-S contract.
5. The MPUC shall include in the rates to be charged by the transmission and distribution utility decommissioning expenses for Maine Yankee. In 2003, and every three years thereafter until the stranded costs are recovered, the MPUC shall review and adjust the stranded cost recovery amounts and related transition charges. However, the MPUC may adjust the amounts at any point in time that they deem appropriate. Since the legislation provides for our recovery of stranded costs by the transmission and distribution company, the Company will continue to recognize existing regulatory assets and plant costs as provided by Emerging Issues Task Force 97-4, “Deregulation of the Pricing of Electricity” (EITF 97-4).
6. Billing and metering services will be subject to competition beginning March 1, 2002, but permits the MPUC to establish an earlier date, no sooner than March 1, 2000. The implementation of this provision was subsequently delayed, and the Company cannot predict when or if it will begin.
7. All competitive providers of retail electricity must be licensed and registered with the MPUC and meet certain financial standards, comply with customer notification requirements, adhere to customer solicitation requirements and are subject to unfair trade practice laws. Competitive electricity providers must have at least 30% renewable resources in their energy portfolios, including hydro-electric generation.
8. A standard offer service will be available, ensuring access for all customers to reasonably priced electric power. Unregulated affiliates of CMP and BHE providing retail electric power are prohibited from providing more than 20% of the load within their respective service territories under the standard offer service, while any unregulated affiliate of the Company does not have a similar restriction.
9. Employees other than officers, displaced as a result of retail competition, will be entitled to certain severance benefits and retraining programs. These costs will be recovered through charges collected by the regulated transmission and distribution company.
The Company believes that its 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, 2002, $67.2 million of regulatory assets remain on the Company’s books. These assets will be amortized over various periods in accordance with the MPUC approved Phase II filing.
For further discussion of the specific impacts of the industry restructuring on the Company and related ratemaking activity, see “MPUC Approves Stranded Cost Revenue Requirements Effective March 1, 2002” and “MPUC Approves Elements of Rates Effective March 1, 2000,” below.
MPUC Approves Stranded Cost Revenue Requirements Effective March 1, 2002
On May 8, 2001, the MPUC issued a notice of investigation to determine whether the Company’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, the Company 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 the Company’s share is $1,005,000. As of December 31, 2001, the Company 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 the Company’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.
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, the Company notified the MPUC of its intention to implement the associated transmission component of its retail transmission and distribution (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%. The Company has increased its transmission rates subject to refund and issuance of a final order by FERC. Although the Company expects FERC’s final order to support the rate increase without any further adjustments, it cannot predict the final outcome of this proceeding.
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, the Company filed its determination of stranded costs, transmission and distribution costs, and rate design with the MPUC. The Company’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 Wheelabrator-Sherman, the obligation for remaining operating expenses and recovery of the Company’s remaining investment in Maine Yankee, and the recovery of several other regulatory assets.
On October 15, 1999, the Company filed with the MPUC a Stipulation resolving the revenue requirement and rate design issues for the Company’s transmission and distribution (T&D) utility. This Stipulation was signed by the Public Advocate and approval was recommended by the MPUC Staff. Under the Stipulation, the Company’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 the Company’s generating assets, but did set forth some general principles concerning the Company’s ultimate stranded costs recovery, including agreement that the major components of the Company’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 the Company’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 unrecovered 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 the Company to offset its unrecovered 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, the Company was granted several accounting orders incorporating certain accounting methodologies used in determining the elements of stranded costs. On August 4, 2000, the MPUC authorized the Company 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. See “MPUC Approves Stranded Cost Revenue Requirements Effective March 1, 2002,” above, for additional information.
Alternative Rate Plan Filing
On March 6, 2003, following a series of informal meetings with the Office of Public Advocate and the MPUC, the Company submitted its formal “Request for Approval of Alternate Rate Plan” (MPUC Docket 2003-85). The proposal (ARP) is a seven-year rate plan for its distribution delivery services with 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. The ARP has numerous components, all of which have been designed to fit together as an integrated whole that will allow the Company to continue to meet the unique needs of its Northern Maine customers. Its key components include: an inflation index and productivity offset; an adjustment for the treatment of extraordinary costs the Company may incur; an interest expense adjustment; an economic conditions adjustment; a shareholder earnings sharing mechanism; pricing flexibility; reliability, safety and service quality indices; and a sharing mechanism for non-core revenues. The Company believes that the ARP will benefit customers by: (1) ensuring that customer’s electric service does not suffer under the plan through the use of the above-described mechanisms; (2) providing predictable and stable rates; (3) providing an acceptable risk sharing environment; and (3) encouraging the Company to minimize its costs wherever possible. At this time the Company cannot predict the nature or the outcome of any decision or ruling by the MPUC in this proceeding.
Seabrook Nuclear Power Project
In 1986, the Company 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 the Company’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, 2002 and 2001 are as follows:
In March 2000, the Company 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 the Company’s 5% equity ownership in Maine Yankee (see Note 5, “Investments in Associated Companies”), the Company’s share of any retrospective premium would not exceed approximately $2.9 million or $.5 million annually, without considering inflation indexing.
