Edgar Filing: MAINE PUBLIC SERVICE CO

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SEC. 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2001

Commission File No. 1-3429

Maine Public Service Company

(Exact name of registrant as specified in its charter)

Maine

(State or other jurisdiction of incorporation or organization)

01-0113635

(I.R.S. Employer Identification No.)

209 State Street, Presque Isle, Maine

(Address of principal executive offices)

04769

(Zip Code)

Registrant's telephone number, including area code: 207-768-5811

Securities registered pursuant to Section 12(b) of the Act:

Title of each class: Common Stock, $7.00 par value

Name of each exchange on which registered: American Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Title of Class

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X . No .

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

Aggregate market value of the voting stock held by non-affiliates at March 14, 2002: $46,910,149.

The number of shares outstanding of each of the issuer's classes of common stock as of March 14, 2002.

Common Stock, $7.00 par value - 1,573,638 shares

DOCUMENTS INCORPORATED BY REFERENCE

1. The Company's 2001 Annual Report to Stockholders is incorporated by reference into Parts I, II and IV.

2. The Company's definitive proxy statement, to be filed pursuant to Regulation 14A no later than 120 days after December 31, 2001, which is the end of the fiscal year covered by this report, is incorporated by reference into Part III.

(Page 1 of 16 pages)

MAINE PUBLIC SERVICE COMPANY

FORM 10-K

For the Fiscal Year Ended December 31, 2001

TABLE OF CONTENTS

		Pages
PART I
Item 1. Business
	General	3
	Financial Information about Foreign and Domestic Operations	4
	Regulation and Rates	5
	Franchises and Competition	5
	Employees	5
	Subsidiaries and Affiliated Companies	5
Item 2. Properties		6
Item 3. Legal Proceedings		6
Item 4. Submission of Matters to a Vote of Security Holders		8
PART II
Item 5. Market for Registrant's Common Equity and Related Shareholder Matters		9
Item 6. Selected Financial Data		9
Item 7. Management's Discussion and Analysis of Financial Condition and
	Results of Operations	9
Item 7a. Quantitative and Qualitative Disclosures About Market Risk		10
Item 8. Financial Statements and Supplementary Data		10
Item 9. Changes In and Disagreements with Accountants		10
PART III
Item 10. Directors and Executive Officers of the Registrant		11
Item 11. Executive Compensation		12
Item 12. Security Ownership of Certain Beneficial Owners and Management		12
Item 13. Certain Relationships and Related Transactions		12
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K		13

Form 10-K

PART I

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") 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 electric energy, and currently engages in the transmission and distribution of electric energy to retail and, until March 1, 2000, wholesale customers in all of Aroostook County and a small portion of Penobscot County in northern Maine. Geographically, the service territory is approximately 120 miles long and 30 miles wide, with a population of approximately 77,000. The service area of the Company includes one of the most important potato growing and processing sections in the United States. In addition, the area produces wood products, principally lumber, as well as pulp wood and wood chips for paper manufacturing. On March 1, 2000, customers in the Company's service territory began purchasing energy from suppliers other than the Company, either from competitive electricity providers or, if they are unable or did not wish to choose a competitive supplier, the Standard Offer Service (SOS), marking the beginning of retail competition in Maine.

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 to the Company the energy not needed to supply its wholesale New Brunswick customer. During 1999, sales to the Company amounted to 65,333 MWH out of the 78,109 MWH generated for sale at Tinker.

See Item 1, "Regulation and Rates", below for further discussion of Maine's electric utility deregulation law and the sale of the Company's generating assets.

EA participated in the wholesale power market during 1999 and until March 1, 2000, when it began selling energy in the competitive retail electricity market in Maine. EA was the standard offer service (SOS) provider for approximately 525,000 residential and small commercial customers in Central Maine Power's (CMP) territory from March 1, 2000 until it expired on February 28, 2002. 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. In the Company's service territory, EA provided 20% of the medium non-residential SOS from March 1, 2000 until February 28, 2001. 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 the competitive markets throughout Maine. These new sales, however, produce far less revenue than EA received in 2001 from SOS in CMP's territory. SOS activity is recorded on a net margin basis, while CES activity is recorded on a gross basis to include the related revenues and purchased power expenses. For further information regarding EA, its contract settlement and efforts to expand sales, see Exhibit 13, 2001 Annual Report to Stockholders, Note 12 to the Consolidated Financial Statements, "Commitments, Contingencies and Regulatory Markets", incorporated herein by reference.

As of 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 in 2001. The Company and W-S agreed to amend the PPA. 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

Form 10-K

PART I

Item 1. Business - Continued

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 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 its retail rates, and is therefore in the best interests of the Company, its customers and shareholders. Beginning on March 1, 2000, WPS Energy Services began taking delivery of W-S output and reimbursing the Company for the market rate. The Company records the above-market cost of the W-S contract as stranded costs.

Financial Information about Foreign and Domestic Operations

(In Thousands of U.S. Dollars)

	2001	2000	1999
Revenues from
Unaffiliated Customers:
Parent-United States	31,780	37,443	58,677
Subsidiary-United States	15,771	38,021	8,429
Subsidiary-U.S. - SOS Margin	2,147	2,774	-
Total Domestic	49,698	78,238	67,106
Subsidiary-Canada	-	-	350
Intercompany Revenues:
Parent-United States	-	-	323
Subsidiary-United States	3	70	311
Total Domestic	3	70	634
Subsidiary-Canada	-	-	1,027
Operating Income (Loss):
Parent-United States	5,379	5,404	7,308
Subsidiary-United States	1,006	1,515	(335)
Total Domestic	6,385	6,919	6,973
Subsidiary-Canada	(25)	86	104
Net Income (Loss)
Parent-United States	4,331	3,354	3,811
Subsidiary-United States	897	1,688	(354)
Total Domestic	5,228	5,042	3,457
Subsidiary-Canada	9	259	549
Identifiable Assets:
Parent-United States	136,931	143,716	160,782
Subsidiary-United States	5,632	6,385	1,445
Total Domestic	142,563	150,101	162,227
Subsidiary-Canada	772	756	9,321

The identifiable assets, by company, are those assets used in each company's operations, excluding intercompany receivables and investments.

Form 10-K

PART I

Item 1. Business - Continued

Regulation and Rates

The information with respect to regulation and rates is presented in Exhibit 13, 2001 Annual Report to Stockholders, Note 12 to the Consolidated Financial Statements, "Commitments, Contingencies and Regulatory Matters", 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 and the generating asset sale, see Exhibit 13, 2001 Annual Report to Stockholders, Note 12 to the Consolidated Financial Statements, "Commitments, Contingencies and Regulatory Matters", incorporated herein by reference.

Employees

The information with respect to employees is presented in Exhibit 13, 2001 Annual Report to Stockholders, page 11, "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.

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 deregulation progress, see Exhibit 13, 2001 Annual Report to Stockholders, Note 12 to the Consolidated Financial Statements, "Commitments, Contingencies and Regulatory Matters", 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.

Form 10-K

PART I

Item 2. Properties

Until June 8, 1999, the Company owned and operated electric generating facilities consisting of: oil-fired steam units with a total capability of 23,000 kilowatts, diesel generation totaling 12,300 kilowatts, and hydro-electric facilities of 2,300 kilowatts. The Canadian Subsidiary owned and operated a hydro-electric plant of 33,500 kilowatts and a small diesel unit with 1,000 kilowatt capacity. As discussed in Exhibit 13, 2001 Annual Report to Stockholders, Note 12 to the Consolidated Financial Statements, "Commitments, Contingencies and Regulatory Matters", incorporated herein by reference, the Company sold its generating assets on June 8, 1999 in accordance with the State's electric deregulation law.

As of December 31, 2001, the Company and Subsidiary had approximately 392.45 pole miles of transmission lines and the Company owned approximately 1,738.91 miles of distribution lines.

The Company was a part-owner of a 600,000 kilowatt oil-fired steam unit built by Central Maine Power Company at its Wyman Station in Yarmouth, Maine. The Company's share of that unit was 3.3455%, or approximately 20,000 kilowatts, and was included in the generating asset sale on June 8, 1999, as more fully described in Exhibit 13, 2001 Annual Report to Stockholders, Note 12 to the Consolidated Financial Statements, "Commitments, Contingencies and Regulatory Matters", incorporated herein by reference.

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.

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 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 ground 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.

Form 10-K

PART I

Item 3. Legal Proceedings - Continued

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. A schedule for this investigation has not yet been announced.

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.

This investigation continues and the Company is unable to predict the timing or nature of the MPUC's ultimate decision.

(b) Maine Public Utilities Commission Investigation of Maine Public Service Company's Stranded Cost Revenue Requirement in MPUC Docket No. 0l-240.

Reference is made to the Company's 1999 Annual Report in which the Company noted that the MPUC had allowed it to begin an annual recovery of $12.5 million in stranded investment beginning on March 1, 2000. On May 8, 2001, the MPUC issued a notice of investigation in the above docket for the purpose of determining whether the Company's rates 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. A stipulation placed before the MPUC in January, 2002 includes annual stranded cost recovery of $11,540,000 and a 15% sharing of the Maine Yankee insurance refund with the Company's shareholders. This stipulation was approved by the MPUC on January 7, 2002, and the appropriate order was issued on February 27, 2002.

(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:

Form 10-K

PART I

Item 3. Legal Proceedings - Continued

(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 believes that at least a substantial portion of its stranded costs should be recovered through fixed charges that its customers cannot avoid by reducing or eliminating their usage. Such a fixed charge would reduce the risk of the Company's ability to recover its stranded costs from customers. The Company, together with CMP and BHE, will be filing testimony in support of its position in early April, 2002.

The Company cannot predict the nature or the outcome of any decision in this proceeding.

Item 4. Submission of Matters To a Vote of Security Holders

At the Company's Annual Meeting of Stockholders, held on May 8, 2001 the only matter voted upon was the uncontested election of the following directors to serve until the 2004 Annual Meeting of Stockholders, each of whom received the votes shown:

Nominee	For	Against	Non-votes and Abstentions
Paul R. Cariani	1,373,796	17,482	181,782
Richard G. Daigle	1,374,996	16,282	181,782
J. Gregory Freeman	1,383,019	8,259	181,782

Form 10-K

PART II

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, 2001, there were 1,001 holders of record of the Company's Common Stock.

Dividend data and market price related to the Common Stock are tabulated as follows for the two most recent calendar years:

	Market Price		Dividends	Dividends
	High	Low	Paid Per Share	Declared Per Share
2001
First Quarter	$26.63	$23.37	$ .32	$.32
Second Quarter	$30.50	$26.00	.32	.32
Third Quarter	$29.60	$27.00	.32	.35
Fourth Quarter	$30.75	$27.75	.35	.35
Total Dividends			$ 1.31	$1.34
2000
First Quarter	$18.00	$16.00	$ .30	$.30
Second Quarter	$20.75	$17.38	.30	.30
Third Quarter	$25.60	$20.25	.30	.32
Fourth Quarter	$27.13	$23.75	.32	.32
Total Dividends			$1.22	$1.24

Dividends declared within the quarter are paid on the first day of the succeeding quarter.

See Exhibit 13, 2001 Annual Report to Stockholders, Note 7 to the Consolidated Financial Statements, "Common Shareholders' Equity", incorporated herein by reference, concerning restrictions on payment of dividends on Common Stock.

Item 6. Selected Financial Data

A five-year summary of selected financial data (1997-2001) is included on page 14 of Exhibit 13, 2001 Annual Report to Stockholders, which summary is incorporated herein by reference.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The information required to be furnished in response to this Item is submitted as pages 4 to 14, Exhibit 13, 2001 Annual Report to Shareholders, which pages are hereby incorporated herein by reference. Information regarding "Construction" is also furnished in Note 12 to the Consolidated Financial Statements, "Commitments, Contingencies and Regulatory Matters", of the Notes to the Consolidated Financial Statements, pages 29 to 37 of Exhibit 13, 2001 Annual Report to Stockholders, which pages are hereby incorporated herein by reference.

Form 10-K

PART II

Item 7a. Quantitative and Qualitative Disclosures about Market Risk

(a) The Company has interest rate risk with three variable rate debt issues of the regulated business as of December 31, 2001 for purposes other than trading. One issue, $9 million of tax-exempt bonds, 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 Exhibit 13, the Company's 2000 Annual Report, 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 $11,540,000 of Taxable Electric Rate Stabilization Revenue Notes issued on May 29, 1998 by the Finance Authority of Maine and 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, 2001. As discussed in Note 8 incorporated above, the Company purchased interest rate caps for each of these issues.

(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.

Item 8. Financial Statements and Supplementary Data

(a) The following financial statements and supplementary data are included in Exhibit 13, the Company's 2001 Annual Report to Stockholders on pages 15 through 37, and are incorporated herein by reference:

Report of Independent Accountants.

Statements of Consolidated Income for the years ended December 31, 2001, 2000 and 1999.

Statements of Consolidated Cash Flows for the years ended December 31, 2001, 2000 and 1999.

Consolidated Balance Sheets as of December 31, 2001 and 2000.

Statements of Consolidated Common Shareholders' Equity for the years ended December 31, 2001, 2000 and 1999.

Consolidated Statements of Capitalization as of December 31, 2001 and 2000.

Notes to Consolidated Financial Statements.

Item 9. Changes In And Disagreements With Accountants On Accounting and Financial Disclosure

None.

Form 10-K

PART III

Item 10. Directors and Executive Officers of the Registrant

Information with regard to the Directors of the registrant is set forth in the proxy statement of the registrant relating to its 2002 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 2001 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:

Name		Age	Office Continuously Held Since
Paul R. Cariani	President and Chief Executive Officer	61	6/1/94
J. Nicholas Bayne	President and Chief Executive Officer-Elect	48	3/18/02
Larry E. LaPlante	Vice President, Treasurer and Chief	50	6/1/99
	Financial Officer
Stephen A. Johnson	Vice President and General Counsel	54	3/2/01 (until 2/15/02)
William L. Cyr	Vice President, Power Delivery	42	6/1/00
Michael A. Thibodeau	Vice President, Human Resources	45	12/1/00

Paul R. Cariani has been an employee of the Company since November 1, 1977, starting as an Assistant to the Treasurer. In May 1978, he was appointed Assistant Treasurer until his election as Treasurer, Secretary and Clerk, on March 1, 1983. In May 1985, he was elected Vice President, Finance and Treasurer effective June 1, 1985. On February 25, 1992, Mr. Cariani was elected a Director of the Company to fill an existing vacancy on the Board. On May 11, 1993, he was elected Executive Vice President, Chief Financial Officer and Treasurer, effective June 1, 1993. Effective June 1, 1994, he was elected President and CEO, replacing the retiring G. Melvin Hovey. Mr. Hovey remains Chairman of the Board of Directors. Mr. Cariani has announced his intention to retire on September 1, 2002.

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 will replace Paul R. Cariani as President on June 1, 2002, and upon Mr. Cariani's retirement effective September 1, 2002, he will also assume 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.

Form 10-K

PART III

Item 10. Directors and Executive Officers of the Registrant - Continued

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, due to Mr. Johnson's resignation. 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.

Stephen A. Johnson was elected to the position of Vice President and General Counsel, effective March 2, 2001, until his resignation effective February 15, 2002. Mr. Johnson also served as Secretary and Clerk of the Company, a position he had held since June 1, 1985. Mr. Johnson was appointed General Counsel of the Company on March 5, 1985. On September 1, 1988, he was elected Vice President of Administration and General Counsel, a position he held until his election as Vice President, Customer Service and General Counsel. Effective June 1, 1990, he was elected to Vice President, Customer Service and General Counsel. On June 1, 1999, he was elected Vice President, Energy Atlantic and General Counsel. Prior to joining the Company, Mr. Johnson was the General Counsel of the Maine Office of the Public Advocate from 1983 to 1985 and prior to that was a Staff Attorney of the Maine Public Utilities Commission.

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, Human Resources effective December 1, 2000. 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.

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 14, 2002.

There are no family relationships among the executive officers.

Item 11. Executive Compensation

Information for this item is set forth in the proxy statement of the registrant relating to its 2002 Annual Meeting of Stockholders, which information (with the exception of the "Board Executive Compensation Committee Report") is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management

Information for this item is set forth in the proxy statement of the registrant relating to its 2002 Annual Meeting of Stockholders, which information is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions

Not applicable.

Form 10-K

PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a) (1) Financial Statements

Report of Independent Accountants

Incorporated by reference into Part II of this report from pages 15 through 37 of the 2001 Annual Report to Stockholders:

Statements of Consolidated Income for years ended December 31, 2001, 2000 and 1999

Statements of Consolidated Cash Flows for the years ended December 31, 2001, 2000 and 1999

Consolidated Balance Sheets as of December 31, 2001 and 2000

Statements of Consolidated Common Shareholders' Equity for the years ended December 31, 2001, 2000 and 1999

Consolidated Statements of Capitalization as of December 31, 2001 and 2000

Notes to Consolidated Financial Statements

(2) Financial Statement Schedules

Included in Part IV of this report:

	Page
Report of Independent Accountants	15
Schedule II - Valuation of Qualifying Accounts and Reserves	16

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

(b) A Form 8-K was filed on: May 24, 2001, 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 14th of March, 2002.

MAINE PUBLIC SERVICE COMPANY

By: /s/ Kurt A. Tornquist

Kurt A. Tornquist

Controller, Assistant Secretary and Assistant Treasurer

Form 10-K

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.

Signature	Title	Date

/s/ G. Melvin Hovey	Chairman of the Board and Director	3/1/2002
(G. Melvin Hovey)
/s/ Paul R. Cariani	President and Director	3/1/2002
(Paul R. Cariani)
/s/ Robert E. Anderson	Director	3/1/2002
(Robert E. Anderson)
/s/ D. James Daigle	Director	3/1/2002
(D. James Daigle)
/s/ Richard G. Daigle	Director	3/1/2002
(Richard G. Daigle)
/s/ J. Gregory Freeman	Director	3/1/2002
(J. Gregory Freeman)
/s/ Deborah L. Gallant	Director	3/1/2002
(Deborah L. Gallant)
/s/ Nathan L. Grass	Director	3/1/2002
(Nathan L. Grass)
/s/ J. Paul Levesque	Director	3/1/2002
(J. Paul Levesque)
/s/ Lance A. Smith	Director	3/1/2002
(Lance A. Smith)

REPORT OF INDEPENDENT ACCOUNTANTS

To the Directors and Shareholders of

Maine Public Service Company

Our audits of the consolidated financial statements referred to in our report dated February 7, 2002 appearing on page 15 of the 2001 Annual Report to Shareholders of Maine Public Service Company (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule in Item 14(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Portland, Maine

February 7, 2002

Maine Public Service Company & Subsidiary

Valuation of Qualifying Accounts & Reserves

For the Years Ended December 31, 2001, 2000 and 1999

		Additions		Deductions

	Balance		Recoveries	Accounts	Balance
	at	Costs	of Accounts	Written Off	at
	Beginning	&	Previously	As	End of
	of Period	Expenses	Written Off	Uncollectible	Period

Reserve Deducted From Asset To Which It Applies:

	Allowance for Uncollectible Accounts


2001	334,690	78,820	108,598	305,608	216,500


2000	215,000	352,739	102,444	335,493	334,690


1999	215,000	171,323	119,690	291,013	215,000

Form 10-K

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)

E-1

4(t)	Seventeenth Supplemental Indenture, Dated April 1, 1997. (Exhibit 4(t) to the Company's 1998 Form 10-K)
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)
9	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)

E-2

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)
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 Dated March 1, 1991. (Exhibit 10(i) to the Company's 1991 Form 10-K)
10(k)	Second Supplemental Indenture 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)
Executive Compensation Plans and Arrangements
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)

E-3

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)
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 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 dated May 1, 1998. (Exhibit 10(v) to the Company's 1998 Form 10-K)
10(y)	Fifth Supplemental Indenture 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)

E-4

*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.
*10(af)	Master Power Purchase & Sale Agreement between Energy Atlantic, LLC and Duke Energy Trading and Marketing, LLC dated September 19, 2001.
11	Not applicable.
12	Not applicable.
*13	2001 Annual Report to Stockholders
16	March 8, 1996 Letter regarding change in certifying accountant from Deloitte & Touche LLP. (Exhibit 16 to the Company's 1996 Form 10-K)
18	Not applicable.
19	Not applicable.
21	Maine and New Brunswick Electrical Power Company, Limited, a Canadian corporation.
22	Not applicable.
23	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)

E-5

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)
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 indus- try 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)

E-6

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)
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)
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.)
*99(aj)	Order of the Maine Public Utilities Commission dated November 20, 2001 in Docket No. 01-384 (Entitlement Agreements).
*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.
*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).