Capacity Arrangements
Generating Asset Sale
On July 7, 1998, the Company and WPS Power Development, Inc., (WPS-PDI) signed a purchase and sale agreement for the Company’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, the Company completed the sale to WPS-PDI for $37.4 million. The Company’s 5% ownership in Maine Yankee was not part of the sale, since the plant is being decommissioned. After paying Canadian, Federal and State income taxes, the remaining proceeds, along with interest in the trust account, were used to reduce the Company’s debt. The gain from the sale is currently deferred, and is being recognized according to the MPUC’s decision on the Company’s determination of stranded costs, transmission and distribution costs, and rate design. The components of the deferred gain are 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 the Company. The proceeds increased the deferred gain and further reduced stranded costs.
With the sale of the Company’s generating assets in June, 1999, the Company 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, the Company has entered into two indemnity obligations with the purchaser, WPS-PDI. First, the Company 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, the Company 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
The Company 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 the Company’s 5% share would be approximately $46.5 million. In December 1998, June 1999, September 2000, February 2001, December 2001, March 2002, May 2002, and again in September, 2002, Maine Yankee updated its estimate of decommissioning costs based on the Settlement. Legislation enacted in Maine in 1997 calls for restructuring the electric utility industry and provides 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, the Company believes that it is entitled to recover substantially all of its share of such costs from its customers and, as of December 31, 2002 is carrying on its consolidated balance sheet a regulatory asset and a corresponding liability in the amount of $22.15 million, which reflects the Company’s 5% share of Maine Yankee’s September 2002 revised estimate of the remaining decommissioning costs less actual decommissioning payments made since then.
The MPUC, on January 27, 2002, approved a Stipulation providing for the recovery of stranded investment, for a two-year period March 1, 2002 until February 29, 2004, which includes the Company’s share of Maine Yankee decommissioning expenses, Maine Yankee replacement power costs, and the remaining Maine Yankee investment. As of December 31, 2002, deferred fuel of $13.1 million is reflected as a regulatory asset, which includes the Maine Yankee replacement power costs, as well as deferred Wheelabrator-Sherman fuel costs. Additionally, the Company has deferred $22.2 million related to uncollected Maine Yankee decommissioning costs.
In May 2000, Maine Yankee terminated its decommissioning operations contract with Stone & Webster Engineering Corporation
(Stone & Webster) pursuant to 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.
Upon the contract termination, Maine Yankee temporarily assumed the general contractor role and entered into interim agreements with Stone & Webster and obtained assignments of several subcontracts in order to allow decommissioning work to continue and to avoid the adverse consequences of an abrupt or inefficient demobilization from the Plant site. Decommissioning of the Plant site continued with major emphasis directed to maintaining the schedule on critical-path projects such as construction of an independent spent fuel storage installation (ISFSI) and preparation of the Plant’s reactor vessel for eventual shipment to an off-site disposal facility. After assessing its long-term alternatives for safely and efficiently completing the decommissioning, including evaluating proposals from prospective successor general contractors, on January 26, 2001, Maine Yankee announced that it would continue to manage the project itself.
In June 2000, Federal Insurance Company (Federal), which had provided performance and payment bonds in the amount of approximately $38.5 million each in connection with the decommissioning operations contract, filed a declaratory-judgment complaint against Maine Yankee in the Bankruptcy Court in Delaware, which was subsequently transferred to the United States District Court in Maine.
The complaint alleged that Maine Yankee had improperly terminated the decommissioning operations contract with Stone & Webster and had failed to give proper notice of the termination to Federal under the contract, and that Federal had no further obligations under the bonds.
After extensive discovery and resolution of certain preliminary issues by the court, in December 2001 Maine Yankee and Federal entered into a settlement agreement pursuant to which Federal paid Maine Yankee $44 million on January 18, 2002. The settlement was reflected on Maine Yankee’s 2001 financial statements. That amount represents full payment under the performance bond, plus an additional amount under the 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.
Maine Yankee has continued to pursue its claim for damages that was originally filed against Stone & Webster and its parent corporations in August 2000 in the Bankruptcy Court in Delaware. After recognizing the payment from Federal, Maine Yankee has asserted a right to recover an additional $21 million in that court from the bankruptcy estates. In February 2002, Stone & Webster filed a claim for approximately $7 million against Maine Yankee in the Bankruptcy Court in Delaware for alleged breaches of contract and to subordinate any Maine Yankee’s claims. On May 30, 2002, the court concluded extensive hearings and argument by allowing a claim in favor of Maine Yankee under section 502 (c) of the Bankruptcy Code, in the estimated amount of $20.8 million against each of the three principal estates (jointly and severally). The Court’s ruling also effectively precluded approximately $4 million of Stone & Webster’s February 2002 claim against Maine Yankee, while offering no opinion or findings on the remainder, the resolution of which will, if necessary, be the subject of further motions and proceedings. The actual cash amount to be recovered by Maine Yankee on this allowed claim remains contingent on a number of factors beyond Maine Yankee’s control, including without limitation the extent to which the bankruptcy estates ultimately have assets available to pay the claim, the ultimate disposition of Stone & Webster’s February 2002 claim, possible reconsideration of the ruling in the future based on actual expenses of completing the decommissioning, and the effect, if any, of any appeal of the May 30 decision by the bankruptcy estates. Maine Yankee therefore cannot predict the final outcome of the Bankruptcy Court proceeding.