E-7

Exhibit 10(ae)

GENERAL RELEASE AGREEMENT

This General Release Agreement ("Agreement") is entered into by and among Engage Energy America LLC ("Engage"), Energy Atlantic, LLC ("Atlantic"), Maine Public Service Co. ("MPS"), Central Maine Power Company ("CMP"), and Frontier Insurance Company ("Frontier"). It is the intent of all parties to this Agreement to settle and release any and all claims under or in connection with any Bonds issued by Frontier in connection with Atlantic's provision of the standard offer service in the service territory of CMP in Maine.

For good and valuable consideration, the receipt of which is hereby acknowledged, the parties agree as follows:

1. Upon delivery by CMP of the original December 16, 1999, Frontier performance bonds numbered 122618, 122617, 122616, and 122615 (the "Frontier Bonds") to Frontier and Frontier's receipt of this Agreement fully executed by all parties, Frontier shall pay Engage and Engage agrees to accept One Million Dollars ($1,000,000) in complete settlement of any and all claims of any and all parties under or arising out of the Frontier Bonds.

2. In consideration of the payment set forth in Paragraph 1, Engage, Atlantic, MPS and CMP and any of their successors, assigns, shareholders, directors, insurers, partners, affiliates, employees and agents (all hereafter "Releasors") hereby releases and forever discharges Frontier and its agents, servants, employees, attorneys, insurers and reinsurers (including but not limited to National Indemnity Company) (hereafter "Releasees") of and from any and all actions, causes of action, claims, or demands of whatever kind or nature, whether known or unknown, that Releasors now have or that may hereafter accrue to any of them on account of, or in any way arising out of Atlantic's provision of standard offer service in CMP's service territory in Maine (Me. PUC Docket No. 99-111, December 3, 1999) , and/or referring or relating in any way to and/or in connection with the Frontier Bonds and its December 14, 1999 General Indemnity Agreement with Atlantic.

3. It is understood and agreed that this settlement is the compromise of doubtful and disputed claims, and that any payments made are not to be construed as admissions on the part of the parties, by whom liability is expressly denied.

4. This Agreement may be executed in one or more counterparts, each of which shall be deemed an original, and all of which together constitutes one and the same instrument, and photographic copies of such signed counterparts may be used in place of the original.

5. Since freedom from costs of future litigation represents an important item of consideration bargained for by the parties to this Agreement, it is agreed that damages recoverable for breach of this Agreement by any party shall include reasonable attorney's fees and other costs as a consequence of such breach.

6. No promise or inducement that is not herein expressed has been made to any party, and in executing this Agreement each party does not rely upon any statement or representation made by any adverse parties or any agent or person representing any adverse party concerning the nature, extent or duration of said damages or losses or the legal liability therefore.

7. This General Release Agreement contains the entire Agreement between all parties for the settlement described herein, and may not be modified or amended in any way except in a writing signed by all parties hereto.

8. The parties further represent that, with the assistance of legal counsel, they have carefully read the foregoing General Release Agreement, and know the contents thereof and sign the same as their own free act and deed.

CAUTION: READ BEFORE SIGNING

Dated: May 24, 2001	/s/ Mark Stiers
	Engage Energy America LLC
	By its: President
Dated: May 24, 2001	/s/ Stephen A. Johnson
	Energy Atlantic, LLC
	By its: Managing Member, Maine Public Service Company, Vice President
Dated: May 24, 2001	/s/ Larry E. LaPlante
	Maine Public Service Company
	By its: Vice President, Treasurer &
	Chief Financial Officer
Dated: May 24, 2001	/s/ Sara Burns
	Central Maine Power Company
	By its: President
Dated: May 24, 2001	/s/ Bruce L. Maas
	Frontier Insurance Company
	By its: Vice President

GENERAL RELEASE AGREEMENT

This General Release Agreement ("Agreement") is entered into by and among

Engage Energy America LLC ("Engage"), Energy Atlantic, LLC ("Atlantic"), Maine

Public Service Co. ("MPS"), and Frontier Insurance Company ("Frontier"). It is the

intent of all parties to this Agreement to settle and release any and all claims under or in

connection with any Bonds issued by Frontier in connection with Atlantic's provision of

the standard offer service in the service territory of Central Maine Power Company

("CMP") in Maine.

For good and valuable consideration, the receipt of which is hereby

acknowledged, the parties agree as follows:

1. In consideration of the execution of a separate General Release Agreement provided by Engage, Atlantic, MPS and Central Maine Power Co. to Frontier, and upon return by CMP to Frontier of the original December 16, 1999, performance bonds numbered 122618, 122617, 122616, and 122615 (the "Frontier Bonds") provided by Frontier to Atlantic in connection with Atlantic's provision of the standard offer service in the service territory of Central Maine Power

Co. (Me. PUC Docket No. 99-111, December 3, 1999), Frontier shall execute this Agreement releasing and forever discharging Engage, Atlantic, and MPS and their agents, servants, employees, affiliates, attorneys, and insurers from any and all actions, causes of action, claims or demands of whatever kind or nature, whether known or unknown, in any way arising out of the December 14, 1999 General Agreement of

Indemnity between Frontier and Atlantic or the Frontier Bonds described above. Frontier provides this Release on its behalf and on behalf of any of its agents, servants, successors, insurers, reinsurers, employees and assigns.

2. It is understood and agreed that this settlement is the compromise of doubtful and disputed claims, and that any payments made are not to be construed as admissions on the part of the parties, by whom liability is expressly denied.

3. This Agreement may be executed in one or more counterparts, each of which shall be deemed an original, and all of which together constitutes one and the same instrument, and photographic copies of such signed counterparts may be used in place of the original.

4. Since freedom from costs of future litigation represents an important item of consideration bargained for by the parties to this Agreement, it is agreed that damages recoverable for breach of this Agreement by any party shall include reasonable attorney's fees and other costs as a consequence of such breach.

5. No promise or inducement that is not herein expressed has been made to any party, and in executing this Agreement each party does not rely upon any statement or representation made by any adverse parties or any agent or person representing any adverse party concerning the nature, extent or duration of said damages or losses or the legal liability therefore.

6. This General Release Agreement contains the entire Agreement between all parties for the settlement described herein, and may not be modified or amended in any way except in a writing signed by all parties hereto.

7. The parties further represent that, with the assistance of legal counsel, they have carefully read the foregoing General Release Agreement, and know the contents thereof and sign the same as their own free act and deed.

CAUTION: READ BEFORE SIGNING

Dated: May 24, 2001	/s/ Bruce L. Maas
	Frontier Insurance Company
	By its: Vice President
Dated: May 24, 2001	/s/ Mark Stiers
	Engage Energy America LLC
	By its: President
Dated: May 24, 2001	/s/ Stephen A. Johnson
	Energy Atlantic, LLC
	By its: Managing Member, Maine Public Service Company, Vice President
Dated: May 24, 2001	/s/ Larry E. LaPlante
	By its: Vice President, Treasurer & Chief Financial Officer

Exhibit 10(af)

Master Power

Purchase & Sale

Agreement

Version 2.1 (modified 4/25/00)

AUTOMATIC LICENSE-PERMISSION OF THE COPYRIGHT OWNERS IS GRANTED FOR REPRODUCTION BY DOWNLOADING FROM A COMPUTER AND PRINTING ELECTRONIC COPIES OF THE WORK. NO AUTHORIZED COPY MAY BE SOLD. THE INDUSTRY IS ENCOURAGED TO USE THIS MASTER POWER PURCHASE AND SALE AGREEMENT IN ITS TRANSACTIONS. ATTRIBUTION TO THE COPYRIGHT OWNERS IS REQUESTED.

MASTER POWER PURCHASE AND SALES AGREEMENT

TABLE OF CONTENTS

COVER SHEET	1
GENERAL TERMS AND CONDITIONS	6
ARTICLE ONE: GENERAL DEFINITIONS	6
ARTICLE TWO: TRANSACTION TERMS AND CONDITIONS	11
2.1 Transactions	11
2.2 Governing Terms	11
2.3 Confirmation	11
2.4 Additional Confirmation Terms	12
2.5 Recording	12
ARTICLE THREE: OBLIGATIONS AND DELIVERIES	12
3.1 Seller's and Buyer's Obligations	12
3.2 Transmission and Scheduling	12
3.3 Force Majeure	12
ARTICLE FOUR: REMEDIES FOR FAILURE TO DELIVER/RECEIVE	13
4.1 Seller Failure	13
4.2 Buyer Failure	13
ARTICLE FIVE: EVENTS OF DEFAULT; REMEDIES	13
5.1 Events of Default	13
5.2 Declaration of an Early Termination Date and Calculation of Settlement
Amounts	15
5.3 Net Out of Settlement Amounts	15
5.4 Notice of Payment of Termination Payment	15
5.5 Disputes With Respect to Termination Payment	15
5.6 Closeout Setoffs	16
5.7 Suspension of Performance	16
ARTICLE SIX: PAYMENT AND NETTING	16
6.1 Billing Period	16
6.2 Timeliness of Payment	17
6.3 Disputes and Adjustments of Invoices	17
6.4 Netting of Payments	17
6.5 Payment Obligation Absent Netting	17
6.6 Security	18
6.7 Payment for Options	18
6.8 Transaction Netting	18

ARTICLE SEVEN: LIMITATIONS	18
7.1 Limitation of Remedies, Liability and Damages	18
ARTICLE EIGHT: CREDIT AND COLLATERAL REQUIREMENTS	19
8.1 Party A Credit Protection	19
8.2 Party B Credit Protection	21
8.3 Grant of Security Interest/Remedies	22
ARTICLE NINE: GOVERNMENTAL CHARGES	23
9.1 Cooperation	23
9.2 Governmental Charges	23
ARTICLE TEN: MISCELLANEOUS	23
10.1 Term of Master Agreement	23
10.2 Representations and Warranties	23
10.3 Title and Risk of Loss	25
10.4 Indemnity	25
10.5 Assignment	25
10.6 Governing Law	25
10.7 Notices	26
10.8 General	26
10.9 Audit	26
10.10 Forward Contract	27
10.11 Confidentiality	27
SCHEDULE M: GOVERNMENTAL ENTITY OR PUBLIC POWER SYSTEMS	28
SCHEDULE P: PRODUCTS AND RELATED DEFINITIONS	32
EXHIBIT A: CONFIRMATION LETTER	39

MASTER POWER PURCHASE AND SALE AGREEMENT

COVER SHEET

This Mater Power Purchase and Sale Agreement ("Master Agreement" ) is made as of the following date:

9-19-2001 ("Effective Date"). The Master Agreement, together with the exhibits, schedules and any written supplements hereto, the Party A Tariff, if any, the Party B Tariff, if any, any designated collateral, credit support or margin agreement or similar arrangement between the Parties and all Transactions (including any confirmations accepted in accordance with Section 2.3 hereto) shall be referred to as the "Agreement." The Parties to this Master Agreement are the following:

Name: ENERGY ATLANTIC LLC ("EA" or "Party A")	Name: DUKE ENERGY TRADING AND MARKETING, LLC ("DETM" or "Party B")
All Notices:	All Notices: See Addendum
Street: 830 Main Street, Suite 20, P.O. Box 1148	Street:
City: Presque Isle, ME Zip: 04769	City: Zip:
Attn: Contract Administration Phone: 207-764-7600 Facsimile: 207-764-4657 Duns: 01-167-3840 Federal Tax ID Number: 52-2093905	Attn: Contract Administration Phone: Facsimile: Duns: Federal Tax ID Number:
Invoices: Attn: Jan Currier Phone: 207-764-7600 Facsimile: 207-764-4657	Invoices: Attn: Phone: Facsimile:
Scheduling: Attn: Don Theriault Phone: 207-764-7600 Facsimile: 207-764-4657	Scheduling: Attn: Phone: Facsimile:
Payments: Attn: Jan Currier Phone: 207- 764-7600 Facsimile: 207-764-4657	Payments: Attn: Phone: Facsimile:
Wire Transfer: BNK: Fleet Bank ABA: 011200365 ACCT: 94-2776-1635	Wire Transfer: BNK: ABA: ACCT:
Credit and Collections: Attn: Vicki Keaton Phone: 207-764-7600 Facsimile: 207-764-4657	Credit and Collections: Attn: Phone: Facsimile:
With additional Notices of an Event of Default or Potential Event of Default to: Attn: Cal Deschene Phone: 207-764-7600 Facsimile: 207-764-4657	With additional Notices of an Event of Default or Potential Event of Default to: Attn: Phone: Facsimile:

The Parties hereby agree that the General Terms and Conditions are incorporated herein, and to the following provisions as provided for in the General Terms and Conditions:

Party A Tariff Dated Docket Number

Party B Tariff Dated Docket Number

Article Two
Transaction Terms and Conditions	[x] Optional provision in Section 2.4. If not checked, inapplicable.
Article Four
Remedies for Failure to Deliver or Receive	[x] Accelerated Payment of Damages. If not checked, inapplicable.
Article Five	[ ] Cross Default for Party A:

Events of Default; Remedies	[ ] Party A:	Cross Default Amount $
	[x] Other Entity: Maine Public Service Company	Cross Default Amount $5,000,000
	[x] Cross Default for Party B:
	[x] Party B: DETM	Cross Default Amount$60,000,000
	[ ] Other Entity:	Cross Default Amount $

	5.6 Closeout Setoff
	[x] Option A (Applicable if no other selection is made.)
	[ ] Option B - Affiliates shall have the meaning set forth in the Agreement unless otherwise specified as follows:
	[ ] Option C (No Setoff)
Article 8	8.1 Party A Credit Protection:
Credit and Collateral Requirements	(a) Financial Information:
	[x] Option A [ ] Option B Specify: [ ] Option C Specify:
	(b) Credit Assurances:
	[ ] Not Applicable [x] Applicable
	(c) Collateral Threshold:
	[ ] Not Applicable [x] Applicable

	If applicable, complete the following:
	Party B Collateral Threshold: $30,000,000; provided, however, that Party B's Collateral Threshold shall be zero if an Event of Default or Potential Event of Default with respect to Party B has occurred and is continuing.
	Party B Independent Amount: $ N/A
	Party B Rounding Amount: $100,000
	(d) Downgrade Event:
	[ ] Not Applicable [x] Applicable
	If applicable, complete the following:
	[x] It shall be a Downgrade Event for Party B if Party B's Corporate Credit Rating falls below BBB- from S&P or Baa3 from Moody's or if Party B is not rated by S&P.
	[ ] Other: Specify:
	(e) Guarantor for Party B: N/A
	Guarantee Amount: N/A
	8.2 Party B Credit Protection:
	(a) Financial Information:
	[ ] Option A [x] Option B Specify: Maine Public Service Company [ ] Option C Specify:
	(b) Credit Assurances:
	[ ] Not Applicable [x] Applicable
	(c) Collateral Threshold:
	[ ] Not Applicable [x] Applicable
	If applicable, complete the following:
	Party A Collateral Threshold: $1,000,000; provided, however, that Party A's Collateral Threshold shall be zero if an Event of Default or Potential Event of Default with respect to Party A has occurred and is continuing. (SEE OTHER CHANGES)
	Party A Independent Amount: $ N/A
	Party A Rounding Amount: $100,000

	(d) Downgrade Event:
	[ ] Not Applicable [x] Applicable
	If applicable, complete the following:
	[ ] It shall be a Downgrade Event for Party A if Party A's Credit Rating falls below____ from S&P or____ from Moody's or if Party A is not rated by either S&P or Moody's
	[x] Other: Specify: It shall be a Downgrade Event if the total shareholder equity of Maine Public Service Company falls below $35,000,000.
	(e) Guarantor for Party A: Maine Public Service Company
	Guarantee Amount: $1,000,000
Article 10
Confidentiality	[x] Confidentiality Applicable	If not checked, inapplicable.
Schedule M
	[ ] Party A is a Governmental Entity or Public Power System
	[ ] Party B is a Governmental Entity or Public Power System
	[ ] Add Section 3.6. If not checked, inapplicable
	[ ] Add Section 8.6. If not checked, inapplicable
Other Changes: 8.2 (C)	Specify, if any: COLLATERAL THRESHOLD
	Maine Public Service Company to provide a guaranty on behalf of Energy Atlantic LLC in the amount of $1,000,000. If not provided, the threshold will be zero. SEE ADDENDUM

IN WITNESS WHEREOF, the Parties have caused this Master Agreement to be duly executed as of the date first above written.

ENERGY ATLANTIC LLC	DUKE ENERGY TRADING AND MARKET NG, LLC
By: /s/ Calvin D. Deschene	By: /s/ Joy Thakur
Name: Calvin D. Deschene	Name: Joy Thakur
Title: General Manager	Title: Senior Director

DISCLAIMER: This Master Power Purchase and Sale Agreement was prepared by a committee of representatives of Edison Electric Institute ("EEI") and National Energy Marketers Association ("NEM") member companies to facilitate orderly trading in and development of wholesale power markets. Neither EEI nor NEM nor any member company nor any of their agents, representatives or attorneys shall be responsible for its use, or any damages resulting therefrom. By providing this Agreement EEI and NEM do not offer legal advice and all users are urged to consult their own legal counsel to ensure that their commercial objectives will be achieved and their legal interests are adequately protected.

GENERAL TERMS AND CONDITIONS

ARTICLE ONE: GENERAL DEFINITIONS

1.1 "Affiliate" means, with respect to any person, any other person (other than an individual) that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with, such person. For this purpose, "control" means the direct or indirect ownership of fifty percent (50%) or more of the outstanding capital stock or other equity interests having ordinary voting power.

1.2 "Agreement" has the meaning set forth in the Cover Sheet.

1.3 "Bankrupt" means with respect to any entity, such entity (i) files a petition or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause of action under any bankruptcy, insolvency, reorganization or similar law, or has any such petition filed or commenced against it, (ii) makes an assignment or any general arrangement for the benefit of creditors, (iii) otherwise becomes bankrupt or insolvent (however evidenced), (iv) has a liquidator, administrator, receiver, trustee, conservator or similar official appointed with respect to it or any substantial portion of its property or assets, or (v) is generally unable to pay its debts as they fall due.

1.4 "Business Day" means any day except a Saturday, Sunday, or a Federal Reserve Bank holiday. A Business Day shall open at 8:00a.m. and close at 5:00p.m. local time for the relevant Party's principal place of business. The relevant Party, in each instance unless otherwise specified, shall be the Party from whom the notice, payment or delivery is being sent and by whom the notice or payment or delivery is to be received.

1.5 "Buyer" means the Party to a Transaction that is obligated to purchase and receive, or cause to be received, the Product, as specified in the Transaction.

1.6 "Call Option" means an Option entitling, but not obligating, the Option Buyer to purchase and receive the Product from the Option Seller at a price equal to the Strike Price for the Delivery Period for which the Option may be exercised, all as specified in the Transaction. Upon proper exercise of the Option by the Option Buyer, the Option Seller will be obligated to sell and deliver the Product for the Delivery Period for which the Option has been exercised.

1.7 "Claiming Party" has the meaning set forth in Section 3.3.

1.8 "Claims" means all third party claims or actions, threatened or filed and, whether groundless, false, fraudulent or otherwise, that directly or indirectly relate to the subject matter of an indemnity, and the resulting losses, damages, expenses, attorneys' fees and court costs, whether incurred by settlement or otherwise, and whether such claims or actions are threatened or filed prior to or after the termination of this Agreement.

1.9 "Confirmation" has the meaning set forth in Section 2.3.

1.10 "Contract Price" means the price in $U.S. (unless otherwise provided for) to be paid by Buyer to Seller for the purchase of the Product, as specified in the Transaction.

1.11 "Costs" means, with respect to the Non-Defaulting Party, brokerage fees, commissions and other similar third party transaction costs and expenses reasonably incurred by such Party either in terminating any arrangement pursuant to which it has hedged its obligations or entering into new arrangements which replace a Terminated Transaction; and all reasonable attorneys' fees and expenses incurred by the Non-Defaulting Party in connection with the termination of a Transaction.

1.12 "Credit Rating" means, with respect to any entity, the rating then assigned to such entity's unsecured, senior long-term debt obligations (not supported by third party credit enhancements) or if such entity does not have a rating for its senior unsecured long-term debt, then the rating then assigned to such entity as an issues rating by S&P, Moody's or any other rating agency agreed by the Parties as set forth in the Cover Sheet.

1.13 "Cross Default Amount" means the cross default amount, if any, set forth in the Cover Sheet for a Party.

1.14 "Defaulting Party" has the meaning set forth in Section 5.1.

1.15 "Delivery Period" means the period of delivery for a Transaction, as specified in the Transaction.

1.16 "Delivery Point" means the point at which the Product will be delivered and received, as specified in the Transaction.

1.17 "Downgrade Event" has the meaning set forth on the Cover Sheet.

1.18 "Early Termination Date" has the meaning set forth in Section 5.2.

1.19 "Effective Date" has the meaning set forth on the Cover Sheet.

1.20 "Equitable Defenses" means any bankruptcy, insolvency, reorganization and other laws affecting creditors' rights generally, and with regard to equitable remedies, the discretion of the court before which proceedings to obtain same may be pending.

1.21 "Event of Default" has the meaning set forth in Section 5.1.

1.22 "FERC" means the Federal Energy Regulatory Commission or any successor government agency.

1.23 "Force Majeure" means an event or circumstance which prevents one Party from performing its obligations under one or more Transactions, which event or circumstance was not anticipated as of the date the Transaction was agreed to, which is not within the reasonable control of, or the result of the negligence of, the Claiming Party, and which, by the exercise of due diligence, the Claiming Party is unable to overcome or avoid or cause to be avoided. Force Majeure shall not be based on (i) the loss of Buyer's markets; (ii) Buyer's inability economically

to use or resell the Product purchased hereunder; (iii) the loss or failure of Seller's supply; or (iv) Seller's ability to sell the Product at a price greater than the Contract Price. Neither Party may raise a claim of Force Majeure based in whole or in part on curtailment by a Transmission Provider unless (i) such Party has contracted for firm transmission with a Transmission Provider for the Product to be delivered to or received at the Delivery Point and (ii) such curtailment is due to "force majeure" or "uncontrollable force" or a similar term as defined under the Transmission Provider's tariff; provided, however, that existence of the foregoing factors shall not be sufficient to conclusively or presumptively prove the existence of a Force Majeure absent a showing of other facts and circumstances which in the aggregate with such factors establish that a Force Majeure as defined in the first sentence hereof has occurred. The applicability of Force Majeure to the Transaction is governed by the terms of the Products and Related Definitions contained in Schedule P.

1.24 "Gains" means, with respect to any Party, an amount equal to the present value of the economic benefit to it, if any (exclusive of Costs), resulting from the termination of a Terminated Transaction, determined in a commercially reasonable manner.

1.25 "Guarantor" means, with respect to a Party, the guarantor, if any, specified for such Party on the Cover Sheet.

1.26 "Interest Rate" means, for any date, the lesser of (a) the per annum rate of interest equal to the prime lending rate as may from time to time be published in The Wall Street Journal under "Money Rates" on such day (or if not published on such day on the most recent preceding day on which published), plus two percent (2%) and (b) the maximum rate permitted by applicable law.

1.27 "Letter(s) of Credit" means one or more irrevocable, transferable standby letters of credit issued by a U.S. commercial bank or a foreign bank with a U.S. branch with such bank having a credit rating of at least A- from S&P or A3 from Moody's, in a form acceptable to the Party in whose favor the letter of credit is issued. Costs of a Letter of Credit shall be borne by the applicant for such Letter of Credit.

1.28 "Losses" means, with respect to any Party, an amount equal to the present value of the economic loss to it, if any (exclusive of Costs), resulting from termination of a Terminated Transaction, determined in a commercially reasonable manner.

1.29 "Master Agreement" has the meaning set forth on the Cover Sheet.

1.30 "Moody's" means Moody's Investor Services, Inc. or its successor.

1.31 "NERC Business Day" means any day except a Saturday, Sunday or a holiday as defined by the North American Electric Reliability Council or any successor organization thereto. A NERC Business Day shall open at 8:00 a.m. and close at 5:00 p.m. local time for the relevant Party's principal place of business. The relevant Party, in each instance unless otherwise specified, shall be the Party from whom the notice, payment or delivery is being sent and by whom the notice or payment or delivery is to be received.

1.32 "Non-Defaulting Party" has the meaning set forth in Section 5.2.

1.33 "Offsetting Transactions" mean any two or more outstanding Transactions, having the same or overlapping Delivery Period(s), Delivery Point and payment date, where under one or more of such Transactions, one Party is the Seller, and under the other such Transaction(s), the same Party is the Buyer.

1.34 "Option" means the right but not the obligation to purchase or sell a Product as specified in a Transaction.

1.35 "Option Buyer" means the Party specified in a Transaction as the purchaser of an option, as defined in Schedule P.

1.36 "Option Seller" means the Party specified in a Transaction as the seller of an option , as defined in Schedule P.

1.37 "Party A Collateral Threshold" means the collateral threshold, if any, set forth in the Cover Sheet for Party A.

1.38 "Party B Collateral Threshold" means the collateral threshold, if any, set forth in the Cover Sheet for Party B.

1.39 "Party A Independent Amount" means the amount , if any, set forth in the Cover Sheet for Party A.

1.40 "Party B Independent Amount" means the amount , if any, set forth in the Cover Sheet for Party B.

1.41 "Party A Rounding Amount" means the amount, if any, set forth in the Cover Sheet for Party A.

1.42 "Party B Rounding Amount" means the amount, if any, set forth in the Cover Sheet for Party B.

1.43 "Party A Tariff" means the tariff, if any, specified in the Cover Sheet for Party A.

1.44 "Party B Tariff" means the tariff, if any, specified in the Cover Sheet for Party B.

1.45 "Performance Assurance" means collateral in the form of either cash, Letter(s) of Credit, or other security acceptable to the Requesting Party.

1.46 "Potential Event of Default" means an event which, with notice or passage of time or both, would constitute an Event of Default.

1.47 "Product" means electric capacity, energy or other product(s) related thereto as specified in a Transaction by reference to a Product listed in Schedule P hereto or as otherwise specified by the Parties in the Transaction.

1.48 "Put Option" means an Option entitling, but not obligating, the Option Buyer to sell and deliver the Product to the Option Seller at a price equal to the Strike Price for the Delivery Period for which the option may be exercised, all as specified in a Transaction. Upon proper exercise of the Option by the Option Buyer, the Option Seller will be obligated to purchase and receive the Product.

1.49 "Quantity" means that quantity of the Product that Seller agrees to make available or sell and deliver, or cause to be delivered, to Buyer, and that Buyer agrees to purchase and receive, or cause to be received, from Seller as specified in the Transaction.

1.50 "Recording" has the meaning set forth in Section 2.4.

1.51 "Replacement Price" means the price at which Buyer, acting in a commercially reasonable manner, purchases at the Delivery Point a replacement for any Product specified in a Transaction but not delivered by Seller, plus (i) costs reasonably incurred by Buyer in purchasing such substitute Product and (ii) additional transmission charges, if any, reasonably incurred by Buyer to the Delivery Point, or at Buyer's option, the market price at the Delivery Point for such Product not delivered as determined by Buyer in a commercially reasonable manner; provided, however, in no event shall such price include any penalties, ratcheted demand or similar charges, nor shall Buyer be required to utilize or change its utilization of its owned or controlled assets or market positions to minimize Seller's liability. For the purposes of this definition, Buyer shall be considered to have purchased replacement Product to the extent Buyer shall have entered into one or more arrangements in a commercially reasonable manner whereby Buyer repurchases its obligation to sell and deliver the Product to another party at the Delivery Point.

1.52 "S&P" means the Standard & Poor's Rating Group (a division of McGraw-Hill, Inc.) or its successor.

1.53 "Sales Price" means the price at which Seller, acting in a commercially reasonable manner, resells at the Delivery Point any Product not received by Buyer, deducting from such proceeds any (i) costs reasonably incurred by Seller in reselling such Product and (ii) additional transmission charges, if any, reasonably incurred by Seller in delivering such Product to the third party purchasers, or at Seller's option, the market price at the Delivery Point for such Product not received as determined by Seller in a commercially reasonable manner; provided, however, in no event shall such price include any penalties, ratcheted demand or similar charges, nor shall Seller be required to utilize or change its utilization of its owned or controlled assets, including contractual assets, or market positions to minimize Buyer's liability. For purposes of this definition, Seller shall be considered to have resold such Product to the extent Seller shall have entered into one or more arrangements in a commercially reasonable manner whereby Seller repurchases its obligation to purchase and receive the Product from another party at the Delivery Point.

1.54 "Schedule" or "Scheduling" means the actions of Seller, Buyer and/or their designated representatives, including each Party's Transmission Providers, if applicable, of notifying, requesting and confirming to each other the quantity and type of Product to be delivered on any given day or days during the Delivery Period at a specified Delivery Point.

1.55 "Seller" means the Party to a Transaction that is obligated to sell and deliver, or cause to be delivered, the Product, as specified in the Transaction.

1.56 "Settlement Amount" means, with respect to a Transaction and the Non-Defaulting Party, the Losses or Gains, and Costs, expressed in U.S. Dollars, which such party incurs as a result of the liquidation of a Terminated Transaction pursuant to Section 5.2.

1.57 "Strike Price" means the price to be paid for the purchase of the Product pursuant to an Option.

1.58 "Terminated Transaction" has the meaning set forth in Section 5.2.

1.59 "Termination Payment" has the meaning set forth in Section 5.3.

1.60 "Transaction" means a particular transaction agreed to by the Parties relating to the sale and purchase of a Product pursuant to this Master Agreement.

1.61 "Transmission Provider" means any entity or entities transmitting or transporting the Product on behalf of Seller or Buyer to or from the Delivery Point in a particular Transaction.

ARTICLE TWO: TRANSACTION TERMS AND CONDITIONS

2.1 Transactions . A Transaction shall be entered into upon agreement of the Parties orally or, if expressly required by either Party with respect to a particular Transaction, in writing, including an electronic means of communication. Each Party agrees not to contest, or assert any defense to, the validity or enforceability of the Transaction entered into in accordance with this Master Agreement (i) based on any law requiring agreements to be in writing or to be signed by the parties, or (ii) based on any lack of authority of the Party or any lack of authority of any employee of the Party to enter into a Transaction.

2.2 Governing Terms . Unless otherwise specifically agreed, each Transaction between the Parties shall be governed by this Master Agreement. This Master Agreement (including all exhibits, schedules and any written supplements hereto), , the Party A Tariff, if any, and the Party B Tariff, if any, any designated collateral, credit support or margin agreement or similar arrangement between the Parties and all Transactions (including any Confirmations accepted in accordance with Section 2.3) shall form a single integrated agreement between the Parties. Any inconsistency between any terms of this Master Agreement and any terms of the Transaction shall be resolved in favor of the terms of such Transaction.

2.3 Confirmation . Seller may confirm a Transaction by forwarding to Buyer by facsimile within three (3) Business Days after the Transaction is entered into a confirmation ("Confirmation") substantially in the form of Exhibit A. If Buyer objects to any term(s) of such Confirmation, Buyer shall notify Seller in writing of such objections within two (2) Business Days of Buyer's receipt thereof, failing which Buyer shall be deemed to have accepted the terms as sent. If Seller fails to send a Confirmation within three (3) Business Days after the Transaction is entered into, a Confirmation substantially in the form of Exhibit A, may be forwarded by Buyer to Seller. If Seller objects to any term(s) of such Confirmation, Seller shall notify Buyer of such objections within two (2) Business Days of Seller's receipt thereof, failing

which Seller shall be deemed to have accepted the terms as sent. If Seller and Buyer each send a Confirmation and neither Party objects to the other Party's Confirmation within two (2) Business Days of receipt, Seller's Confirmation shall be deemed to be accepted and shall be the controlling Confirmation, unless (i) Seller's Confirmation was sent more than three (3) Business Days after the Transaction was entered into and (ii) Buyer's Confirmation was sent prior to Seller's Confirmation, in which case Buyer's Confirmation shall be deemed to be accepted and shall be the controlling Confirmation. Failure by either Party to send or either Party to return an executed Confirmation or any objection by either Party shall not invalidate the Transaction agreed to by the Parties.

2.4 Additional Confirmation Terms. If the Parties have elected on the Cover Sheet to make this Section 2.4 applicable to this Master Agreement, when a Confirmation contains provisions, other than those provisions relating to the commercial terms of the Transaction (e.g., price or special transmission conditions), which modify or supplement the general terms and conditions of this Master Agreement (e.g., arbitration provisions or additional representations and warranties), such provisions shall not be deemed to be accepted pursuant to Section 2.3 unless agreed to either orally or in writing by the Parties; provided that the foregoing shall not invalidate any Transaction agreed to by the Parties.

2.5 Recording 2.5Recording . Unless a Party expressly objects to a Recording (defined below) at the beginning of a telephone conversation, each Party consents to the creation of a tape or electronic recording ("Recording") of all telephone conversations between the Parties to this Master Agreement, and that any such Recordings will be retained in confidence, secured from improper access, and may be submitted in evidence in any proceeding or action relating to this Agreement. Each Party waives any further notice of such monitoring or recording, and agrees to notify its officers and employees of such monitoring or recording and to obtain any necessary consent of such officers and employees. The Recording, and the terms and conditions described therein, if admissible, shall be the controlling evidence for the Parties' agreement with respect to a particular Transaction in the event a Confirmation is not fully executed (or deemed accepted) by both Parties. Upon full execution (or deemed acceptance) of a Confirmation, such Confirmation shall control in the event of any conflict with the terms of a Recording, or in the event of any conflict with the terms of this Master Agreement.

ARTICLE THREE: OBLIGATIONS AND DELIVERIES

3.1 Seller's and Buyer's Obligations. With respect to each Transaction, Seller shall sell and deliver, or cause to be delivered, and Buyer shall purchase and receive, or cause to be received, the Quantity of the Product at the Delivery Point, and Buyer shall pay Seller the Contract Price; provided, however, with respect to Options, the obligations set forth in the preceding sentence shall only arise if the Option Buyer exercises its Option in accordance with its terms. Seller shall be responsible for any costs or charges imposed on or associated with the Product or its delivery of the Product up to the Delivery Point. Buyer shall be responsible for any costs or charges imposed on or associated with the Product or its receipt at and from the Delivery Point.

3.2 Transmission and Scheduling. Seller shall arrange and be responsible for transmission service to the Delivery Point and shall Schedule or arrange for Scheduling services

with its Transmission Providers, as specified by the Parties in the Transaction, or in the absence thereof, in accordance with the practice of the Transmission Providers, to deliver the Product to the Delivery Point. Buyer shall arrange and be responsible for transmission service at and from the Delivery Point and shall Schedule or arrange for Scheduling services with its Transmission Providers to receive the Product at the Delivery Point.

3.3 Force Majeure. To the extent either Party is prevented by Force Majeure from carrying out, in whole or part, its obligations under the Transaction and such Party (the "Claiming Party") gives notice and details of the Force Majeure to the other Party as soon as practicable, then, unless the terms of the Product specify otherwise, the Claiming Party shall be excused from the performance of its obligations with respect to such Transaction (other than the obligation to make payments then due or becoming due with respect to performance prior to the Force Majeure). The Claiming Party shall remedy the Force Majeure with all reasonable dispatch. The non-Claiming Party shall not be required to perform or resume performance of its obligations to the Claiming Party corresponding to the obligations of the Claiming Party excused by Force Majeure.

ARTICLE FOUR: REMEDIES FOR FAILURE TO DELIVER/RECEIVE

4.1 Seller Failure . If Seller fails to schedule and/or deliver all or part of the Product pursuant to a Transaction, and such failure is not excused under the terms of the Product or by Buyer's failure to perform, then Seller shall pay Buyer, on the date payment would otherwise be due in respect of the month in which the failure occurred or, if "Accelerated Payment of Damages" is specified on the Cover Sheet, within five (5) Business Days of invoice receipt, an amount for such deficiency equal to the positive difference, if any, obtained by subtracting the Contract Price from the Replacement Price. The invoice for such amount shall include a written statement explaining in reasonable detail the calculation of such amount.

4.2 Buyer Failure. If Buyer fails to schedule and/or receive all or part of the Product pursuant to a Transaction and such failure is not excused under the terms of the Product or by Seller's failure to perform, then Buyer shall pay Seller, on the date payment would otherwise be due in respect of the month in which the failure occurred or, if "Accelerated Payment of Damages" is specified on the Cover Sheet, within five (5) Business Days of invoice receipt, an amount for such deficiency equal to the positive difference, if any, obtained by subtracting the Sales Price from the Contract Price. The invoice for such amount shall include a written statement explaining in reasonable detail the calculation of such amount.

ARTICLE FIVE: EVENTS OF DEFAULT; REMEDIES

5.1 Events of Default. An "Event of Default" shall mean, with respect to a Party (a "Defaulting Party"), the occurrence of any of the following:

(a) the failure to make, when due, any payment required pursuant to this Agreement if such failure is not remedied within three (3) Business Days after written notice;

(b) any representation or warranty made by such Party herein is false or misleading in any material respect when made or when deemed made or repeated;

(c) the failure to perform any material covenant or obligation set forth in this Agreement (except to the extent constituting a separate Event of Default, and except for such Party's obligations to deliver or receive the Product, the exclusive remedy for which is provided in Article Four) if such failure is not remedied within three (3) Business Days after written notice;

(d) such Party becomes Bankrupt;

(e) the failure of such Party to satisfy the creditworthiness/collateral

requirements agreed to pursuant to Article Eight hereof;

(f) such Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all the obligations of such Party under this Agreement to which it or its predecessor was a party by operation of law or pursuant to an agreement reasonably satisfactory to the other Party;

(g) if the applicable cross default section in the Cover Sheet is indicated for such Party, the occurrence and continuation of (i) a default, event of default or other similar condition or event in respect of such Party or any other party specified in the Cover Sheet for such Party under one or more agreements or instruments, individually or collectively, relating to indebtedness for borrowed money in an aggregate amount of not less than the applicable Cross Default Amount (as specified in the Cover Sheet), which results in such indebtedness becoming, or becoming capable at such time of being declared, immediately due and payable or (ii) a default by such Party or any other party specified in the Cover Sheet for such Party in making on the due date therefor one or more payments, individually or collectively, in an aggregate amount of not less than the applicable Cross Default Amount (as specified in the Cover Sheet);

(h) with respect to such Party's Guarantor, if any:

(i) if any representation or warranty made by a Guarantor in connection with this Agreement is false or misleading in any material respect when made or when deemed made or repeated;

(ii) the failure of a Guarantor to make any payment required or to perform any other material covenant or obligation in any guaranty made in connection with this Agreement and such failure shall not be remedied within three (3) Business Days after written notice;

(iii) a Guarantor becomes Bankrupt;

(iv) the failure of a Guarantor's guaranty to be in full force and effect for purposes of this Agreement (other than in accordance with its terms) prior to the satisfaction of all obligations of such Party under each Transaction to which such guaranty shall relate without the written consent of the other Party; or

(v) a Guarantor shall repudiate, disaffirm, disclaim, or reject, in whole or in part, or challenge the validity of any guaranty.