Federal legislation enacted in 1987 directed the 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 the Congress. As provided in the statutory procedure, the State of Nevada formally objected to the site in April 2002 and in July 2002 the Congress overrode the objection. Construction of the repository requires the approval of the NRC, upon application of the DOE and after a public adjudicatory hearing as well as 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 associate 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. 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 independent spent fuel storage installation (ISFSI), utilizing dry-cask storage,
on the Plant site and is in 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 had indicated that it disputes Maine Yankee’s basis for terminating the contract and has served Maine Yankee with a demand to arbitrate the dispute, while at the same time the parties have been in negotiations to resolve the situation. In the meantime, Maine Yankee has entered into contracts with the major subcontractors and resumed the transfer of fuel to the ISFSI under its own management Maine Yankee believes that its termination of the NAC contract was legally justified, but cannot predict the outcome of the negotiations or arbitration proceeding.
On February 28, 2003, the Nuclear Regulatory Commission approved Maine Yankee’s License Termination Plan. The LTP was approved without any unexpected conditions.
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.
MEPCO
The Company 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
The Company was ordered into a Power Purchase Agreement (PPA) with Wheelabrator-Sherman (W-S) 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 W-S 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 $13.1 million and $12.1 million at December 31, 2002 and 2001, respectively.
The Company and W-S 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 W-S after March 1, 2000 are reflected as stranded costs.
The Company estimates its remaining commitment to purchase power under this contract to be $47.2 million from January 1, 2003 through 2006. The Company has entered a contract whereby WPS-PDI takes delivery of the power through February 28, 2002 at market prices, and beginning March 1, 2002, Energy Atlantic, the Company’s wholly-owned marketing subsidiary, will be taking delivery of 40% of W-S’s output and WPS-PDI will take the remainder. The Company estimates that the remaining stranded costs will be $30.0 million through 2006, assuming arrangements similar to the one with WPS-PDI and EA will be in place for that period.
WPS Complaint
On October 30, 2000, WPS Energy Services (WPS), a Competitive Electricity Provider (CEP) offering retail sales of electricity in the Company’s service territory, filed a Complaint (Docket No. 00-894) against the Company, as well as a Petition to Alter or Amend the MPUC’s September 2, 1998 Order in Docket No. 98-138.
The Complaint alleged that the Company violated various provisions of Chapter 304 of the MPUC’s Regulations governing relations between the Company and all CEPs, including the Company’s own marketing subsidiary, Energy Atlantic, LLC (EA). According to the Complaint, various of the Company’s employees engaged in conduct that either awards EA a competitive advantage over other CEPs or burdened WPS with an unfair disadvantage relative to EA. These allegations included such practices as denying WPS information made available to EA, or providing EA with information about WPS’s customers that is not available publicly. The Company did not believe it in any way violated any provisions of Chapter 304 and so argued to the MPUC.
In its September 2, 1998 Order in Docket No. 98-138 authorizing the formation of EA, the Commission allowed the Company and EA to share the services of certain employees under certain conditions on the grounds that such sharing was in the public interest and would not have any anti-competitive effect on the retail market for electricity. WPS claims that the sharing does not conform to the conditions set forth in the Order and that, in any event, the Commission should now find such sharing not in the public interest, thereby amending its original September 2, 1998 Order.
The Complaint and Petition to Amend the September 2, 1998 Order, in addition to requesting a prohibition on the sharing of certain employees, particularly Maine Public Service Company’s General Counsel, also seeks a formal investigation of the Complaint, penalties for any violations of the Commission’s rules and certain specific relief for violations of Chapter 304.
In its response, the Company strongly denied the allegations in the WPS Complaint and asked the Commission to dismiss the Complaint and for Summary Judgment in its favor.
On May 1, 2001, the Commission issued its Order in this matter, finding that some counts in the WPS Complaint should be dismissed but that others raised factual issues that could be resolved only through a more formal hearing process. The Commission declined, however, to take initial jurisdiction over the Complaint. Instead, the Commission ordered the parties to submit their dispute to the informal dispute resolution process set forth in MPS’s Chapter 304 Implementation Plan. Under this Plan, the dispute must be submitted to an independent law firm which must issue its decision within 30 days. Only if the matter is not resolved to both parties’ satisfaction would the Commission then take jurisdiction over the dispute. The Commission also stated that it would open an investigation into the issues of whether MPS’s General Counsel’s dual role with MPS and EA is inherently problematic and the standards that should govern any MPS employees who also provide services to EA.
The parties submitted the dispute to an independent arbitrator who issued his proposed findings on June 29, 2001. The arbitrator found that MPS did not violate any provisions of Chapter 304, except for the Company’s unintentional failure to identify WPS as a Standard Offer Service provider on its March and April 2000 bills to customers. The arbitrator recommended that MPS refund to WPS its billing fees for these two months, approximately $18,000. On July 5, 2001, the Company and WPS informed the Commission of their acceptance of the arbitrator’s findings. As a result, the Commission, in its July 13, 2001 Order, stated that it would not be necessary for it to further address the allegations in the WPS complaint, even though it would continue its investigation into the sharing of employee services.
On March 6, 2002, the Company, WPS and the Public Advocate filed with the MPUC a Stipulation resolving all remaining issues in the investigation. The Stipulation contained several provisions that clarified the extent to which the Company’s senior management could become involved in the affairs of EA and included restrictions and requirements governing the direct contact between the Company’s senior management and EA personnel for all but one designated executive. The Stipulation also specifically prohibited one employee, (the “designated executive”) from being involved in certain types of Company activities, knowledge of which could gain EA a competitive advantage in the retail market. Finally, the Stipulation gave the MPUC the right to conduct an annual audit to determine whether EA and the Company are complying with Chapter 304. The costs of this audit, up to $10,000, shall be paid for by the Company. This Stipulation was approved by the MPUC in an Order dated April 29, 2002. On February 24, 2003, EA announced its intent to withdraw from the Northern Maine market due to the lack of profitability in that market. EA will continue to serve its existing contracts in Northern Maine until they expire through February 28, 2004. EA believes that this action substantially relieves the underlying concerns that gave rise to the WPS Complaint, particularly regarding the sharing of employees in connection with EA’s energy marketing within the Company’s service territory. On February 21, 2003 the Company filed with the MPUC an “Application for Exemption of Chapter 304” and expects a ruling on the application during calendar year 2003.
Construction Program
Expenditures on additions, replacements and equipment for the years ended December 31, 2002, 2001, and 2000, along with 2003 estimated expenditures, are as follows:
14. GUARANTOR ARRANGEMENTS
In November 2002, the FASB issued FIN No. 45 (FIN 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 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.
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, 2002.
15. QUARTERLY INFORMATION (unaudited)
Quarterly financial data for the two years ended December 31, 2002 is as follows:
(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 E-1 to E-7.
The MPUC Order approving the Reorganization of the Company into a Holding Company Structure, Docket No. 02-676, (Exhibit 99(an) of the Company’s 2002 Form 10-K) is also included on Pages O-1 to O-21.
(b) A Form 8-K was filed on:
• October 18, 2002, covering the board authorization for reorganization described under Item 5, Other Events.
• January 23, 2003, covering 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.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized, on the 28th of March, 2003.
MAINE PUBLIC SERVICE COMPANY
By:
/s/ Michael A. Thibodeau
Michael A. Thibodeau
Vice President, Controller and Chief Risk Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the date indicated.
Schedule II
Maine Public Service Company & Subsidiary
Valuation of Qualifying Accounts & Reserves
For the Years Ended December 31, 2002, 2001 and 2000
CERTIFICATIONS
I, J. Nicholas Bayne, certify that:
1. I have reviewed this annual report on Form 10-K of Maine Public Service Company (the registrant);
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c) presented in this annual report conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of the registrant’s board of directors:
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have significant role in the registrant’s internal controls; and
6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
I, Larry E. LaPlante, certify that:
1. I have reviewed this annual report on Form 10-K of Maine Public Service Company (the registrant);
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
c) presented in this annual report conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of the registrant’s board of directors:
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have significant role in the registrant’s internal controls; and
6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
INDEX TO EXHIBITS
Certain of the following exhibits are filed herewith. Certain other of the following exhibits have heretofore been filed with the Commission and are incorporated herein by reference. (* indicates filed herewith)
3(a)
Restated Articles of Incorporation with all amendments through May 8, 1990. (Exhibit 3(a) to 1990 Form 10-K)
3(b)
By-laws of the Company, as amended through May 12, 1987. (Exhibit 3(b) to 1987 Form 10-K)
4(a)
Indenture of Mortgage and Deed of Trust defining the rights of the holders of the Company’s First Mortgage Bonds. (Exhibit 4(a) to 1980 Form 10-K)
4(b)
First Supplemental Indenture. (Exhibit 4(b) to 1980 Form 10-K)
4(c)
Second Supplemental Indenture. (Exhibit 4(c) to 1980 Form 10-K)
4(d)
Third Supplemental Indenture. (Exhibit 4(d) to 1980 Form 10-K)
4(e)
Fourth Supplemental Indenture. (Exhibit 4(e) to 1980 Form 10-K)
4(f)
Fifth Supplemental Indenture. (Exhibit A to Form 8-K dated May 10, 1968)
4(g)
Sixth Supplemental Indenture. (Exhibit A to Form 8-K dated April 10, 1973)
4(h)
Seventh Supplemental Indenture. (Exhibit A to Form 8-K dated November 7, 1975)
4(i)
Eighth Supplemental Indenture. (Exhibit 4(i) to 1980 Form 10-K)
4(j)
Ninth Supplemental Indenture. (Exhibit B to Form 10-Q for the second quarter of 1978)
4(k)
Tenth Supplemental Indenture. (Exhibit 4(k) to 1980 Form 10-K)
4(l)
Eleventh Supplemental Indenture. (Exhibit 4(l) to 1982 Form 10-K)
4(m)
Indenture defining the rights of the holders of the Company’s 9 7/8% debentures. (Exhibit A to Form 8-K, dated June 10, 1970)
4(n)
Indenture defining the rights of the holders of the Company’s 14% debentures. (Exhibit 4(n) to 1982 Form 10-K)
4(o)
Twelfth Supplemental Indenture. (Exhibit 4(o) to Form 10-Q for the quarter ended September 30, 1984)
4(p)
Thirteenth Supplemental Indenture. (Exhibit 4(p) to Form 10-Q for the quarter ended September 30, 1984)
4(q)
Fourteenth Supplemental Indenture, Dated July 1, 1985. (Exhibit 4(q) to 1985 Form 10-K)
4(r)
Fifteenth Supplemental Indenture, Dated March 1, 1986. (Exhibit 4(r) to 1985 Form 10-K)
4(s)
Sixteenth Supplemental Indenture, Dated September 1, 1991. (Exhibit 4(s) to the Company’s 1991 Form 10-K)
4(t)
Seventeenth Supplemental Indenture, Dated April 1, 1997. (Exhibit 4(t) to the Company’s 1998 Form 10-K)
E-1
4(u)
Eighteenth Supplemental Indenture, Dated April 1, 1998. (Exhibit 4(u) to the Company’s 1998 Form 10-K)
4(v)
Nineteenth Supplemental Indenture, Dated May 1, 1998. (Exhibit 4(v) to the Company’s 1998 Form 10-K)
4(w)
Twentieth Supplemental Indenture, Dated October 1, 2000. (Exhibit 4(w) to the Company’s 2000 Form 10-K)
Not applicable.