5.2 Declaration of an Early Termination Date and Calculation of Settlement Amounts. If an Event of Default with respect to a Defaulting Party shall have occurred and be continuing, the other Party (the "Non-Defaulting Party") shall have the right (i) to designate a day, no earlier than the day such notice is effective and no later than 20 days after such notice is effective, as an early termination date ("Early Termination Date") to accelerate all amounts owing between the Parties and to liquidate and terminate all, but not less than all, Transactions (each referred to as a "Terminated Transaction") between the Parties, (ii) withhold any payments due to the Defaulting Party under this Agreement and (iii) suspend performance. The Non-Defaulting Party shall calculate, in a commercially reasonable manner, a Settlement Amount for each such Terminated Transaction as of the Early Termination Date (or, to the extent that in the reasonable opinion of the Non-Defaulting Party certain of such Terminated Transactions are commercially impracticable to liquidate and terminate or may not be liquidated and terminated under applicable law on the Early Termination Date, as soon thereafter as is reasonably practicable).

5.3 Net Out of Settlement Amounts. The Non-Defaulting Party shall aggregate all Settlement Amounts into a single amount by: netting out (a) all Settlement Amounts that are due to the Defaulting Party, plus, at the option of the Non-Defaulting Party, any cash or other form of security then available to the Non-Defaulting Party pursuant to Article Eight, plus any or all other amounts due to the Defaulting Party under this Agreement against (b) all Settlement Amounts that are due to the Non-Defaulting Party, plus any or all other amounts due to the Non-Defaulting Party under this Agreement, so that all such amounts shall be netted out to a single liquidated amount (the "Termination Payment") payable by one Party to the other. The Termination Payment shall be due to or due from the Non-Defaulting Party as appropriate.

5.4 Notice of Payment of Termination Payment. As soon as practicable after a liquidation, notice shall be given by the Non-Defaulting Party to the Defaulting Party of the amount of the Termination Payment and whether the Termination Payment is due to or due from the Non-Defaulting Party. The notice shall include a written statement explaining in reasonable detail the calculation of such amount. The Termination Payment shall be made by the Party that owes it within two (2) Business Days after such notice is effective.

5.5 Disputes With Respect to Termination Payment. If the Defaulting Party disputes the Non-Defaulting Party's calculation of the Termination Payment, in whole or in part, the Defaulting Party shall, within two (2) Business Days of receipt of Non-Defaulting Party's calculation of the Termination Payment, provide to the Non-Defaulting Party a detailed written

explanation of the basis for such dispute; provided, however, that if the Termination Payment is due from the Defaulting Party, the Defaulting Party shall first transfer Performance Assurance to the Non-Defaulting Party in an amount equal to the Termination Payment.

5.6 Closeout Setoffs.

Option A: After calculation of a Termination Payment in accordance with Section 5.3, if the Defaulting Party would be owed the Termination Payment, the Non-Defaulting Party shall be entitled, at its option and in its discretion, to (i) set off against such Termination Payment any amounts due and owing by the Defaulting Party to the Non-Defaulting Party under any other agreements, instruments or undertakings between the Defaulting Party and the Non-Defaulting Party and/or (ii) to the extent the Transactions are not yet liquidated in accordance with Section 5.2, withhold payment of the Termination Payment to the Defaulting Party. The remedy provided for in this Section shall be without prejudice and in addition to any right of setoff, combination of accounts, lien or other right to which any Party is at any time otherwise entitled (whether by operation of law, contract or otherwise).

Option B: After calculation of a Termination Payment in accordance with Section 5.3, if the Defaulting Party would be owed the Termination Payment, the Non-Defaulting Party shall be entitled, at its option and in its discretion, to (i) set off against such Termination Payment any amounts due and owing by the Defaulting Party or any of its Affiliates to the Non-Defaulting Party or any of its Affiliates under any other agreements, instruments or undertakings between the Defaulting Party or any of its Affiliates and the Non-Defaulting Party or any of its Affiliates and/or (ii) to the extent the Transactions are not yet liquidated in accordance with Section 5.2, withhold payment of the Termination Payment to the Defaulting Party. The remedy provided for in this Section shall be without prejudice and in addition to any right of setoff, combination of accounts, lien or other right to which any Party is at any time otherwise entitled (whether by operation of law, contract or otherwise).

Option C: Neither Option A nor B shall apply.

5.7 Suspension of Performance. Notwithstanding any other provision of this Master Agreement, if (a) an Event of Default or (b) a Potential Event of Default shall have occurred and be continuing, the Non-Defaulting Party, upon written notice to the Defaulting Party, shall have the right (i) to suspend performance under any or all Transactions; provided, however, in no event shall any such suspension continue for longer than ten (10) NERC Business Days with respect to any single Transaction unless an early Termination Date shall have been declared and notice thereof pursuant to Section 5.2 given, and (ii) to the extent an Event of Default shall have occurred and be continuing to exercise any remedy available at law or in equity.

ARTICLE SIX: PAYMENT AND NETTING

6.1 Billing Period. Unless otherwise specifically agreed upon by the Parties in a Transaction, the calendar month shall be the standard period for all payments under this Agreement (other than Termination Payments and, if "Accelerated Payment of Damages" is specified by the Parties in the Cover Sheet, payments pursuant to Section 4.1 or 4.2 and Option premium payments pursuant to Section 6.7). As soon as practicable after the end of each month,

each Party will render to the other Party an invoice for the payment obligations, if any, incurred hereunder during the preceding month.

6.2 Timeliness of Payment . Unless otherwise agreed by the Parties in a Transaction, all invoices under this Master Agreement shall be due and payable in accordance with each Party's invoice instructions on or before the later of the twentieth (20th) day of each month, or tenth (10th) day after receipt of the invoice or, if such day is not a Business Day, then on the next Business Day. Each Party will make payments by electronic funds transfer, or by other mutually agreeable method(s), to the account designated by the other Party. Any amounts not paid by the due date will be deemed delinquent and will accrue interest at the Interest Rate, such interest to be calculated from and including the due date to but excluding the date the delinquent amount is paid in full.

6.3 Disputes and Adjustments of Invoices . A Party may, in good faith, dispute the correctness of any invoice or any adjustment to an invoice, rendered under this Agreement or adjust any invoice for any arithmetic or computational error within twelve (12) months of the date the invoice, or adjustment to an invoice, was rendered. In the event an invoice or portion thereof, or any other claim or adjustment arising hereunder, is disputed, payment of the undisputed portion of the invoice shall be required to be made when due, with notice of the objection given to the other Party. Any invoice dispute or invoice adjustment shall be in writing and shall state the basis for the dispute or adjustment. Payment of the disputed amount shall not be required until the dispute is resolved. Upon resolution of the dispute, any required payment shall be made within two (2) Business Days of such resolution along with interest accrued at the Interest Rate from and including the due date to but excluding the date paid. Inadvertent overpayments shall be returned upon request or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Interest Rate from and including the date of such overpayment to but excluding the date repaid or deducted by the Party receiving such overpayment. Any dispute with respect to an invoice is waived unless the other Party is notified in accordance with this Section 6.3 within twelve (12) months after the invoice is rendered or any specific adjustment to the invoice is made. If an invoice is not rendered within twelve (12) months after the close of the month during which performance of a Transaction occurred, the right to payment for such performance is waived.

6.4 Netting of Payments. The Parties hereby agree that they shall discharge mutual debts and payment obligations due and owing to each other on the same date pursuant to all Transactions through netting, in which case all amounts owed by each Party to the other Party for the purchase and sale of Products during the monthly billing period under this Master Agreement, including any related damages calculated pursuant to Article Four (unless one of the Parties elects to accelerate payment of such amounts as permitted by Article Four), interest, and payments or credits, shall be netted so that only the excess amount remaining due shall be paid by the Party who owes it.

6.5 Payment Obligation Absent Netting. If no mutual debts or payment obligations exist and only one Party owes a debt or obligation to the other during the monthly billing period, including, but not limited to, any related damage amounts calculated pursuant to Article Four, interest, and payments or credits, that Party shall pay such sum in full when due.

6.6 Security. Unless the Party benefitting from Performance Assurance or a guaranty notifies the other Party in writing, and except in connection with a liquidation and termination in accordance with Article Five, all amounts netted pursuant to this Article Six shall not take into account or include any Performance Assurance or guaranty which may be in effect to secure a Party's performance under this Agreement.

6.7 Payment for Options. The premium amount for the purchase of an Option shall be paid within two (2) Business Days of receipt of an invoice from the Option Seller. Upon exercise of an Option, payment for the Product underlying such Option shall be due in accordance with Section 6.1.

6.8 Transaction Netting. If the Parties enter into one or more Transactions, which in conjunction with one or more other outstanding Transactions, constitute Offsetting Transactions, then all such Offsetting Transactions may by agreement of the Parties, be netted into a single Transaction under which:

(a) the Party obligated to deliver the greater amount of Energy will deliver the difference between the total amount it is obligated to deliver and the total amount to be delivered to it under the Offsetting Transactions, and

(b) the Party owing the greater aggregate payment will pay the net difference owed between the Parties.

Each single Transaction resulting under this Section shall be deemed part of the single, indivisible contractual arrangement between the parties, and once such resulting Transaction occurs, outstanding obligations under the Offsetting Transactions which are satisfied by such offset shall terminate.

ARTICLE SEVEN: LIMITATIONS

7.1 Limitation of Remedies, Liability and Damages. EXCEPT AS SET FORTH HEREIN, THERE IS NO WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, AND ANY AND ALL IMPLIED WARRANTIES ARE DISCLAIMED. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR'S LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED HEREIN OR IN A TRANSACTION, THE OBLIGOR'S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR

OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED HEREUNDER CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS.

ARTICLE EIGHT: CREDIT AND COLLATERAL REQUIREMENTS

8.1 Party A Credit Protection. The applicable credit and collateral requirements shall be as specified on the Cover Sheet. If no option in Section 8.1(a) is specified on the Cover Sheet, Section 8.l(a) Option C shall apply exclusively. If none of Sections 8.1(b), 8.1(c) or 8.1(d) are specified on the Cover Sheet, Section 8.1(b) shall apply exclusively.

(a) Financial Information. Option A: If requested by Party A, Party B shall deliver (i) within 120 days following the end of each fiscal year, a copy of Party B's annual report containing audited consolidated financial statements for such fiscal year and (ii) within 60 days after the end of each of its first three fiscal quarters of each fiscal year, a copy of Party B's quarterly report containing unaudited consolidated financial statements for such fiscal quarter. In all cases the statements shall be for the most recent accounting period and prepared in accordance with generally accepted accounting principles; provided, however, that should any such statements not be available on a timely basis due to a delay in preparation or certification, such delay shall not be an Event of Default so long as Party B diligently pursues the preparation, certification and delivery of the statements.

Option B: If requested by Party A, Party B shall deliver (i) within 120 days following the end of each fiscal year, a copy of the annual report containing audited consolidated financial statements for such fiscal year for the party(s) specified on the Cover Sheet and (ii) within 60 days after the end of each of its first three fiscal quarters of each fiscal year, a copy of quarterly report containing unaudited consolidated financial statements for such fiscal quarter for the party(s) specified on the Cover Sheet. In all cases the statements shall be for the most recent accounting period and shall be prepared in accordance with generally accepted accounting principles; provided, however, that should any such statements not be available on a timely basis due to a delay in preparation or certification, such delay shall not be an Event of Default so long as the relevant entity diligently pursues the preparation, certification and delivery of the statements.

Option C: Party A may request from Party B the information specified in the Cover Sheet.

(b) Credit Assurances. If Party A has reasonable grounds to believe that Party B's creditworthiness or performance under this Agreement has become unsatisfactory, Party A will provide Party B with written notice requesting Performance Assurance in an amount determined by Party A in a commercially reasonable manner. Upon receipt of such notice Party B shall have three (3) Business Days to remedy the situation by providing such Performance Assurance to Party A. In the event that Party B fails to provide such Performance Assurance, or a guaranty or other credit assurance acceptable to Party A within three (3) Business Days of receipt of notice, then an Event of Default under Article Five will be deemed to have occurred and Party A will be entitled to the remedies set forth in Article Five of this Master Agreement.

(c) Collateral Threshold. If at any time and from time to time during the term of this Agreement (and notwithstanding whether an Event of Default has occurred), the Termination Payment that would be owed to Party A plus Party B's Independent Amount, if any, exceeds the Party B Collateral Threshold, then Party A, on any Business Day, may request that Party B provide Performance Assurance in an amount equal to the amount by which the Termination Payment plus Party B's Independent Amount, if any, exceeds the Party B Collateral Threshold (rounding upwards for any fractional amount to the next Party B Rounding Amount) ("Party B Performance Assurance"), less any Party B Performance Assurance already posted with Party A. Such Party B Performance Assurance shall be delivered to Party A within three (3) Business Days of the date of such request. On any Business Day (but no more frequently than weekly with respect to Letters of Credit and daily with respect to cash), Party B, at its sole cost, may request that such Party B Performance Assurance be reduced correspondingly to the amount of such excess Termination Payment plus Party B's Independent Amount, if any, (rounding upwards for any fractional amount to the next Party B Rounding Amount). In the event that Party B fails to provide Party B Performance Assurance pursuant to the terms of this Article Eight within three (3) Business Days, then an Event of Default under Article Five shall be deemed to have occurred and Party A will be entitled to the remedies set forth in Article Five of this Master Agreement.

For purposes of this Section 8.1(c), the calculation of the Termination Payment shall be calculated pursuant to Section 5.3 by Party A as if all outstanding Transactions had been liquidated, and in addition thereto, shall include all amounts owed but not yet paid by Party B to Party A, whether or not such amounts are due, for performance already provided pursuant to any and all Transactions.

(d) Downgrade Event. If at any time there shall occur a Downgrade Event in respect of Party B, then Party A may require Party B to provide Performance Assurance in an amount determined by Party A in a commercially reasonable manner. In the event Party B shall fail to provide such Performance Assurance or a guaranty or other credit assurance acceptable to Party A within three (3) Business Days of receipt of notice, then an Event of Default shall be deemed to have occurred and Party A will be entitled to the remedies set forth in Article Five of this Master Agreement.

(e) If specified on the Cover Sheet, Party B shall deliver to Party A, prior to or concurrently with the execution and delivery of this Master Agreement a guarantee in an amount not less than the Guarantee Amount specified on the Cover Sheet and in a form reasonably acceptable to Party A.

8.2 Party B Credit Protection. The applicable credit and collateral requirements shall be as specified on the Cover Sheet. If no option in Section 8.2(a) is specified on the Cover Sheet, Section 8.2(a) Option C shall apply exclusively. If none of Sections 8.2(b), 8.2(c) or 8.2(d) are specified on the Cover Sheet, Section 8.2(b) shall apply exclusively.

(a) Financial Information. Option A: If requested by Party B, Party A shall deliver (i) within 120 days following the end of each fiscal year, a copy of Party A's annual report containing audited consolidated financial statements for such fiscal year and (ii) within 60 days after the end of each of its first three fiscal quarters of each fiscal year, a copy of such Party's quarterly report containing unaudited consolidated financial statements for such fiscal quarter. In all cases the statements shall be for the most recent accounting period and prepared in accordance with generally accepted accounting principles; provided, however, that should any such statements not be available on a timely basis due to a delay in preparation or certification, such delay shall not be an Event of Default so long as such Party diligently pursues the preparation, certification and delivery of the statements.

Option B: If requested by Party B, Party A shall deliver (i) within 120 days following the end of each fiscal year, a copy of the annual report containing audited consolidated financial statements for such fiscal year for the party(s) specified on the Cover Sheet and (ii) within 60 days after the end of each of its first three fiscal quarters of each fiscal year, a copy of quarterly report containing unaudited consolidated financial statements for such fiscal quarter for the party(s) specified on the Cover Sheet. In all cases the statements shall be for the most recent accounting period and shall be prepared in accordance with generally accepted accounting principles; provided, however, that should any such statements not be available on a timely basis due to a delay in preparation or certification, such delay shall not be an Event of Default so long as the relevant entity diligently pursues the preparation, certification and delivery of the statements.

Option C: Party B may request from Party A the information specified in the Cover Sheet.

(b) Credit Assurances. If Party B has reasonable grounds to believe that Party A's creditworthiness or performance under this Agreement has become unsatisfactory, Party B will provide Party A with written notice requesting Performance Assurance in an amount determined by Party B in a commercially reasonable manner. Upon receipt of such notice Party A shall have three (3) Business Days to remedy the situation by providing such Performance Assurance to Party B. In the event that Party A fails to provide such Performance Assurance, or a guaranty or other credit assurance acceptable to Party B within three (3) Business Days of receipt of notice, then an Event of Default under Article Five will be deemed to have occurred and Party B will be entitled to the remedies set forth in Article Five of this Master Agreement.

Threshold (rounding upwards for any fractional amount to the next Party A Rounding Amount) ("Party A Performance Assurance"), less any Party A Performance Assurance already posted with Party B. Such Party A Performance Assurance shall be delivered to Party B within three (3) Business Days of the date of such request. On any Business Day (but no more frequently than weekly with respect to Letters of Credit and daily with respect to cash), Party A, at its sole cost, may request that such Party A Performance Assurance be reduced correspondingly to the amount of such excess Termination Payment plus Party A's Independent Amount, if any, (rounding upwards for any fractional amount to the next Party A Rounding Amount). In the event that Party A fails to provide Party A Performance Assurance pursuant to the terms of this Article Eight within three (3) Business Days, then an Event of Default under Article Five shall be deemed to have occurred and Party B will be entitled to the remedies set forth in Article Five of this Master Agreement.

For purposes of this Section 8.2(c), the calculation of the Termination Payment shall be calculated pursuant to Section 5.3 by Party B as if all outstanding Transactions had been liquidated, and in addition thereto, shall include all amounts owed but not yet paid by Party A to Party B, whether or not such amounts are due, for performance already provided pursuant to any and all Transactions.

(d) Downgrade Event. If at any time there shall occur a Downgrade Event in respect of Party A, then Party B may require Party A to provide Performance Assurance in an amount determined by Party B in a commercially reasonable manner. In the event Party A shall fail to provide such Performance Assurance or a guaranty or other credit assurance acceptable to Party B within three (3) Business Days of receipt of notice, then an Event of Default shall be deemed to have occurred and Party B will be entitled to the remedies set forth in Article Five of this Master Agreement.

(e) If specified on the Cover Sheet, Party A shall deliver to Party B, prior to or concurrently with the execution and delivery of this Master Agreement a guarantee in an amount not less than the Guarantee Amount specified on the Cover Sheet and in a form reasonably acceptable to Party B.

8.3Grant of Security Interest/Remedies . To secure its obligations under this Agreement and to the extent either or both Parties deliver Performance Assurance hereunder, each Party (a "Pledgor") hereby grants to the other Party (the "Secured Party") a present and continuing security interest in, and lien on (and right of setoff against), and assignment of, all cash collateral and cash equivalent collateral and any and all proceeds resulting therefrom or the liquidation thereof, whether now or hereafter held by, on behalf of, or for the benefit of, such Secured Party, and each Party agrees to take such action as the other Party reasonably requires in order to perfect the Secured Party's first-priority security interest in, and lien on (and right of setoff against), such collateral and any and all proceeds resulting therefrom or from the liquidation thereof. Upon or any time after the occurrence or deemed occurrence and during the continuation of an Event of Default or an Early Termination Date, the Non-Defaulting Party may do any one or more of the following: (i) exercise any of the rights and remedies of a Secured Party with respect to all Performance Assurance, including any such rights and remedies under law then in effect; (ii) exercise its rights of setoff against any and all property of the Defaulting Party in the possession of the Non-Defaulting Party or its agent; (iii) draw on any outstanding

Letter of Credit issued for its benefit; and (iv) liquidate all Performance Assurance then held by or for the benefit of the Secured Party free from any claim or right of any nature whatsoever of the Defaulting Party, including any equity or right of purchase or redemption by the Defaulting Party. The Secured Party shall apply the proceeds of the collateral realized upon the exercise of any such rights or remedies to reduce the Pledgor's obligations under the Agreement (the Pledgor remaining liable for any amounts owing to the Secured Party after such application), subject to the Secured Party's obligation to return any surplus proceeds remaining after such obligations are satisfied in full.

ARTICLE NINE: GOVERNMENTAL CHARGES

9.1 Cooperation. Each Party shall use reasonable efforts to implement the provisions of and to administer this Master Agreement in accordance with the intent of the parties to minimize all taxes , so long as neither Party is materially adversely affected by such efforts.

9.2 Governmental Charges. Seller shall pay or cause to be paid all taxes imposed by any government authority("Governmental Charges") on or with respect to the Product or a Transaction arising prior to the Delivery Point. Buyer shall pay or cause to be paid all Governmental Charges on or with respect to the Product or a Transaction at and from the Delivery Point (other than ad valorem, franchise or income taxes which are related to the sale of the Product and are, therefore, the responsibility of the Seller). In the event Seller is required by law or regulation to remit or pay Governmental Charges which are Buyer's responsibility hereunder, Buyer shall promptly reimburse Seller for such Governmental Charges. If Buyer is required by law or regulation to remit or pay Governmental Charges which are Seller's responsibility hereunder, Buyer may deduct the amount of any such Governmental Charges from the sums due to Seller under Article 6 of this Agreement. Nothing shall obligate or cause a Party to pay or be liable to pay any Governmental Charges for which it is exempt under the law.

ARTICLE TEN: MISCELLANEOUS

10.1 Term of Master Agreement. The term of this Master Agreement shall commence on the Effective Date and shall remain in effect until terminated by either Party upon (thirty) 30 days' prior written notice; provided, however, that such termination shall not affect or excuse the performance of either Party under any provision of this Master Agreement that by its terms survives any such termination and, provided further, that this Master Agreement and any other documents executed and delivered hereunder shall remain in effect with respect to the Transaction(s) entered into prior to the effective date of such termination until both Parties have fulfilled all of their obligations with respect to such Transaction(s), or such Transaction(s) that have been terminated under Section 5.2 of this Agreement.

10.2 Representations and Warranties. On the Effective Date and the date of entering into each Transaction, each Party represents and warrants to the other Party that:

(i) it is duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation;

(ii) it has all regulatory authorizations necessary for it to legally perform its obligations under this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3);

(iii) the execution, delivery and performance of this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3) are within its powers, have been duly authorized by all necessary action and do not violate any of the terms and conditions in its governing documents, any contracts to which it is a party or any law, rule, regulation, order or the like applicable to it;

(iv) this Master Agreement, each Transaction (including any Confirmation accepted in accordance with Section 2.3), and each other document executed and delivered in accordance with this Master Agreement constitutes its legally valid and binding obligation enforceable against it in accordance with its terms; subject to any Equitable Defenses.

(v) it is not Bankrupt and there are no proceedings pending or being contemplated by it or, to its knowledge, threatened against it which would result in it being or becoming Bankrupt;

(vi) there is not pending or, to its knowledge, threatened against it or any of its Affiliates any legal proceedings that could materially adversely affect its ability to perform its obligations under this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3);

(vii) no Event of Default or Potential Event of Default with respect to it has occurred and is continuing and no such event or circumstance would occur as a result of its entering into or performing its obligations under this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3);

(viii) it is acting for its own account, has made its own independent decision to enter into this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3) and as to whether this Master Agreement and each such Transaction (including any Confirmation accepted in accordance with Section 2.3) is appropriate or proper for it based upon its own judgment, is not relying upon the advice or recommendations of the other Party in so doing, and is capable of assessing the merits of and understanding, and understands and accepts, the terms, conditions and risks of this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3);

(ix) it is a "forward contract merchant" within the meaning of the United States Bankruptcy Code;

(x) it has entered into this Master Agreement and each Transaction (including any Confirmation accepted in accordance with Section 2.3) in connection with the conduct of its business and it has the capacity or ability to make or take delivery of all Products referred to in the Transaction to which it is a Party;

(xi) with respect to each Transaction (including any Confirmation accepted in accordance with Section 2.3) involving the purchase or sale of a Product or an Option, it is a producer, processor, commercial user or merchant handling the Product, and it is entering into such Transaction for purposes related to its business as such; and

(xii) the material economic terms of each Transaction are subject to individual negotiation by the Parties.

10.3 Title and Risk of Loss. Title to and risk of loss related to the Product shall transfer from Seller to Buyer at the Delivery Point. Seller warrants that it will deliver to Buyer the Quantity of the Product free and clear of all liens, security interests, claims and encumbrances or any interest therein or thereto by any person arising prior to the Delivery Point.

10.4 Indemnity. Each Party shall indemnify, defend and hold harmless the other Party from and against any Claims arising from or out of any event, circumstance, act or incident first occurring or existing during the period when control and title to Product is vested in such Party as provided in Section 10.3. Each Party shall indemnify, defend and hold harmless the other Party against any Governmental Charges for which such Party is responsible under Article Nine.

10.5 Assignment. Neither Party shall assign this Agreement or its rights hereunder without the prior written consent of the other Party, which consent may be withheld in the exercise of its sole discretion; provided, however, either Party may, without the consent of the other Party (and without relieving itself from liability hereunder), (i) transfer, sell, pledge, encumber or assign this Agreement or the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements, (ii) transfer or assign this Agreement to an affiliate of such Party which affiliate's creditworthiness is equal to or higher than that of such Party, or (iii) transfer or assign this Agreement to any person or entity succeeding to all or substantially all of the assets whose creditworthiness is equal to or higher than that of such Party; provided, however, that in each such case, any such assignee shall agree in writing to be bound by the terms and conditions hereof and so long as the transferring Party delivers such tax and enforceability assurance as the non-transferring Party may reasonably request.

10.6 Governing Law. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. EACH PARTY WAIVES ITS RESPECTIVE RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY LITIGATION ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT.

10.7 Notices. All notices, requests, statements or payments shall be made as specified in the Cover Sheet. Notices (other than scheduling requests) shall, unless otherwise specified herein, be in writing and may be delivered by hand delivery, United States mail, overnight courier service or facsimile. Notice by facsimile or hand delivery shall be effective at the close of business on the day actually received, if received during business hours on a Business Day, and otherwise shall be effective at the close of business on the next Business Day. Notice by overnight United States mail or courier shall be effective on the next Business Day after it was sent. A Party may change its addresses by providing notice of same in accordance herewith.

10.8 General. This Master Agreement (including the exhibits, schedules and any written supplements hereto), the Party A Tariff, if any, the Party B Tariff, if any, any designated collateral, credit support or margin agreement or similar arrangement between the Parties and all Transactions (including any Confirmation accepted in accordance with Section 2.3) constitute the entire agreement between the Parties relating to the subject matter. Notwithstanding the foregoing, any collateral, credit support or margin agreement or similar arrangement between the Parties shall, upon designation by the Parties, be deemed part of this Agreement and shall be incorporated herein by reference. This Agreement shall be considered for all purposes as prepared through the joint efforts of the parties and shall not be construed against one party or the other as a result of the preparation, substitution, submission or other event of negotiation, drafting or execution hereof. Except to the extent herein provided for, no amendment or modification to this Master Agreement shall be enforceable unless reduced to writing and executed by both Parties. Each Party agrees if it seeks to amend any applicable wholesale power sales tariff during the term of this Agreement, such amendment will not in any way affect outstanding Transactions under this Agreement without the prior written consent of the other Party. Each Party further agrees that it will not assert, or defend itself, on the basis that any applicable tariff is inconsistent with this Agreement. This Agreement shall not impart any rights enforceable by any third party (other than a permitted successor or assignee bound to this Agreement). Waiver by a Party of any default by the other Party shall not be construed as a waiver of any other default. Any provision declared or rendered unlawful by any applicable court of law or regulatory agency or deemed unlawful because of a statutory change (individually or collectively, such events referred to as "Regulatory Event") will not otherwise affect the remaining lawful obligations that arise under this Agreement; and provided, further, that if a Regulatory Event occurs, the Parties shall use their best efforts to reform this Agreement in order to give effect to the original intention of the Parties. The term "including" when used in this Agreement shall be by way of example only and shall not be considered in any way to be in limitation. The headings used herein are for convenience and reference purposes only. All indemnity and audit rights shall survive the termination of this Agreement for twelve (12) months. This Agreement shall be binding on each Party's successors and permitted assigns.

10.9 Audit. Each Party has the right, at its sole expense and during normal working hours, to examine the records of the other Party to the extent reasonably necessary to verify the accuracy of any statement, charge or computation made pursuant to this Master Agreement. If requested, a Party shall provide to the other Party statements evidencing the Quantity delivered at the Delivery Point. If any such examination reveals any inaccuracy in any statement, the necessary adjustments in such statement and the payments thereof will be made promptly and shall bear interest calculated at the Interest Rate from the date the overpayment or underpayment was made until paid; provided, however, that no adjustment for any statement or

payment will be made unless objection to the accuracy thereof was made prior to the lapse of twelve (12) months from the rendition thereof, and thereafter any objection shall be deemed waived.

10.10 Forward Contract. The Parties acknowledge and agree that all Transactions constitute "forward contracts" within the meaning of the United States Bankruptcy Code.

10.11 Confidentiality. If the Parties have elected on the Cover Sheet to make this Section 10.11 applicable to this Master Agreement, neither Party shall disclose the terms or conditions of a Transaction under this Master Agreement to a third party (other than the Party's employees, lenders, counsel, accountants or advisors who have a need to know such information and have agreed to keep such terms confidential) except in order to comply with any applicable law, regulation, or any exchange, control area or independent system operator rule or in connection with any court or regulatory proceeding; provided, however, each Party shall, to the extent practicable, use reasonable efforts to prevent or limit the disclosure. The Parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, this confidentiality obligation.

SCHEDULE M

(THIS SCHEDULE IS INCLUDED IF THE APPROPRIATE BOX ON THE COVER SHEET IS MARKED INDICATING A PARTY IS A GOVERNMENTAL ENTITY OR PUBLIC POWER SYSTEM)

A. The Parties agree to add the following definitions in Article One.

"Act" means ______________________________. (1)

"Governmental Entity or Public Power System" means a municipality, county, governmental board, public power authority, public utility district, joint action agency, or other similar political subdivision or public entity of the United States, one or more States or territories or any combination thereof.

"Special Fund" means a fund or account of the Governmental Entity or Public Power System set aside and or pledged to satisfy the Public Power System's obligations hereunder out of which amounts shall be paid to satisfy all of the Public Power System's obligations under this Master Agreement for the entire Delivery Period.

B. The following sentence shall be added to the end of the definition of "Force Majeure" in Article One.

If the Claiming Party is a Governmental Entity or Public Power System, Force Majeure does not include any action taken by the Governmental Entity or Public Power System in its governmental capacity.

C. The Parties agree to add the following representations and warranties to Section10.2:

Further and with respect to a Party that is a Governmental Entity or Public Power System, such Governmental Entity or Public Power System represents and warrants to the other Party continuing throughout the term of this Master Agreement, with respect to this Master Agreement and each Transaction, as follows: (i) all acts necessary to the valid execution, delivery and performance of this Master Agreement, including without limitation, competitive bidding, public notice, election, referendum, prior appropriation or other required procedures has or will be taken and performed as required under the Act and the Public Power System's ordinances, bylaws or other regulations, (ii) all persons making up the governing body of Governmental Entity or Public Power System are the duly elected or appointed incumbents in their positions and hold such

_________________________

1 Cite the state enabling and other relevant statutes applicable to Governmental Entity or Public Power System.

positions in good standing in accordance with the Act and other applicable law, (iii) entry into and performance of this Master Agreement by Governmental Entity or Public Power System are for a proper public purpose within the meaning of the Act and all other relevant constitutional, organic or other governing documents and applicable law, (iv) the term of this Master Agreement does not extend beyond any applicable limitation imposed by the Act or other relevant constitutional, organic or other governing documents and applicable law, (v) the Public Power System's obligations to make payments hereunder are unsubordinated obligations and such payments are (a) operating and maintenance costs (or similar designation) which enjoy first priority of payment at all times under any and all bond ordinances or indentures to which it is a party, the Act and all other relevant constitutional, organic or other governing documents and applicable law or (b) otherwise not subject to any prior claim under any and all bond ordinances or indentures to which it is a party, the Act and all other relevant constitutional, organic or other governing documents and applicable law and are available without limitation or deduction to satisfy all Governmental Entity or Public Power System' obligations hereunder and under each Transaction or (c) are to be made solely from a Special Fund, (vi) entry into and performance of this Master Agreement and each Transaction by the Governmental Entity or Public Power System will not adversely affect the exclusion from gross income for federal income tax purposes of interest on any obligation of Governmental Entity or Public Power System otherwise entitled to such exclusion, and (vii) obligations to make payments hereunder do not constitute any kind of indebtedness of Governmental Entity or Public Power System or create any kind of lien on, or security interest in, any property or revenues of Governmental Entity or Public Power System which, in either case, is proscribed by any provision of the Act or any other relevant constitutional, organic or other governing documents and applicable law, any order or judgment of any court or other agency of government applicable to it or its assets, or any contractual restriction binding on or affecting it or any of its assets.

D. The Parties agree to add the following sections to Article Three:

Section 3.4 Public Power System's Deliveries. On the Effective Date and as a condition to the obligations of the other Party under this Agreement, Governmental Entity or Public Power System shall provide the other Party hereto (i) certified copies of all ordinances, resolutions, public notices and other documents evidencing the necessary authorizations with respect to the execution, delivery and performance by Governmental Entity or Public Power System of this Master Agreement and (ii) an opinion of counsel for Governmental Entity or Public Power System, in form and substance reasonably satisfactory to the Other Party, regarding the validity, binding effect and enforceability of this Master Agreement against Governmental Entity or Public Power System in

respect of the Act and all other relevant constitutional organic or other governing documents and applicable law.

Section 3.5 No Immunity Claim. Governmental Entity or Public Power System warrants and covenants that with respect to its contractual obligations hereunder and performance thereof, it will not claim immunity on the grounds of sovereignty or similar grounds with respect to itself or its revenues or assets from (a) suit, (b) jurisdiction of court (including a court located outside the jurisdiction of its organization), (c) relief by way of injunction, order for specific performance or recovery of property, (d) attachment of assets, or (e) execution or enforcement of any judgment.

E. If the appropriate box is checked on the Cover Sheet, as an alternative to selecting one of the options under Section 8.3, the Parties agree to add the following section to Article Three:

Section 3.6 Governmental Entity or Public Power System Security. With respect to each Transaction, Governmental Entity or Public Power System shall either (i) have created and set aside a Special Fund or (ii) upon execution of this Master Agreement and prior to the commencement of each subsequent fiscal year of Governmental Entity or Public Power System during any Delivery Period, have obtained all necessary budgetary approvals and certifications for payment of all of its obligations under this Master Agreement for such fiscal year; any breach of this provision shall be deemed to have arisen during a fiscal period of Governmental Entity or Public Power System for which budgetary approval or certification of its obligations under this Master Agreement is in effect and, notwithstanding anything to the contrary in Article Four, an Early Termination Date shall automatically and without further notice occur hereunder as of such date wherein Governmental Entity or Public Power System shall be treated as the Defaulting Party. Governmental Entity or Public Power System shall have allocated to the Special Fund or its general funds a revenue base that is adequate to cover Public Power System's payment obligations hereunder throughout the entire Delivery Period.

F. If the appropriate box is checked on the Cover Sheet, the Parties agree to add the following section to Article Eight:

Section 8.4 Governmental Security. As security for payment and performance of Public Power System's obligations hereunder, Public Power System hereby pledges, sets over, assigns and grants to the other Party a security interest in all of Public Power System's right, title and interest in and to [specify collateral].

G. The Parties agree to add the following sentence at the end of Section 10.6 - Governing Law:

NOTWITHSTANDING THE FOREGOING, IN RESPECT OF THE APPLICABILITY OF THE ACT AS HEREIN PROVIDED, THE LAWS OF THE STATE OF _____________ (2) SHALL APPLY.

_____________________

2 Insert relevant state for Governmental Entity or Public Power System.

SCHEDULE P: PRODUCTS AND RELATED DEFINITIONS

"Ancillary Services" means any of the services identified by a Transmission Provider in its transmission tariff as "ancillary services" including, but not limited to, regulation and frequency response, energy imbalance, operating reserve-spinning and operating reserve-supplemental, as may be specified in the Transaction.

"Capacity" has the meaning specified in the Transaction.

"Energy" means three-phase, 60-cycle alternating current electric energy, expressed in megawatt hours.

"Firm (LD)" means, with respect to a Transaction, that either Party shall be relieved of its obligations to sell and deliver or purchase and receive without liability only to the extent that, and for the period during which, such performance is prevented by Force Majeure. In the absence of Force Majeure, the Party to which performance is owed shall be entitled to receive from the Party which failed to deliver/receive an amount determined pursuant to Article Four.

"Firm Transmission Contingent - Contract Path" means, with respect to a Transaction, that the performance of either Seller or Buyer (as specified in the Transaction) shall be excused, and no damages shall be payable including any amounts determined pursuant to Article Four, if the transmission for such Transaction is interrupted or curtailed and (i) such Party has provided for firm transmission with the transmission provider(s) for the Product in the case of the Seller from the generation source to the Delivery Point or in the case of the Buyer from the Delivery Point to the ultimate sink, and (ii) such interruption or curtailment is due to "force majeure" or "uncontrollable force" or a similar term as defined under the applicable transmission provider's tariff. This contingency shall excuse performance for the duration of the interruption or curtailment notwithstanding the provisions of the definition of "Force Majeure" in Section 1.23 to the contrary.

"Firm Transmission Contingent - Delivery Point" means, with respect to a Transaction, that the performance of either Seller or Buyer (as specified in the Transaction) shall be excused, and no damages shall be payable including any amounts determined pursuant to Article Four, if the transmission to the Delivery Point (in the case of Seller) or from the Delivery Point (in the case of Buyer) for such Transaction is interrupted or curtailed and (i) such Party has provided for firm transmission with the transmission provider(s) for the Product, in the case of the Seller, to be delivered to the Delivery Point or, in the case of Buyer, to be received at the Delivery Point and (ii) such interruption or curtailment is due to "force majeure" or "uncontrollable force" or a similar term as defined under the applicable transmission provider's tariff. This transmission contingency excuses performance for the duration of the interruption or curtailment, notwithstanding the provisions of the definition of "Force Majeure" in Section 1.23 to the contrary. Interruptions or curtailments of transmission other than the transmission either immediately to or from the Delivery Point shall not excuse performance

"Firm (No Force Majeure)" means, with respect to a Transaction, that if either Party fails to perform its obligation to sell and deliver or purchase and receive the Product, the Party to which performance is owed shall be entitled to receive from the Party which failed to perform an

amount determined pursuant to Article Four. Force Majeure shall not excuse performance of a Firm (No Force Majeure) Transaction.

"Into ______________ (the "Receiving Transmission Provider"), Seller's Daily Choice" means that, in accordance with the provisions set forth below, (1) the Product shall be scheduled and delivered to an interconnection or interface ("Interface") either (a) on the Receiving Transmission Provider's transmission system border or (b) within the control area of the Receiving Transmission Provider if the Product is from a source of generation in that control area, which Interface, in either case, the Receiving Transmission Provider identifies as available for delivery of the Product in or into its control area; and (2) Seller has the right on a daily prescheduled basis to designate the Interface where the Product shall be delivered. An "Into" Product shall be subject to the following provisions:

1. Prescheduling and Notification. Subject to the provisions of Section 6, not later than the prescheduling deadline of 11:00 a.m. CPT on the Business Day before the next delivery day or as otherwise agreed to by Buyer and Seller, Seller shall notify Buyer ("Seller's Notification") of Seller's immediate upstream counterparty and the Interface (the "Designated Interface") where Seller shall deliver the Product for the next delivery day, and Buyer shall notify Seller of Buyer's immediate downstream counterparty.

2. Availability of "Firm Transmission" to Buyer at Designated Interface; "Timely Request for Transmission," "ADI" and "Available Transmission." In determining availability to Buyer of next-day firm transmission ("Firm Transmission") from the Designated Interface, a "Timely Request for Transmission" shall mean a properly completed request for Firm Transmission made by Buyer in accordance with the controlling tariff procedures, which request shall be submitted to the Receiving Transmission Provider no later than 30 minutes after delivery of Seller's Notification, provided, however, if the Receiving Transmission Provider is not accepting requests for Firm Transmission at the time of Seller's Notification, then such request by Buyer shall be made within 30 minutes of the time when the Receiving Transmission Provider first opens thereafter for purposes of accepting requests for Firm Transmission.