10(a)(1)
Joint Ownership Agreement with Public Service of New Hampshire in respect to construction of two nuclear generating units designated as Seabrook Units 1 and 2, together with related amendments to date. (Exhibit 10 to the Company’s 1980 Form 10-K)
10(a)(2)
Twentieth Amendment to Joint Ownership Agreement. (Exhibit 10(a)(6) to the Company’s 1986 Form 10-K)
10(a)(3)
Twenty-Second Amendment to Joint Ownership Agreement. (Exhibit 10(a)(3) to the 1988 Form 10-K)
10(b)(1)
Capital Funds Agreement, dated as of May 20, 1968 between Maine Yankee Atomic Power Company and the Company. (Exhibit 10(b)(1) to Form 10-Q for the quarter ended March 31, 1983)
10(b)(2)
Power Contract, dated as of May 20, 1968 between Maine Yankee Atomic Power Company and the Company. (Exhibit 10(b)(2) to Form 10-Q for the quarter ended March 31, 1983)
10(c)(1)
Participation Agreement, as of June 20, 1969, with Maine Electric Power Company, Inc. (Exhibit 10(c)(1) to Form 10-Q for the quarter ended March 31, 1983)
10(c)(2)
Agreement, as of June 20, 1969, among the Company and the other Maine Participants. (Exhibit 10(c)(2) to Form 10-Q for quarter ended March 31, 1983)
10(c)(3)
Power Purchase and Transmission Agreement Supplement to Participation Agreement, dated as of August 1, 1969, with Maine Electric Power Company, Inc. (Exhibit 10(c)(3) to Form 10-Q for quarter ended March 31, 1983)
10(c)(4)
Supplement Amending Participation Agreement, as of June 24, 1970, with Maine Electric Power Company, Inc. (Exhibit 10(c)(4) to Form 10-Q for quarter ended March 31, 1983)
10(c)(5)
Second Supplement to Participation Agreement, dated as of December 1, 1971, including as Exhibit A the Unit Participation Agreement dated November 15, 1971, as amended, between Maine Electric Power Company, Inc. and the New Brunswick Electric Power Commission. (Exhibit 10(c)(5) to Form 10-Q for quarter ended March 31, 1983)
10(c)(6)
Agreement and Assignment, as of August 1, 1977, by Connecticut Light & Power Company, Hartford Electric Company, Holyoke Water Power Company, Holyoke Power Company, Western Massachusetts Electric Company and the Company. (Exhibit 10(c)(6) to Form 10-Q for the quarter ended March 31, 1983)
10(c)(7)
Amendment dated November 30, 1980 to Agreement and Assignment as of August 1, 1977, between Connecticut Light & Power Company, Hartford Electric Company, Holyoke Water Power Company, Holyoke Power Company, Western Massachusetts Electric Company and the Company. (Exhibit 10(c)(7) to Form 10-Q for the quarter ended March 31, 1983)
E-2
10(c)(8)
Assignment Agreement as of January 1, 1981, between Central Maine Power Company and the Company. (Exhibit 10(c)(8) to Form 10-Q for the quarter ended March 31, 1983)
10(d)
Wyman Unit #4 Agreement for Joint Ownership as of November 1, 1974, with Amendments 1, 2, and 3, dated as of June 30, 1975, August 16, 1976, December 31, 1978, respectively. (Exhibit 10(d) to Form 10-Q for the quarter ended March 31, 1983)
10(e)
Agreement between Sherman Power Company and Maine Public Service Company, dated June 4, 1984, with amendments dated July 12, 1984 and February 14, 1985. (Exhibit 10(f) to 1984 Form 10-K)
10(f)
Credit Agreement, dated as of October 8, 1987 among the Registrant and The Bank of New York, Bank of New England, N.A., The Merrill Trust Company and The Bank of New York, as agent for the Participating Banks. (Exhibit 10(g) to Form 8-K dated October 13, 1987)
10(g)
Amendment No. 1, dated as of October 8, 1989, to the Revolving Credit Agreement, dated as of October 8, 1987, among the Registrant and The Bank of New York, Bank of New England, N.A., Fleet Bank (formerly the Merrill Trust Company) and The Bank of New York as agent for the participating banks. (Exhibit 10(l) to Form 8-K dated September 22, 1989)
10(h)
Amendment No. 2, dated as of June 5, 1992, to the Revolving Credit Agreement, among the Registrant and The Bank of New York, Bank of New England, N.A., Shawmut Bank and the Bank of New York, as agent for the participating banks. (Exhibit 10(h) to the Company’s 1992 Form 10-K)
10(i)
Indenture of Second Mortgage and Deed of Trust, dated as of October 1, 1985, made by the Registrant to J. Henry Schroder Bank and Trust Company, as Trustee. (Exhibit 10(i) to Form 8-K dated November 1, 1985)
10(j)
First Supplemental Indenture of the Second Mortgage and Deed of Trust Dated March 1, 1991. (Exhibit 10(i) to the Company’s 1991 Form 10-K)
10(k)