Pursuant to the terms hereof, delivery of the Product may under certain circumstances be redesignated to occur at an Interface other than the Designated Interface (any such alternate designated interface, an "ADI") either (a) on the Receiving Transmission Provider's transmission system border or (b) within the control area of the Receiving Transmission Provider if the Product is from a source of generation in that control area, which ADI, in either case, the Receiving Transmission Provider identifies as available for delivery of the Product in or into its control area using either firm or non-firm transmission, as available on a day-ahead or hourly basis (individually or collectively referred to as "Available Transmission") within the Receiving Transmission Provider's transmission system.

3. Rights of Buyer and Seller Depending Upon Availability of/Timely Request for Firm Transmission.

A. Timely Request for Firm Transmission made by Buyer, Accepted by the Receiving Transmission Provider and Purchased by Buyer. If a Timely Request for Firm Transmission is made by Buyer and is accepted by the Receiving Transmission Provider

and Buyer purchases such Firm Transmission, then Seller shall deliver and Buyer shall receive the Product at the Designated Interface.

i. If the Firm Transmission purchased by Buyer within the Receiving Transmission Provider's transmission system from the Designated Interface ceases to be available to Buyer for any reason, or if Seller is unable to deliver the Product at the Designated Interface for any reason except Buyer's non-performance, then at Seller's choice from among the following, Seller shall: (a) to the extent Firm Transmission is available to Buyer from an ADI on a day-ahead basis, require Buyer to purchase such Firm Transmission from such ADI, and schedule and deliver the affected portion of the Product to such ADI on the basis of Buyer's purchase of Firm Transmission, or (b) require Buyer to purchase non-firm transmission, and schedule and deliver the affected portion of the Product on the basis of Buyer's purchase of non-firm transmission from the Designated Interface or an ADI designated by Seller, or (c) to the extent firm transmission is available on an hourly basis, require Buyer to purchase firm transmission, and schedule and deliver the affected portion of the Product on the basis of Buyer's purchase of such hourly firm transmission from the Designated Interface or an ADI designated by Seller.

ii. If the Available Transmission utilized by Buyer as required by Seller pursuant to Section 3A(i) ceases to be available to Buyer for any reason, then Seller shall again have those alternatives stated in Section 3A(i) in order to satisfy its obligations.

iii. Seller's obligation to schedule and deliver the Product at an ADI is subject to Buyer's obligation referenced in Section 4B to cooperate reasonably therewith. If Buyer and Seller cannot complete the scheduling and/or delivery at an ADI, then Buyer shall be deemed to have satisfied its receipt obligations to Seller and Seller shall be deemed to have failed its delivery obligations to Buyer, and Seller shall be liable to Buyer for amounts determined pursuant to Article Four.

iv. In each instance in which Buyer and Seller must make alternative scheduling arrangements for delivery at the Designated Interface or an ADI pursuant to Sections 3A(i) or (ii), and Firm Transmission had been purchased by both Seller and Buyer into and within the Receiving Transmission Provider's transmission system as to the scheduled delivery which could not be completed as a result of the interruption or curtailment of such Firm Transmission, Buyer and Seller shall bear their respective transmission expenses and/or associated congestion charges incurred in connection with efforts to complete delivery by such alternative scheduling and delivery arrangements. In any instance except as set forth in the immediately preceding sentence, Buyer and Seller must make alternative scheduling arrangements for delivery at the Designated Interface or an ADI under Sections 3A(i) or (ii), Seller shall be responsible for any additional transmission purchases and/or associated congestion charges incurred by Buyer in connection with such alternative scheduling arrangements.

B. Timely Request for Firm Transmission Made by Buyer but Rejected by the Receiving Transmission Provider. If Buyer's Timely Request for Firm Transmission is rejected by the Receiving Transmission Provider because of unavailability of Firm Transmission from the Designated Interface, then Buyer shall notify Seller within 15 minutes after receipt of the Receiving Transmission Provider's notice of rejection ("Buyer's Rejection Notice"). If Buyer timely notifies Seller of such unavailability of Firm Transmission from the Designated Interface, then Seller shall be obligated either (1) to the extent Firm Transmission is available to Buyer from an ADI on a day-ahead basis, to require Buyer to purchase (at Buyer's own expense) such Firm Transmission from such ADI and schedule and deliver the Product to such ADI on the basis of Buyer's purchase of Firm Transmission, and thereafter the provisions in Section 3A shall apply, or (2) to require Buyer to purchase (at Buyer's own expense) non-firm transmission, and schedule and deliver the Product on the basis of Buyer's purchase of non-firm transmission from the Designated Interface or an ADI designated by the Seller, in which case Seller shall bear the risk of interruption or curtailment of the non-firm transmission; provided, however, that if the non-firm transmission is interrupted or curtailed or if Seller is unable to deliver the Product for any reason, Seller shall have the right to schedule and deliver the Product to another ADI in order to satisfy its delivery obligations, in which case Seller shall be responsible for any additional transmission purchases and/or associated congestion charges incurred by Buyer in connection with Seller's inability to deliver the Product as originally prescheduled. If Buyer fails to timely notify Seller of the unavailability of Firm Transmission, then Buyer shall bear the risk of interruption or curtailment of transmission from the Designated Interface, and the provisions of Section 3D shall apply.

C. Timely Request for Firm Transmission Made by Buyer, Accepted by the Receiving Transmission Provider and not Purchased by Buyer. If Buyer's Timely Request for Firm Transmission is accepted by the Receiving Transmission Provider but Buyer elects to purchase non-firm transmission rather than Firm Transmission to take delivery of the Product, then Buyer shall bear the risk of interruption or curtailment of transmission from the Designated Interface. In such circumstances, if Seller's delivery is interrupted as a result of transmission relied upon by Buyer from the Designated Interface, then Seller shall be deemed to have satisfied its delivery obligations to Buyer, Buyer shall be deemed to have failed to receive the Product and Buyer shall be liable to Seller for amounts determined pursuant to Article Four.

D. No Timely Request for Firm Transmission Made by Buyer, or Buyer Fails to Timely Send Buyer's Rejection Notice. If Buyer fails to make a Timely Request for Firm Transmission or Buyer fails to timely deliver Buyer's Rejection Notice, then Buyer shall bear the risk of interruption or curtailment of transmission from the Designated Interface. In such circumstances, if Seller's delivery is interrupted as a result of transmission relied upon by Buyer from the Designated Interface, then Seller shall be deemed to have satisfied its delivery obligations to Buyer, Buyer shall be deemed to have failed to receive the Product and Buyer shall be liable to Seller for amounts determined pursuant to Article Four.

4. Transmission.

A. Seller's Responsibilities. Seller shall be responsible for transmission required to deliver the Product to the Designated Interface or ADI, as the case may be. It is expressly agreed that Seller is not required to utilize Firm Transmission for its delivery obligations hereunder, and Seller shall bear the risk of utilizing non-firm transmission. If Seller's scheduled delivery to Buyer is interrupted as a result of Buyer's attempted transmission of the Product beyond the Receiving Transmission Provider's system border, then Seller will be deemed to have satisfied its delivery obligations to Buyer, Buyer shall be deemed to have failed to receive the Product and Buyer shall be liable to Seller for damages pursuant to Article Four.

B. Buyer's Responsibilities. Buyer shall be responsible for transmission required to receive and transmit the Product at and from the Designated Interface or ADI, as the case may be, and except as specifically provided in Section 3A and 3B, shall be responsible for any costs associated with transmission therefrom. If Seller is attempting to complete the designation of an ADI as a result of Seller's rights and obligations hereunder, Buyer shall co-operate reasonably with Seller in order to effect such alternate designation.

5. Force Majeure. An "Into" Product shall be subject to the "Force Majeure"

provisions in Section 1.23.

6. Multiple Parties in Delivery Chain Involving a Designated Interface. Seller and Buyer recognize that there may be multiple parties involved in the delivery and receipt of the Product at the Designated Interface or ADI to the extent that (1) Seller may be purchasing the Product from a succession of other sellers ("Other Sellers"), the first of which Other Sellers shall be causing the Product to be generated from a source ("Source Seller") and/or (2) Buyer may be selling the Product to a succession of other buyers ("Other Buyers"), the last of which Other Buyers shall be using the Product to serve its energy needs ("Sink Buyer"). Seller and Buyer further recognize that in certain Transactions neither Seller nor Buyer may originate the decision as to either (a) the original identification of the Designated Interface or ADI (which designation may be made by the Source Seller) or (b) the Timely Request for Firm Transmission or the purchase of other Available Transmission (which request may be made by the Sink Buyer). Accordingly, Seller and Buyer agree as follows:

A. If Seller is not the Source Seller, then Seller shall notify Buyer of the Designated Interface promptly after Seller is notified thereof by the Other Seller with whom Seller has a contractual relationship, but in no event may such designation of the Designated Interface be later than the prescheduling deadline pertaining to the Transaction between Buyer and Seller pursuant to Section 1.

B. If Buyer is not the Sink Buyer, then Buyer shall notify the Other Buyer with whom Buyer has a contractual relationship of the Designated Interface promptly after Seller notifies Buyer thereof, with the intent being that the party bearing actual responsibility to secure transmission shall have up to 30 minutes after receipt of the Designated Interface to submit its Timely Request for Firm Transmission.

C. Seller and Buyer each agree that any other communications or actions required to be given or made in connection with this "Into Product" (including without limitation, information relating to an ADI) shall be made or taken promptly after receipt of the relevant information from the Other Sellers and Other Buyers, as the case may be.

D. Seller and Buyer each agree that in certain Transactions time is of the essence and it may be desirable to provide necessary information to Other Sellers and Other Buyers in order to complete the scheduling and delivery of the Product. Accordingly, Seller and Buyer agree that each has the right, but not the obligation, to provide information at its own risk to Other Sellers and Other Buyers, as the case may be, in order to effect the prescheduling, scheduling and delivery of the Product

"Native Load" means the demand imposed on an electric utility or an entity by the requirements of retail customers located within a franchised service territory that the electric utility or entity has statutory obligation to serve.

"Non-Firm" means, with respect to a Transaction, that delivery or receipt of the Product may be interrupted for any reason or for no reason, without liability on the part of either Party.

"System Firm" means that the Product will be supplied from the owned or controlled generation or pre-existing purchased power assets of the system specified in the Transaction (the "System") with non-firm transmission to and from the Delivery Point, unless a different Transmission Contingency is specified in a Transaction. Seller's failure to deliver shall be excused: (i) by an event or circumstance which prevents Seller from performing its obligations, which event or circumstance was not anticipated as of the date the Transaction was agreed to, which is not within the reasonable control of, or the result of the negligence of, the Seller; (ii) by Buyer's failure to perform; (iii) to the extent necessary to preserve the integrity of, or prevent or limit any instability on, the System; (iv) to the extent the System or the control area or reliability council within which the System operates declares an emergency condition, as determined in the system's, or the control area's, or reliability council's reasonable judgment; or (v) by the interruption or curtailment of transmission to the Delivery Point or by the occurrence of any Transmission Contingency specified in a Transaction as excusing Seller's performance. Buyer's failure to receive shall be excused (i) by Force Majeure; (ii) by Seller's failure to perform, or (iii) by the interruption or curtailment of transmission from the Delivery Point or by the occurrence of any Transmission Contingency specified in a Transaction as excusing Buyer's performance. In any of such events, neither party shall be liable to the other for any damages, including any amounts determined pursuant to Article Four.

"Transmission Contingent" means, with respect to a Transaction, that the performance of either Seller or Buyer (as specified in the Transaction) shall be excused, and no damages shall be payable including any amounts determined pursuant to Article Four, if the transmission for such Transaction is unavailable or interrupted or curtailed for any reason, at any time, anywhere from the Seller's proposed generating source to the Buyer's proposed ultimate sink, regardless of whether transmission, if any, that such Party is attempting to secure and/or has purchased for the Product is firm or non-firm. If the transmission (whether firm or non-firm) that Seller or Buyer is attempting to secure is from source to sink is unavailable, this contingency excuses performance for the entire Transaction. If the transmission (whether firm or non-firm) that

Seller or Buyer has secured from source to sink is interrupted or curtailed for any reason, this contingency excuses performance for the duration of the interruption or curtailment notwithstanding the provisions of the definition of "Force Majeure" in Article 1.23 to the contrary.

"Unit Firm" means, with respect to a Transaction, that the Product subject to the Transaction is intended to be supplied from a generation asset or assets specified in the Transaction. Seller's failure to deliver under a "Unit Firm" Transaction shall be excused: (i) if the specified generation asset(s) are unavailable as a result of a Forced Outage (as defined in the NERC Generating Unit Availability Data System (GADS) Forced Outage reporting guidelines) or (ii) by an event or circumstance that affects the specified generation asset(s) so as to prevent Seller from performing its obligations, which event or circumstance was not anticipated as of the date the Transaction was agreed to, and which is not within the reasonable control of, or the result of the negligence of, the Seller or (iii) by Buyer's failure to perform. In any of such events, Seller shall not be liable to Buyer for any damages, including any amounts determined pursuant to Article Four.

EXHIBIT A: CONFIRMATION LETTER

MASTER POWER PURCHASE AND SALE AGREEMENT

CONFIRMATION LETTER

This confirmation letter shall confirm the Transaction agreed to on__________, ___ between ________________________ ("Party A") and _____________________ ("Party B") regarding the sale/purchase of the Product under the terms and conditions as follows:

Seller:

Buyer:

Product:

[] Into _________________, Seller's Daily Choice

[] Firm (LD)

[] Firm (No Force Majeure)

[] System Firm

(Specify System: )

[] Unit Firm

(Specify Unit(s): )

[] Other

[] Transmission Contingency (If not marked, no transmission contingency)

[] FT-Contract Path Contingency [] Seller [] Buyer

[] FT-Delivery Point Contingency [] Seller [] Buyer

[] Transmission Contingent [] Seller [] Buyer

[] Other transmission contingency

(Specify: )

Contract Quantity:

Delivery Point:

Contract Price:

Energy Price:

Other Charges:

Confirmation Letter

Page 2

Delivery Period:

Special Conditions:

Scheduling:

Option Buyer:

Option Seller:

Type of Option:

Strike Price:

Premium:

Exercise Period:

This confirmation letter is being provided pursuant to and in accordance with the Master Power Purchase and Sale Agreement dated ______________ (the "Master Agreement") between Party A and Party B, and constitutes part of and is subject to the terms and provisions of such Master Agreement. Terms used but not defined herein shall have the meanings ascribed to them in the Master Agreement.

[Party A] [Party B]

Name: Name:

Title: Title:

Phone No: Phone No:

Fax: Fax:

Addendum to the

Master Power Purchase and Sales Agreement (EEI)

Between Duke Energy Trading and Marketing, L.L.C.

and

Energy Atlantic LLC

dated

September 19, 2001

The above-referenced Master Power Purchase and Sales Agreement (the "Agreement") between Duke Energy Trading and Marketing, L.L.C. ("DETM") and Energy Atlantic LLC ("Energy Atlantic") shall be revised as follows:

Cover Sheet: The address information and related terms and conditions attached to this Addendum shall be incorporated into the Cover Sheet and the Agreement.

Section 1.23: Delete the words "provided, however, that existence of the foregoing factors shall not be sufficient to conclusively or presumptively prove the existence of a Force Majeure absent a showing of other facts and circumstances which in the aggregate with such factors establish that a Force Majeure as defined in the first sentence hereof has occurred."

Section 1.50: Delete the words "Section 2.4" and replace with "Section 2.5."

1.62: Add new section:

"Collateral Interest Rate" will be a per annum rate of interest equal to the Federal Funds Rate. "Federal Funds Rate" means, for any day, an interest rate per annum equal to either (A) the rate published as the Overnight Federal Funds Effective Rate that appears on the Telerate Page 118 for such day (or, if such day is not a Business Day, for the preceding Business Day) or (B) if such rate is not so published for any day which is a Business Day, the Federal Funds Rate as published by the Federal Reserve Bank in H.15 (519).

Section 2.1: Add the following as a second paragraph:

The Parties may have entered into power purchases and sales prior to the execution of this Agreement ("Existing Transactions"), which are currently subject to an existing contract ("Existing Agreement") including, but not limited to, the WSPP Agreement, the MAPP Restated Service Agreement, or a bilateral agreement between the Parties. Effective as of the date of this Agreement, these Existing Transactions shall for all purposes be Transactions hereunder and shall be subject to all the terms of this Agreement, except that (1) all service level/product definitions; (2) the regional reliability requirements and guidelines; and (3) Force Majeure/Uncontrollable Force definitions shall have the meaning ascribed to them in the Existing Agreement in effect on the date the Transaction was entered into.

Section 2.3: The word "may" in the first line shall be changed to "shall."

Section 3.3: The following shall be inserted at the end of the first sentence: "for so long as the event or condition of Force Majeure is in effect."

Section 4: Add the following as Section 4.3 to the Agreement:

Suspension of Performance for Failure to Deliver/Receive. Notwithstanding, and in addition to the remedies provided pursuant to Sections 4.1 and 4.2, if Seller or Buyer fails to schedule and/or deliver/receive all or part of the Product pursuant to a transaction, and such failure is not excused under the terms of the Product or by the other Party's failure to perform, then upon one (1) Business Day prior notice, and for so long as the non-performing Party fails to perform, the performing Party shall have the right to suspend its performance under any or all Transactions.

Section 5.1 (g), Subsection (i): Delete the words "event of default" and replace with the words "Event of Default." in the second and third lines.

Section 5.1 (g): Delete the words "or becoming capable at such time of being declared," after the word "becoming" and before the word "immediately" in the eighth and ninth lines.

Section 5.1(h): The following shall be inserted as subparagraph (vi):

(vi) if the applicable cross default section in the Cover Sheet is indicated for such Guarantor, the occurrence and continuation of (i) a default, event of default or other similar condition or event in respect of such Guarantor or any other party specified in the Cover Sheet for such Guarantor under one or more agreements or instruments, individually or collectively, relating to indebtedness for borrowed money in an aggregate amount of not less than the applicable Cross Default Amount (as specified in the Cover Sheet), which results in such indebtedness becoming immediately due and payable or (ii) a default by such Guarantor in making on the due date therefor one or more payments, individually or collectively, in an aggregate amount of not less than the applicable Cross Default Amount (as specified in the Cover Sheet).

Section 5.1: Add a new Section 5.1(i) that reads the "default by a Party under any other agreement between the Parties including but not limited to any commodity or financial derivative agreement or transaction."

Section 5.2: Add the phase, "or with respect to its Guarantor" after the first use of the phrase, "Defaulting Party" in the second line.

Section 5.3: Add the phrase "plus, at the option of the Non-Defaulting Party, any cash or other form of liquid security then in the possession of the Defaulting Party or its agent pursuant to Article Eight," after the first use of the phrase "due to the Non-Defaulting Party" in the sixth line.

Section 5.4:

The following shall be inserted after "liquidation" in the second line: "and termination of a Transaction pursuant to Section 5.2."

Add the following to the end of the paragraph:

"Notwithstanding any provision to the contrary contained in this Agreement, the Non-Defaulting Party shall not be required to pay the Defaulting Party any amount under Article 5 until the Non-Defaulting Party receives confirmation satisfactory to it in its reasonable discretion that all other obligations of any kind whatsoever of the Defaulting Party to make any payments to the Non-Defaulting Party under this Agreement or otherwise which are due and payable as of the Early Termination Date have been fully and finally performed. Each Party hereby grants to the other Party a continuing security interest in all of its right, title and interest in, to and under any Commodity Contract, Forward Contract, and Swap Agreement, (each as defined in the United States Bankruptcy Code) between the Parties (collectively the "Financial Contracts"), together with all proceeds thereof (the "Collateral") in order to margin, guaranty, secure or settle the performance and payment of its obligations owing under each and every Financial Contract (the "Secured Obligations")."

Section 5.6 (Option A): The following shall be added to the end of the first sentence: "until the Transaction is liquidated pursuant to Section 5.2."