Second Supplemental Indenture of the Second Mortgage and Deed of Trust Dated September 1, 1991. Exhibit 10(j) to the Company’s 1991 Form 10-K)
10(l)
Agency Agreement dated as of October 1, 1985, between J. Henry Schroder Bank and Trust Company, as Trustee under the Indenture of Second Mortgage and Deed of Trust dated as of October 1, 1985, made by the Registrant to J. Henry Schroder Bank and Trust Company, as Trustee, and Continental Illinois National Bank and Trust Company, as Trustee, under an Indenture of Mortgage and Deed of Trust, dated as of October 1, 1945, as amended and supplemented, made by the Registrant to Continental Illinois National Bank and Trust Company, as Trustee. (Exhibit 10(j) to Form 8-K dated November 1, 1985)
10(m)
Employment Contract between Frederick C. Bustard and Maine Public Service Company dated August 22, 1989. (Exhibit 10(h) to 1989 Form 10-K)
10(n)
Employment Contract between Paul R. Cariani and Maine Public Service Company dated November 5, 1999. (Exhibit 10(n) to 1999 Form 10-K)
10(o)
Employment Contract between Stephen A. Johnson and Maine Public Service Company dated November 5, 1999. (Exhibit 10(o) to 1999 Form 10-K)
10(p)
Employment Contract between Larry E. LaPlante and Maine Public Service Company, dated November 5, 1999. (Exhibit 10(p) to 1999 Form 10-K)
10(q)
Employment Contract between William L. Cyr and Maine Public Service Company, dated November 5, 1999. (Exhibit 10(q) to 1999 Form 10-K)
E-3
10(r)
Employment Contract between Michael A. Thibodeau and Maine Public Service Company, dated December 11, 2000. (Exhibit 10(r) to the Company’s 2000 Form 10-K)
10(s)
Maine Public Service Company, Prior Service Executive Retirement Plan, dated May 12, 1992. (Exhibit 10(s) to 1992 Form 10-K)
10(t)
Maine Public Service Company Pension Plan. (Exhibit 10(t) to 1992 Form 10-K)
10(u)
Maine Public Service Company Retirement Savings Plan. (Exhibit 10(u) to 1992 Form 10-K)
10(v)
Third Supplemental Indenture of the Second Mortgage and Deed of Trust Dated as of June 1, 1996. (Exhibit 10(t) to 1996 Form 10-K)
10(w)
Amendment No. 3, dated as of October 8, 1995, to the Revolving Credit Agreement, dated as of October 7, 1987, among the Registrant and The Bank of New York, Shawmut Bank of Boston, Fleet Bank of Maine, and The Bank of New York, an agent for the participating Banks. (Exhibit 10(u) to 1996 Form 10-K)
10(x)
Fourth Supplemental Indenture of the Second Mortgage and Deed of Trust dated May 1, 1998. (Exhibit 10(v) to the Company’s 1998 Form 10-K)
10(y)
Fifth Supplemental Indenture of the Second Mortgage and Deed of Trust dated October 1, 2000.(Exhibit 10(y) to the Company’s 2000 Form 10-K)
10(z)
Agreement between WPS Power Development, Inc., and Maine Public Service Company, dated July 7, 1998. (Exhibit 10(w) to the Company’s 1998 Form 10-K)
10(aa)
Agreement between Wheelabrator-Sherman Energy Company and Maine Public Service Company, dated October 15, 1997, with amendments dated January 30, 1998 and April 28, 1998. (Exhibit 10(x) to the Company’s 1998 Form 10-K)
10(ab)
Agreement between Loring Development Authority of Maine and Maine Public Service Company, dated July 9, 1998. (Exhibit 10(y) to the Company’s 1998 Form 10-K)
10(ac)
Wholesale Power Sales Agreement between Energy Atlantic, LLC and Engage Energy US, L.P., dated December 9, 1999, with amendments dated March 10, 2000 and August 1, 2000 and addendums dated December 14, 1999 and December 1, 2000. (Exhibit 10(ac) to the Company’s 2000 Form 10-K)
10(ad)
Fourth Amendment to Wholesale Power Agreement between Energy Atlantic, LLC and Engage Energy US, L.P., dated June 26, 2001. (Exhibit 99.2 to the Company’s May 24, 2001 Form 8-K)
10(ae)
General Release Agreements between Engage Energy America, LLC, Energy Atlantic, LLC (EA), Maine Public Service Co., Central Maine Power Company (CMP) and Frontier Insurance Company (Frontier) for any and all claims under or in connection with any Bonds issued by Frontier in connection with EA’s provision of the Standard Offer Service in the service territory of CMP in Maine, both dated May 24, 2001. (Exhibit 10(ae) to the Company’s 2001 Form 10-K)
10(af)
Master Power Purchase & Sale Agreement between Energy Atlantic, LLC and Duke Energy Trading and Marketing, LLC dated September 19, 2001. (Exhibit 10(af) to the Company’s 2001 Form 10-K)
10(ag)
Sixth Supplemental Indenture of the Second Mortgage and Deed of Trust dated June 1, 2002. (Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended June 30, 2002).