Section 5.7:

The letter "(a)" and the phrase "or (b) a Potential Event of Default" shall be removed.

Add "and Return of Performance Assurance" after the word "Performance" in the title of this section.

At the end of the paragraph, add "Upon the occurrence of an event described above the Defaulting Party shall immediately return all Performance Assurances provided by the Non-Defaulting Party pursuant to this Agreement."

Section 8.1(c) and 8.2(c) Add at the end of the second paragraph: "Notwithstanding anything herein to the contrary, for purposes of this provision, the calculation of Termination Payment shall exclude Costs."

Section 8.1(c) Amend to add the following in line 14 after the "." and before "In":

"In the event some or all of the Party B Performance Assurance is in the form of cash, upon the return by Party A of such cash, Party A shall include a payment to Party B of interest calculated at the Collateral Interest Rate for the period the cash was held by Party A excluding the date in which such cash is returned."

Section 8.1(d): After the comma in line five, add "or fails to maintain such Performance Assurance or guaranty or other credit assurance for so long as the Downgrade Event is continuing."

Section 8.2: In (ii) under "Option B," replace "unaudited" with "audited" and insert "if possible" after "Cover Sheet" at the end of that sentence.

Section 8.2(c): Amend to add the following in line 14 after the "." and before "In":

"In the event some or all of the Party A Performance Assurance is in the form of cash, upon the return by Party B of such cash, Party B shall include a payment to Party A of interest calculated at the Collateral Interest Rate for the period the cash was held by Party B excluding the date in which such cash is returned."

Section 8.2(d): After the comma in line five, add "or fails to maintain such Performance Assurance or guaranty or other credit assurance for so long as the Downgrade Event is continuing."

Section 8.3: Add the following as a second paragraph: "For purposes of this Master Agreement, "collateral" shall not include Energy Atlantic receivables or the proceeds thereof that do not result from the sale of Product under this Master Agreement. "Cash collateral" shall specifically exclude such receivables but shall include cash posted as collateral hereunder by either Party.

Section 9.2: Insert the following after "government authority:" in the second line: "or other changes imposed by rule, regulation or order."

Section 10.4: Delete the word "arising" and replace it with "to the extent such Claims arise" in the second line. Add the following as a second paragraph:

"If any legal proceedings shall be instituted or any claim or demand shall be asserted by any third party in respect of which indemnification may be sought by either Party hereto, the Party seeking indemnification (the "Indemnitee") shall give prompt written notice of the legal proceedings or the assertion of any claim or demand of which it has knowledge that is covered by the indemnity under this Agreement to be forwarded to the Party from which indemnification is sought (the "Indemnitor"). Within 30 days after delivery of such notification, the Indemnitor may, upon written notice thereof to the Indemnitee, assume control of the defense of such action, suit, proceeding or claim with counsel reasonably satisfactory to the Indemnitee. If the Indemnitor does not assume control of such defense, the Indemnitee shall control such defense. The Party not controlling such defense may participate therein at its own expense; provided that if the Indemnitor assumes control of such defense and the Indemnitee reasonably concludes, based on advice from counsel, that the Indemnitor and the Indemnitee have conflicting interests with respect to such action, suit, proceeding or claim, the reasonable fees and expenses of counsel to the Indemnitee solely in connection therewith shall be considered indemnifiable costs for purposes of this Agreement; provided, however, that in no event

shall the Indemnitor be responsible for the fees and expenses of more than one counsel for the Indemnitee. The Party controlling such defense shall keep the other Party advised of the status of such action, suit, proceeding or claim and the defense thereof and shall consider recommendations made by the other Party with respect thereto. The Indemnitee shall not agree to any settlement of such action, suit, proceeding or claim without the prior written consent of the Indemnitor. The Indemnitor shall not agree to any settlement of such action, suit, proceeding or claim that does not include a complete release of the Indemnitee from all liability with respect thereto or that imposes any liability or obligation on the Indemnitee without the prior written consent of the Indemnitee, which shall not be unreasonably withheld, conditioned or delayed."

Section 10.5: Delete the words "which consent may be withheld in the exercise of its sole discretion" and replace with the words "which consent shall not be unreasonably withheld."

Section 10.11: Add "Affiliates" after "accountants" in the fourth line.

Section 10.12: Add new section:

Calculation of Termination Payment. For the purposes of calculating a Termination Payment pursuant to Article 5 and 8, the Parties may include Settlement Amounts for any and all other transactions between them for the physical purchase and sale of power, including options, whether or not such other transactions are governed by this Master Agreement.

Section 10.13 Add new section:

Arbitration and Legal Recourse.

10.13.1. Any unresolved controversy or claim arising out of or relating to this Agreement involving amounts less than $5,000,000 shall be settled by arbitration in accordance with the Rules of the American Arbitration Association to the extent not inconsistent with the rules specified herein. As to disputes that involve amounts of $5,000,000 or more, the Parties may choose to litigate or may resolve such disputes by the provisions of this Article.

10.13.2. Each Party shall choose one arbitrator within twenty (20) Business Days of either Party's written election to the other to arbitrate, and within ten (10) Business Days after both such arbitrators are chosen, such arbitrators shall choose a third arbitrator who shall act as Chair. Any arbitrator chosen shall be a disinterested party with knowledge of the industry.

10.13.3. The first arbitration hereunder shall be conducted in Houston, Texas. The following proceeding shall take place in New York City, New York. Successive arbitration proceedings shall alternate between Houston and New York, in said order.

10.13.4. The arbitrators, once chosen, shall consider any Transaction tapes or any other evidence which the arbitrators deem necessary and shall then accept sealed written

resolutions of the subject dispute from each Party on a confidential basis to be submitted within twenty (20) Business Days of establishment of the arbitration panel. The written submissions shall be in a form and subject to any limitations as may be prescribed by the arbitrators. The arbitrators shall then choose only one of the proposed solutions, (without modification) as the fairest solution to the dispute within ten (10) Business Days of receipt of the written submissions of both Parties. A majority vote shall govern and the decision of the arbitrators shall be final and binding.

10.13.5. Any expenses incurred in connection with hiring the arbitrators and performing the arbitration shall be shared and paid equally between the Parties. Each Party shall bear and pay its own expenses incurred by each in connection with the arbitration, unless otherwise included in a solution chosen by the arbitration panel. In the event either Party must file a court action to enforce an arbitration award under this Article, the prevailing Party shall be entitled to recover its court costs and reasonable attorney fees.

10.13.6. The existence, contents or results of any arbitration hereunder may not be disclosed without the prior written consent of both Parties, subject to Section 10.11 herein.

Add new Section 10.14.

Electronic Imaged Documents. Any document generated by the Parties with respect to this Agreement, including this Agreement, may be imaged and stored electronically ("Imaged Documents"). Imaged Documents may be introduced as evidence in any proceeding as if such were original business records and neither Party shall contest the admissibility of Imaged Documents as evidence in any proceeding.

Add the following wording to Schedule P:

Other Products and Service Levels: The Parties may agree to use a product/service level defined by a different agreement (i.e., the WSPP Agreement, the ERCOT agreement, etc.) for a particular Transaction. Unless the Parties expressly state and agree that all the terms and conditions of such other agreement will apply to any such Transaction, the Transaction shall be subject to all the terms of this Agreement, except that (1) all service level/product definitions; (2) the regional reliability requirements and guidelines; and (3) Force Majeure/Uncontrollable Force definitions shall have the meaning ascribed to them in the different agreement in effect on the date the Transaction was entered into.

All notices, invoices, payments, statements, Confirmations and communications made to DETM pursuant to this Agreement shall be made as follows:

Correspondence:
If the deal is done with the	Duke Energy Trading and Marketing, L.L.C.
Houston office:	5400 Westheimer
	Houston, Texas 77056
	Attention: Contract Administration
	Phone: (713) 627-6177	FAX: (713) 627-6188
If the deal is done with the	Duke Energy Trading and Marketing, L.L.C.
Salt Lake City office:	4 Triad Center, Suite 1000
	Salt Lake City, UT 84180
	Attention: Contract Administration
	Phone: (801) 531-4400	FAX: (801) 531-5490
Invoices:
If the deal is done with the	Duke Energy Trading and Marketing, L.L.C.
Houston office:	5400 Westheimer
	Houston, Texas 77056
	Attention: Power Accounting
	Phone: (713) 627-5400	Fax: (713) 989-0267
If the deal is done with the	Duke Energy Trading and Marketing, L.L.C.
Salt Lake City office:	4 Triad Center, Suite 1000
	Salt Lake City, UT 84180
	Attention: Power Accounting
	Phone: (801) 531-4400	FAX: (801) 531-5473
Power Scheduling:
Salt Lake City:	Phone: (801) 531-5123	Fax: (801) 531-5111
Houston:	Phone: (713) 989-0847	Fax: (713) 989-0491
Payment By Check:	Duke Energy Trading and Marketing, L.L.C.
	P. O. Box 201204
	Houston, TX 77216-1204
Payment By Wire Transfer:	Chase Manhattan Bank
	New York, NY
	For the Account of:
	Duke Energy Trading and Marketing, L.L.C.
	Account No. 910-2-771293 ABA No. 021000021

Confirmations sent to a DETM office contrary to these instructions shall not be deemed "received" for the purposes of Section 2.3 of the Agreement.

ACCEPTED AND AGREED:

DUKE ENERGY TRADING AND MARKETING, L.L.C.

/s/ Joy Thakur

By: Joy Thakur, Senior Director

Date: September 26, 2001

ENERGY ATLANTIC LLC

/s/ Calvin D. Deschene

By: Calvin D. Deschene, General Manager

Date: September 19, 2001

Exhibit 13

(Front Cover)

Maine Public Service Company

We put a lot of energy into Northern Maine

Economic Growth at Loring Commerce Centre

2001 Annual Report

(Inside Front Cover)

Growth and Expansion

Since the closure of Loring Air Force Base on September 30, 1994, Loring Commerce Centre has actively promoted development at the former military facility which consists of approximately 8,700 acres of land, 2.8 million square feet of building space, and a 12,100 foot runway capable of handling the world's largest aircraft. Several tenants now utilize the buildings and collectively, these organizations occupy 1.6 million square feet of space, will employ 1,400 people, and thus contribute significantly to the local economy.

A military vehicle refurbishment center is operated by the Maine Army National Guard at Loring. Their mission is to fix and repair military vehicles, utilizing cost effective and labor efficient methods to maximize savings for the Department of Defense. Since its start in 1997, the Maine Readiness Sustainment Maintenance Center has saved close to $7million in structure and tooling, has grown to over 150 employees, and is expected to see more growth and expansion over the next year. The Center is presently using eight buildings at the Loring Commerce Centre and is actively involved in a student partnership with area schools.

In June, 2001, The Telford Group, a Bangor, Maine based aviation services firm, expanded its aircraft maintenance operations at the Loring International Airport through a joint venture with Volvo Aero Services. Telford's activities at Loring call for storage, disassembly, and associated maintenance of aircraft, which could be as large as the Boeing 747 series, requiring large hangar facilities such as those currently available at Loring.

Area Designated as a Rural Empowerment Zone

In 2002, Aroostook County was designated as a rural Empowerment Zone. Communities are eligible for a variety of federal tax benefits along with technical assistance to help create and sustain long-term private investment in job creation over a ten-year period. Among the benefits of qualifying as an Empowerment Zone are availability of tax-exempt bonds, wage credit provisions, brownfields deductible expenses, and quality zone academy bonds.

Maine Public Service Company

209 State Street

P. O. Box 1209

Presque Isle, Maine 04769-1209

Tel. No. (207) 768-5811 - FAX No. (207) 764-6586

Home Page: http://www.mainepublicservice.com - E-Mail: info@mainepublicservice.com

(Page 1)

Maine Public Service Company

The primary goal of Maine Public Service Company is to deliver reliable, economical electrical power to Northern Maine. The Company is an investor-owned electric utility with two wholly-owned subsidiaries, Energy Atlantic, LLC, (EA) and Maine and New Brunswick Electrical Power Company, Ltd. (Maine and New Brunswick).

The year 2001 was Maine Public Service Company's first full year of retail competition and we remain committed to providing highly reliable delivery services to more than 35,000 retail electric customer accounts in a 3,600 square mile service territory, at the lowest possible cost. The electrical system is strengthened by interconnections with New Brunswick, Canada, allowing support from the New Brunswick system and indirectly from the Hydro-Quebec system. Major business activities in the area center around the production of agricultural and forest products. EA's activity is comprised of the competitive retail sale of power throughout Maine, while Maine and New Brunswick has been inactive since the Company's generating assets were sold in June 1999.

Table of Contents

Profile and Table of Contents	1
President's Letter	2-3
Analysis of Financial Condition and Review of Operations -- 2001	4-13
Shareholder Information	14
Five-Year Summary of Selected Financial Data	14
Report of Independent Accountants	15
Financial Statements and Notes	16-37
Consolidated Financial Statistics	38
Consolidated Operating Statistics	39
Directors	40
Executive Officers, Director and Officer Changes, and Stock Transfer Information	Inside Back Cover

(Photo)

The Maine Readiness Sustainment Maintenance Center at Loring turns out approximately 50 refurbished units a month including the multipurpose HMMWV, 5-ton trucks, emergency vehicles, dozers, and mobile kitchen trailers. A storage program for Howitzers and other military vehicle and equipment parts is also part of their responsibility.

Cover Photos:

(Top) A newly refurbished multipurpose vehicle was manufactured by the Maine Readiness Sustainment Maintenance Center for recruiters to use at parades and career fairs; (Left) Balancing new tires; (Right) Medic symbols are painted on emergency vehicle; and (Bottom) One of the first aircraft received at the Telford facility for maintenance and storage.

(Page 2)

President's Letter

to our Shareholders

and Employees

(Picture)

Paul R. Cariani

President and CEO

The year 2001 was again excellent for your Company with earnings of $3.33 per share compared to $3.34 in 2000. The total return on equity (ROE) was 12.7% with the delivery company earning 10.5%, compared to its allowed ROE of 10.7%. Net income was $5.2 million in 2001 compared to $5.3 million in 2000.

As a result of our strong financial performance, the Company increased the annual dividend from $1.28 to $1.40 on October 1, 2001. In addition, our stock price increased by approximately 12% for the year and was one of the better performers in our industry.

Energy Atlantic (EA), our unregulated power marketing subsidiary, contributed $.57 per share in spite of an after tax write-off of approximately one million dollars related to the settlement of a dispute between Engage Energy America, LLC (Engage) and EA. (Please refer to Note 3 of Notes to Consolidated Statements for more information). Because of this settlement, EA's contribution to 2001 earnings is substantially lower than its contribution of $1.06 per share in 2000. A substantial part of EA's success in the past two years was attributable to supplying residential Standard Offer Service (SOS) in Central Maine Power's (CMP) territory. Although it presented a competitive bid, EA was not the successful bidder for residential SOS beginning March 1, 2002 in CMP's service territory, and EA's earnings in 2002 will reflect these lost revenues. In addition, SOS for medium and large class customers in the CMP and Bangor Hydro-Electric Company (BHE) territories has recently been awarded at a price that is likely to inhibit competition in these classes for the year beginning March 1, 2002. This will make it more difficult for all competitive providers, including EA, to compete for medium and large class customers in these territories.

EA has been working with Duke Energy Trading to develop a power supply relationship and also was the successful bidder for 40% of the output from the

(Page 3)

Wheelabrator-Sherman generating facility beginning March 1, 2002, which it has already resold to retail customers in Maine Public Service Company's territory. Although EA has enjoyed excellent success over the last two years, the energy marketing business is very volatile and, for reasons discussed previously, 2002 is likely to produce results that do not compare favorably with those of 2001.

The regulated transmission and distribution (T&D) company had a very good year despite reduced sales resulting from the downturn in the economy. Earnings for the T&D Company were $2.76 per share compared to $2.28 last year, with lower interest costs the major contributing factor to the increased earnings.

Last year, I reported that MPS would not incur any liability for 2001 regarding replacement power costs for Maine Yankee (MY), although calendar years 2002 through 2004 could still be subject to liability if the auction price of independent power production contracts exceeded replacement power costs set forth in the MY Decommissioning Study. I am pleased to report that, based upon the results of the auction prices for independent power producer contracts, the Company will not be subject to any liability in 2002 and subsequent years.

In other regulatory issues, the MPUC approved the Company's stranded cost revenue requirements, effective for the two-year period beginning March 1, 2002, and the investigation into rate design will be ongoing in 2002.

In other matters, I regretfully report the resignation of Stephen A. Johnson, Vice President and General Counsel, effective February 15, 2002. Steve accepted a position with the Company's outside law firm and has been an outstanding contributor to the success of MPS and EA.

I am pleased to report the addition of Lance A. Smith to our Board of Directors. Lance has been very active and successful in the agricultural community and is a welcome addition to our Board.

This is the final report you will receive from me, since I will be retiring effective September 1, 2002. As I look back over the years, your Company has faced many challenges and successfully moved forward from the closing of Loring Air Force Base to the closure of the Maine Yankee Nuclear Plant. Deregulation has provided an opportunity for EA while the delivery company has maintained stable rates, which are the lowest among Maine's investor-owned utilities. It has been an honor and a privilege to serve as your President and to be part of MPS.

My successor, J. Nick Bayne of Charlotte, North Carolina, was elected to the position of President and CEO-Elect by the Board of Directors on March 1, 2002. He assumed transitional responsibilities at MPS on March18, 2002. His previous experience includes leadership positions with both regulated and unregulated energy firms.

The Directors and I sincerely believe Nick will be an excellent leader for your Company and the communities we serve. He inherits an excellent management team and a company that is financially strong. I believe your Company has a bright future.

Finally, I wish to thank our dedicated employees who contribute so much to the success of this Company. I also thank you, our shareholders, for the confidence and support you afforded me over the years.

Sincerely,

Paul R. Cariani

President and CEO

(Page 4)

Analysis of Financial Condition and Review of Operations - 2001

Electric Industry Restructuring

The Company's business environment in 2001 reflects Maine's electric utility restructuring effective March 1, 2000, when the Company began providing customers with transmission and distribution services only. As required by law, the Company divested its generating assets in 1999 with the gain from the sale of these assets deferred on our balance sheet to be used to offset stranded costs beginning March 1, 2000. The associated changes affected many aspects of the Company's financial and operational results in 2001 and 2000, the year of transition, causing significant differences for the transmission and distribution business for 2001 and 2000, as compared to 1999, when the Company operated as an integrated electric utility. An understanding of the following points will enhance comprehension of information presented in this Annual Report and the restructuring's impact on the Company's shareholders and customers:

1. Electric restructuring began on March 1, 2000 and, therefore, only two months of the results for 2000 were reported in a manner consistent with prior years. Comparisons of both prior and future periods to 2001 and 2000 are complicated by this mixture.

2. Since March 1, 2000, the Company has provided only transmission and distribution (T & D) services. These delivery services charged to our customers are determined by the Federal Energy Regulatory Commission (FERC) for transmission services and by the Maine Public Utilities Commission (MPUC) for distribution services, using traditional rate base, rate of return ratemaking principals used by the regulatory agencies.

3. The Company's revenue dollars decreased significantly after the beginning of retail competition, because the customers now buy their power from energy providers. Although the energy supply is reflected on its customers' bills, the Company merely collects and remits to the supplier. Until the Company sold its generating assets on June 8, 1999, related generating costs were expensed. Following the generating asset sale and until March 1, 2000, purchased electricity was expensed. Revenues included the recovery of these costs in rates approved by the MPUC and by FERC. On the other hand, Energy Atlantic, LLC, (EA or Energy Atlantic) the Company's wholly-owned unregulated marketing subsidiary, sells energy supply in the competitive retail market and their business activity increased dramatically after March 1, 2000.

4. The Company's sales in MWH's are comparable to pre-March 1, 2000 results because the new T & D rates are still applied to MWH's delivered. The prior year data has been reclassified consistent with the new classifications, effective March 1, 2000.