10(ah)
Stock Option Grant Agreement dated June 1, 2002. (Exhibit 10.2 to the Company’s Form 10-Q for the quarter ended June 30, 2002.)
E-4
10(ai)
Employee Continuity Agreement between James Nicholas Bayne and Maine Public Service Company dated July 25, 2002. (Exhibit 10.3 to the Company’s Form 10-Q for the quarter ended June 30, 2002.)
Not applicable.
Not applicable.
March 8, 1996 Letter regarding change in certifying accountant from Deloitte & Touche LLP. (Exhibit 16 to the Company’s 1996 Form 10-K)
Not applicable.
Not applicable.
Maine and New Brunswick Electrical Power Company, Limited, a Canadian corporation.
Not applicable.
Not applicable.
99(a)
Agreement of Purchase and Sale between Maine Public Service and Eastern Utilities Associates, dated April 7, 1986. (Exhibit 28(a) to Form 10-Q for the quarter ended June 30, 1986)
99(b)
Addendum to Agreement of Purchase and Sale, dated June 26, 1986. (Exhibit 28(b) to Form 10-Q for the Quarter ended June 30, 1986)
99(c)
Stipulation between Maine Public Service Company, the Staff of the Commission and the Maine Public Utilities Commission and the Maine Public Advocate, dated July 14, 1986. (Exhibit 28(c) to Form 10-Q for the quarter ended June 30, 1986)
99(d)
Amendment to July 14, 1986 Stipulation, dated July 18, 1986. (Exhibit 28(d) to Form 10-Q for the quarter ended June 30, 1986)
99(e)
Order of the Maine Public Utilities Commission dated July 21, 1986, Docket Nos 84-80, 84-113 and 86-3. (Exhibit 28(g) to 1986 Form 10-K)
99(f)
Order of the Maine Public Utilities Commission, dated May 9, 1986, Docket Nos. 84-113 and 86-3 (with attached Stipulations). (Exhibit 28(r) to 1986 Form 10-K)
99(g)
Order of the Maine Public Utilities Commission, dated July 31, 1987, Docket Nos. 84-80, 84-113, 87-96 and 87-167 (with attached Stipulation). (Exhibit 28(i) to 1988 Form 10-K)
99(h)
Agreement between Maine Public Service Company and various current Seabrook Nuclear Project Joint Owners, dated January 13, 1989. (Exhibit 28(o) to 1988 Form 10-K)
99(i)
Order of the Maine Public Utilities Commission dated November 30, 1995 (with attached Stipulation) in Docket No. 95-052. (Exhibit 28(p) to 1995 Form 10-K)
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99(j)
Order of the Federal Energy Regulatory Commission dated May 31, 1995 in Docket No. ER 95-836-000. (Exhibit 28(r) to 1995 Form 10-K)
99(k)
Order of Maine Public Utilities Commission dated June 26, 1996 in Docket 95-052 (Rate Design). (Exhibit 99(n) to 1996 Form 10-K)
99(l)
Independent Auditors Report of Deloitte & Touche L.L.P. dated February 14, 1996 regarding year ended December 31, 1995. (Exhibit 99(l) to 1997 Form 10-K)
99(m)
Amendment No. 1, dated as of March 28, 1997, to the Letter of Credit and Reimbursement Agreement, dated as of June 1, 1996, among the Registrant, The Bank of New York, Fleet Bank of Maine, and The Bank of New York, as Agent and Issuing Bank. (Exhibit 99(m) to 1997 Form 10-K)
99(n)
Amendment No. 4, dated as of March 28, 1997, to the Revolving Credit Agreement, dated as of October 8, 1987, by and among the Registrant, the signatory Banks thereto and The Bank of New York, as Agent. (Exhibit 99(n) to 1997 Form 10-K)
99(o)
Order of Maine Public Utilities Commission dated January 30, 1998 in Docket No. 97-830 (Annual Increase under Rate Stabilization Plan). (Exhibit 99(o) to 1997 Form 10-K)
99(p)
Order by the Maine Public Utilities Commission dated January 15, 1998 in Docket No. 97-727. (Exhibit 99(q) to 1997 Form 10-K)
99(q)
Order of Maine Public Utilities Commission dated February 20, 1998 in Docket 97-670 (Divestiture of Generation Assets). (Exhibit 99(q) to the Company’s 1998 Form 10-K)
99(r)
Order of Maine Public Utilities Commission dated September 21, 1998 in Docket 98-138 (Formation of marketing affiliate). (Exhibit 99(r) to the Company’s 1998 Form 10-K)
99(s)
Order of Maine Public Utilities Commission dated December 15, 1998 in Docket 98-865 (Annual Increase Under Rate Stabilization Plan). (Exhibit 99(s) to the Company’s 1998 Form 10-K)
99(t)
Report of Synapse Energy Economics regarding competition and market power in the Northern Maine market for the Maine Public Utilities Commission for Docket 97-586. (Exhibit 99(t) to the Company’s 1998 Form 10-K)
99(u)
Final Report of the MPUC and the Maine Attorney General regarding market power issues raised by the prospect of retail competition in the electric industry in Docket 97-877. (Exhibit 99(u) to the Company’s 1998 Form 10-K)
99(v)
Order of the Federal Energy Regulatory Commission dated December 22, 1998 in Docket No. ER95-836-000. (Exhibit 99(v) to the Company’s 1998 Form 10-K)
99(w)
Order of Maine Public Utilities Commission dated April 5, 1999 in Docket 98-584 (Generating Asset Sale Approval). (Exhibit 99(w) to 1999 Form 10-K)
99(x)
Order of the Federal Energy Regulatory Commission dated April 14, 1999 in Docket EC 99-29-000 (Generating Asset Sale Approval). (Exhibit 99(x) to 1999 Form 10-K)
99(y)
Order of the Federal Energy Regulatory Commission dated November 15, 1999 in Docket ER 99-4225-000 (Independent System Administrator). (Exhibit 99(y) to 1999 Form 10-K)
99(z)
Order of Maine Public Utilities Commission dated December 1, 1999 in Docket 98-577 (Stipulation Approval). (Exhibit 99(z) to 1999 Form 10-K)
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99(aa)
Order of Maine Public Utilities Commission dated December 3, 1999 in Docket 99-111 (Energy Atlantic as Central Maine Power Standard Offer Provider). (Exhibit 99(aa) to 1999 Form 10-K)
99(ab)
Order of Maine Public Utilities Commission dated February 17, 2000 in Docket 98-577 (Order Approving Phase II Stipulation). (Exhibit 99(ab) to 1999 Form 10-K)
99(ac)
Order of the Federal Energy Regulatory Commission dated August 14, 2000 in Dockets ER00-1053-000 and ER00-1053-002. (Exhibit 99(ac) to the Company’s 2000 Form 10-K)
99(ad)
Order of the Maine Public Utilities Commission dated November 17, 1999 in Docket 99-610 (Reduction in Capital). (Exhibit 99(ad) to the Company’s 2000 Form 10-K)
99(ae)
Order of the Maine Public Utilities Commission dated August 11, 2000 in Docket 99-185 (Stipulation Approval). (Exhibit 99(ae) to the Company’s 2000 Form 10-K)
99(af)
Agreement between the Maine Public Utilities Commission, the Company, Central Maine Power Company and Bangor Hydro-Electric Company dated January 10, 2001 regarding Maine Yankee Power Costs. (Exhibit 99(af) to the Company’s 2000 Form 10-K)
99(ag)
Notice of Investigation of the Maine Public Utilities Commission dated May 8, 2001 in Docket 01-245 (Rate Design) (Exhibit 99(ag) to the Company’s 2001 Form 10-K)
99(ah)
Order of the Maine Public Utilities Commission dated May 24, 2001 in Docket No. 99-764 (Amendments to Entitlement Agreements and Granting Waiver). (Exhibit 99.1 to the Company’s May 24, 2001 Form 8-K)
99(ai)
Procedural Order of the Maine Public Utilities Commission dated July 13, 2001 in Docket No. 00-894 (WPS Energy Service Complaint and related Proposed Findings and Decision of Investigator William B. Devoe, Esq.) (Exhibit 99(ai) to the Company’s 2001 Form 10-K)
99(aj)
Order of the Maine Public Utilities Commission dated November 20, 2001 in Docket No. 01-384 (Entitlement Agreements). (Exhibit 99(aj) to the Company’s 2001 Form 10-K)
99(ak)
Further Settlement Agreement between the Maine Public Utilities Commission, the Public Advocate and the Company dated January 24, 2002 regarding Maine Yankee Power costs. (Exhibit 99(ak) to the Company’s 2001 Form 10-K)
99(al)
Order of the Maine Public Utilities Commission dated February 27, 2002 in Docket No. 01-240 (Stranded Costs Stipulation approved effective March 1, 2002). (Exhibit 99(al) to the Company’s 2001 Form 10-K)
99(am)
Order of Maine Public Utilities Commission dated April 29, 2002 in Docket No. 2000-894 approving revised Stipulation of WPS Complaint Settlement. (Exhibit 99.1 to the Company’s Form 10-Q for the quarter ended March 31, 2002.)
*99(an)
Order of the Maine Public Utilities Commission dated March 26, 2003, (with attached Stipulation) in Docket No. 02-676, Request for Approval of Reorganization of the Company into a Holding Company Structure, Pages O-1 through O-21.
*99(ao)
Letter to Shareholders and Q&A with President from the 2002 Annual Report. (See Pages 2 to 4 and 13 to 15, respectively.)
*99(ap)
Certification of Financial Reports of Company’s 2002 Form 10-K, dated March 28, 2003.
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