5. On March 1, 2000, the MPUC allowed the recovery of stranded costs from our customers. The contractual amounts paid to Wheelabrator-Sherman (W-S) above the market price received from an unrelated power marketer for the output is recorded as stranded cost by the Company. The entire contractual amount was reported as purchased power expense prior to March1, 2000. The Seabrook amortization is also classified as stranded cost effective March 1, 2000. These MPUC approved charges to stranded costs are partially offset by the amortization of the deferred gain from the generating asset sale.

Please refer to Note 12 of the Notes to Consolidated Financial Statements, "Commitments, Contingencies, and Regulatory Matters" for details of the industry restructuring and the related rate orders of the MPUC. Note 3 of the Notes to Consolidated Financial Statements, "Energy Atlantic" describes the Company's wholly-owned unregulated subsidiary's activities in detail.

RESULTS OF OPERATIONS

Earnings and Dividends

Net income and earnings (loss) 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:

(Dollars in Thousands)

Net Income		2001	2000	1999
	Core T&D	$4,340	$3,613	$4,360
	EA	897	1,688	(354)
	Total Company	$5,237	$5,301	$4,006
Earnings Per Share
	Core T&D	$ 2.76	$ 2.28	$ 2.70
	EA	.57	1.06	(.22)
	Total Company	$ 3.33	$ 3.34	$ 2.48

For 2001, the Company's return on equity was 12.7% compared to 13.8% and 11.1% for 2000 and 1999, respectively. In determining rates at the beginning of deregulation, March 1, 2000, the MPUC authorized a return on equity of 10.7% for the core T&D business. For 2001, the core T&D business earned 10.5% compared to 9.5% for 2000.

EA earnings in 2001 reflects 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 one-time 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 $425,000 less in 2001 than 2000. In addition, interest expenses in 2001 were approximately

(Page 5)

$1.2 million 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. These reductions follow the national trend of lower interest rates as a result of the Federal Reserve's interest rate cuts to spur the economy.

During 1999, the Company sold its generating assets and deferred a net gain of $19.9 million. In accordance with the previously mentioned mega-case order for T&D rates, (see "Electric Industry Restructuring", above) beginning March 1, 2000, the deferred gain is being amortized, which significantly reduces other stranded cost revenue requirements. However, in 1999, the Company did recognize $389,000 of net income associated with excess deferred income taxes and unamortized investment tax credits associated with the assets sold.

During the three-year period, dividends have been increased three times. Your Board of Directors increased the quarterly dividend from $.25 to $.30 per share effective with the October 1, 1999 payment. One year later, your Board increased the dividend to $.32 per share, an increase of $.02. On October 1, 2001, the dividend was increased to $.35 per share, an increase of $.03 per share. Dividends paid during 2001 were $1.31 per share compared to $1.22 and $1.05 for 2000 and 1999, respectively.

Operating Revenues and Energy Deliveries

Consolidated revenues and MWH delivered for the years 2001, 2000, and 1999 are as follows:

Consolidated Revenues and Megawatt Hours Delivered(Dollars in Thousands)

	2001		2000		1999
	Dollars	MWH	Dollars	MWH	Dollars	MWH
Residential	$ 12,382	166,012	$ 14,605	166,049	$ 21,708	170,481
Large Commercial	4,684	160,575	6,111	171,023	10,596	149,979
Medium Commercial	5,242	107,207	5,908	103,914	9,578	99,121
Small Commercial	5,994	85,605	7,075	87,867	10,248	88,570
Other Retail	767	3,309	783	3,259	885	3,210
Total Regulated Retail	29,069	522,708	34,482	532,112	53,015	511,361
Energy Atlantic Competitive
Energy Supply	15,771	375,768	37,054	824,845	--	---
Total Retail	44,840	898,476	71,536	1,356,957	53,015	511,361
Sales for Resale	--	--	1,798	38,010	12,536	390,587
Total Deliveries of Electricity	44,840	898,476	73,334	1,394,967	65,551	901,948
Other Operating Revenues	2,711		2,130		1,905
Total Operating Revenues	47,551		75,464		67,456
Energy Atlantic Standard
Offer Service Margin	2,147		2,774		--
Total Revenues	$49,698		$78,238		$67,456

The year 2001 was the first full year after Maine's electric industry restructuring which, as discussed in "Electric Industry Restructuring" above, began on March 1, 2000. The Company provides transmission and distribution (T&D) services, regulated by the Maine Public Utilities Commission (MPUC), but no longer supplies energy. The Company's wholly-owned marketing subsidiary, Energy Atlantic, LLC, (EA), provides electricity at competitive rates throughout Maine. Comparisons of the regulated retail revenues for the years 1999 through 2001 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, will focus on MWH deliveries.

Total T&D regulated retail sales in 2001 were 522,708 MWH, a decrease of 9,404 MWH (1.8%) and an increase of 11,347 MWH (2.2%) compared to 2000 and 1999, respectively. The decrease from

(Page 6)

2000 was due to the 10,448 MWH (6.1%) decrease in large commercial customers sales, primarily lumber and wood products (7,005 MWH) and food processing (4,105 MWH). Sales to Irving Forest Products, a wood products customer, decreased 6,472 MWH in 2001 compared to 2000 due to production curtailments. An expansion in 1999 by McCain Foods, our largest customer, contributed additional sales of approximately 17,000 MWH in 2000, accounting for most of the 21,044 MWH (14.0%) increase in large commercial sales compared to 1999. Residential sales for 2001 of 166,012 MWH approximated 2000, and were 4,469 MWH (2.6%) less than 1999. Medium commercial sales in 2001 were 107,207 MWH, reflecting increases of 3,293 MWH (3.2%) and 8,086 MWH (8.2%) compared to 2000 and 1999, respectively, due to continued increase in activity at the former Loring Air Force Base. Activity in the small commercial class decreased 2,262 MWH (2.6%) to 85,605 MWH in 2001 compared to 2000 and decreased 2,965 MWH (3.3%) compared to 1999. Sales to wholesale customers ceased with the industry restructuring on March 1, 2000.

During 1996 and 1997, the Company entered into long-term discount contracts, which principally expired at the end of 2000, with five of its largest customers. All five of these customers produced evidence of hardship to continue operations in the area or were investigating self-generation, criteria that the MPUC reviewed before approving these load-retention contracts. On August 4, 2000, the MPUC approved new contracts with two of these customers for up to eleven years, retaining these valuable customers. In addition, the MPUC authorized revenue recognition and establishment of a regulatory asset for the difference between the amounts billed under these contracts and the originally approved contracts which totaled $961,000 and $380,000 in 2001 and 2000, respectively, recorded as other revenues. These regulatory assets will be recovered in future rates.

The MPUC has jurisdiction over retail rates. As discussed in the "Regulatory Proceedings -- MPUC Approves Elements of Rates Effective March 1, 2000" section below, the MPUC approved rates for the Company's transmission and distribution (T&D) utility as of March 1, 2000, exclusive of the energy supply, now purchased by customers from competitive energy providers or standard offer service. Until February 29, 2000, the Company operated under a four-year rate plan which had granted rate increases of 4.4%, 2.9% and 3.9% effective January 1, 1996, February 1, 1997 and February 1, 1998, respectively. For the final year of the rate plan, the MPUC approved a stipulation allowing a 3.66% specified rate increase as of April 1, 1999. Rather than increase customer rates, the MPUC allowed the recognition of these revenues as an offset to the available value from the sale of the generating assets. The 3.66% increase totaled $1,316,000 in 1999 and $379,000 for the first two months of 2000, and has been recorded as other operating revenues. Other operating revenues were $2,711,000 in 2001, compared to $2,130,000 and $1,905,000 in 2000 and 1999, respectively. The $581,000 increase in 2001 compared to 2000 reflects the increase in regulatory revenue adjustments, discussed above. The Federal Energy Regulatory Commission (FERC) has jurisdiction over transmission rates.

As more fully described in the "Energy Atlantic" section below, EA's business is comprised of Standard Offer Service (SOS) and Competitive Energy Supply (CES) activity. The reported SOS activity of $2,147,000 for 2001 represents the accrued net margin principally from SOS provided to approximately 525,000 residential and small commercial customer accounts in Central Maine Power's service territory. The $627,000 decrease (22.6%) from 2000 reflects a $1.8 million before-tax charge for a contract settlement with Engage Energy America, LLC (Engage), the wholesale provider, recorded in the second quarter of 2001. The impact of this settlement, which is also further discussed in the "Energy Atlantic" section below, was partially offset by the SOS activity for all of 2001. In 2000, there were only ten months of sales. EA's CES sales were 375,768 MWH in 2001, a 449,077 MWH (54.4%) decrease from 2000. This reflects the expiration of several large CES contracts during 2001, which had been in place for most of 2000.

Operating Expenses

For the three-year period 1999-2001, energy supply and transmission and distribution operation and maintenance expenses are as follows:(Dollars in Thousands)

	2001	2000	1999
Energy Supply
Purchased Power
Wheelabrator-Sherman	$ --	$ 2,567	$14,205
Maine Yankee	--	571	3,760
Northeast Empire	--	1,508	7,768
Other Purchases	--	2,398	7,619
Energy Atlantic	14,984	36,433	7,324
Total Purchased Power	14,984	43,477	40,676
Deferred Fuel	--	114	(1,603)
Net Purchased Power	14,984	43,591	39,073
Generation
Fuel Expense	--	--	622
Other	--	2	569
Total Generation	--	2	1,191
Total Energy Supply	$14,984	$43,593	$40,264
T&D Operation and Maintenance
Transmission and Distribution	$ 3,343	$ 3,219	$ 3,008
Customer Accounting and General Administrative	7,198	7,493	7,276
Energy Atlantic	1,097	1,351	1,037
Other Oper. & Maint.	$11,638	$12,063	$11,321
Stranded Costs
Wheelabrator-Sherman	$ 9,003	$10,694	Not
Maine Yankee	3,170	2,727	Applicable
Seabrook	1,110	925
Amortization of Gain from Asset Sale	(4,856)	(5,440)
Deferred Fuel	833	--
Total Stranded Costs	$ 9,260	$ 8,906

Beginning March 1, 2000, the Company no longer supplies electricity to our retail customers under regulated rates and, therefore, ceased purchasing power on that date. As discussed in "Electric Industry Restructuring" above, the Company's wholly-owned unregulated marketing subsidiary, Energy Atlantic, LLC, (EA) entered the retail market as an energy provider throughout the State of Maine on March 1, 2000, after participating in the wholesale market prior to February 29, 2000. As discussed in the "Energy Atlantic" section below, EA's competitive energy provider sales and purchase power expenses are recognized on a gross basis throughout 2000 and 2001.

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Energy supply expenses of $14,984,000 in 2001 consist only of purchases by EA. The decreases in energy supply of $28,609,000 and $25,280,000 from 2000 and 1999, respectively, reflect the termination of the Company's power purchases on March 1, 2000, as well as a decrease in purchases by EA from 2000 to 2001. The decrease in purchases by EA reflects the expiration of several large CES contracts during 2001 which had been in place for most of 2000. During 1999 and for the first two months of 2000, EA's sales were limited to bulk power sales.

As explained above, the Company supplied power to its customers until February 29, 2000. Purchases from Wheelabrator-Sherman (W-S), Northeast Empire and other suppliers, as well as decommissioning expenses for Maine Yankee, were classified as Energy Supply expenses during the first two months of 2000 and all of 1999, when the Company operated as an integrated electric utility. Payments continued after March 1, 2000 to W-S and Maine Yankee, but were classified as stranded costs, as discussed below. Deferred fuel expense, a component of purchased power, was a positive $114,000 in 2000, compared to a negative $1,603,000 in 1999. A positive deferred fuel expense indicates that amounts collected through rates exceed current costs, which occurred during the first two months of 2000. A negative deferred fuel expense indicates expenses deferred to a future period when these costs will be collected in rates. As more fully discussed in Note 12 of the Notes to Consolidated Financial Statements, "Commitments, Contingencies and Regulatory Matters -- Four-year Rate Stabilization Plan", the Company was allowed to defer one-half of the Maine Yankee replacement power costs, offset by the savings from the amended purchase power agreement with W-S until the termination of the plan on February 29, 2000. Generating expenses of $1,191,000 in 1999 represent activity until the Company's generating assets were sold on June 8, 1999.

Transmission and distribution (T&D) expenses were $3,343,000 in 2001, an increase of $124,000 over 2000. Additional tree trimming expenses of $137,000 were the primary reason for the increase. The $211,000 increase in T&D expenses from 1999 to 2000 was principally due to fees paid to the Northern Maine Independent System Administrator beginning on March 1, 2000, and a severe windstorm in December, 2000 which increased expenses by $125,000. These increases were partially offset by a $274,000 decrease in tree trimming expenses. 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, partially offset by increased medical premiums. EA's other operation expenses were $1,097,000 in 2001, a decrease of $254,000 from 2000, primarily due to decreased bad debt expense of $248,000.

The Company recognized $9,260,000 of stranded costs in 2001, compared to $8,906,000 in 2000. Beginning on March 1, 2000, as detailed in the table above and discussed below in "Regulatory Proceedings -- MPUC Approves Elements of Rates Effective March1, 2000", below, the Company is now classifying certain expenses as stranded costs. The Wheelabrator-Sherman and Maine Yankee costs of $9,003,000 and $3,170,000, respectively, in 2001, and $10,694,000 and $2,727,000, respectively, in 2000, as well as deferred fuel costs of $833,000 in 2001 are comparable to expenses recorded as purchased power prior to March 1, 2000. The Seabrook costs of $1,110,000 in 2001 and $925,000 in 2000 represent amortization of the unrecovered costs beginning March 1, 2000, and are comparable to expenses previously classified as amortization. As stipulated, the Company is allowed to offset these stranded costs with the amortization of the deferred gain from the generating asset sale of June 1999, described in detail in Note 12 of the Notes to Consolidated Financial Statements, "Commitments, Contingencies and Regulatory Matters -- Capacity Arrangements - Generating Asset Sale".

Interest expenses for 2001 were $1,291,000, compared to $2,459,000 and $4,236,000 for 2000 and 1999, respectively. The decrease from 2000 to 2001 of $1,168,000 is primarily due to the early redemption of the 9.775% bonds in June, 2000, accounting for $664,000 of the decrease, and lower interest rates in 2001. The decrease from 1999 to 2000 of $1,777,000 is primarily due to the redemption of long-term debt, principally the 9.775% bonds mentioned above, with proceeds from the generating asset sale, as discussed in Note 8 of the Notes to Consolidated Financial Statements, "Long-Term Debt", partially offset by increased short-term borrowing interest costs in 2000 to meet working capital needs, accounting for $1,023,000 of the decrease. The Company was allowed to recognize $963,000 and $768,000 in stranded cost carrying charges in 2001 and 2000, respectively, as a reduction to interest expense and an increase to deferred fuel to be collected in future periods.

The $686,000 decrease in Interest and Dividend Income in 2001 compared to 2000 was primarily due to a $414,000 decrease in interest earned on generating asset sale proceeds, in addition to lower interest rates earned on the tax-exempt bond proceeds held in trust. The $48,000 decrease in Interest and Dividend Income in 2000 compared to 1999 was primarily due to a $342,000 decrease in interest earned on generating asset sale proceeds, offset by a $243,000 increase in EA's interest income from their escrow arrangement with Engage and by interest earned on the proceeds of the tax-exempt bonds beginning in October 2000.

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. EA's net income was $897,000 for 2001 compared to $1,688,000 in 2000 and a loss of $354,000 for 1999. The decrease from 2000 primarily reflects the expiration of several large competitive retail contracts in Central Maine Power's (CMP) service territory, as well as the expiration of most medium non-residential service in the Company's service territory. As discussed below, EA also recognized a settlement charge of $1.08 million.

Energy Atlantic provides standard offer service (SOS) and competitive energy supply (CES) to retail customers, both of which utilize power principally provided via a Wholesale Power Sales Agreement with Engage Energy America, LLC (Engage). Revenues are received and expenses are paid directly by an escrow agent pursuant to instruction from Engage. EA receives a percentage of the net profit from the sale of energy. EA was the SOS provider for approximately 525,000 residential and small non-residential customers in CMP's service territory through February 28, 2002. Under the original SOS terms, EA had furnished a performance bond of approximately $33,000,000 issued by Frontier Insurance Company. The utility (in this case CMP) bears the SOS account collection risk, as it is 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 records the accrued net margin of the SOS activity as revenue in the financial statements.

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EA's CES activity currently consists of industrial and commercial customers in Maine in which EA maintains collection risk and negotiates contracts directly with customers. CES activity is recorded on a gross basis to include the related revenues and purchased power expenses.

On December 5, 2000, the Federal Energy Regulatory Commission (FERC) issued an order requiring an increase in the Installed Capacity (ICAP) Deficiency Charge in the New England market from $0.17 to $8.75 per kw/month, which was subsequently reduced to $4.87 on September 1, 2001. Engage sent EA a letter giving notice that it was invoking certain contract renegotiation rights and setting forth its position that an increase of this magnitude would give it grounds to cancel its contract with EA. EA responded by stating its view that the contract requires Engage to sustain the market risks of increases in the cost of supplying power and that the notice was in breach of the contract. Without agreeing with EA's position, Engage withdrew its notice letter. Subsequently, Engage alleged that EA previously breached the contract in certain respects. EA denied these allegations.

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 includes the following:

(i) Engage will continue to supply EA with all energy required to perform outstanding retail contracts and the SOS commitments.

(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 cannot 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 current parent company) has 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 will receive $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 will be 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.

After the elimination of the requirement to purchase power exclusively from Engage in May, 2001, EA began securing other sources of supply to support further CES sales. In September, 2001, after examining several competitive bids, including EA's, the MPUC awarded the SOS contract for residential and small commercial customers in CMP's territory to a different marketer beginning March1, 2002. Although positive, EA's CES sales to retail customers will produce far less revenue in 2002 than EA received in 2001 from SOS in CMP's territory. EA continues to pursue additional supply to increase revenues.

Maine Yankee

The Maine Agreement for the decommissioning of Maine Yankee requires the Maine owners, (Central Maine Power, Bangor Hydro-Electric Company and the Company) for the period from March 1, 2000 through December 1, 2004, to hold their Maine retail ratepayers harmless from the amounts by which the replacement power costs for Maine Yankee exceed the replacement power costs assumed in the report to the Maine Yankee Board of Directors that served as a basis for the Plant shutdown decision, up to a maximum cumulative amount of $41 million. The Company's share of the maximum amount would be $4.1 million for the period. Based on agreements with the MPUC, there was no liability for the years ended December 31, 2000 and 2001. Pursuant to the Company's filing in early 2002, on January 24, 2002, the MPUC issued a notice of settlement for the remaining years 2002, 2003 and 2004. Since the replacement power benchmark prices for the three-year period were below the Maine Yankee-assumed prices for these three years, the Commission concurred with the Company's assertion that, in effect, the calculations would result in no additional liability.

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February 2001, and again in December 2001, 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, 2001 is carrying on its consolidated balance sheet a regulatory asset and a corresponding liability in the amount of $24.7 million, which reflects the Company's 5% share of Maine Yankee's December 31, 2001 estimate of decommissioning costs.

The MPUC, on January 27, 2002, approved a Stipulation providing for the recovery of stranded investment, for a two-year period from March 1, 2002 until February 29, 2004, which includes the Company's share of Maine Yankee decommissioning expenses, Maine Yankee replacement costs, and the remaining Maine Yankee investment.

In December 2000, Maine Yankee distributed approximately $20million to its owners from proceeds received as a result of the termination of Maine Yankee's membership in a nuclear industry mutual insurance company. The Company received its 5% ownership share, or $1.0 million, and reported it as a regulatory liability as of December 31, 2001 and 2000. In January 2002, the MPUC approved a stipulation on stranded costs which included an allocation of 15% of the refund to shareholders and the remainder to offset the recognition of stranded costs. On September 27, 2001, Maine Yankee's Board of Directors voted to redeem 75,200 shares, 15% of the shares outstanding, of Maine Yankee's Common Stock in accordance with a plan approved by the Securities and Exchange Commission on September 10, 2001. The plan calls for the redemption of Common Stock periodically through 2008. On October 4, 2001, the Company received approximately $500,000 for 15% of its Common Stock in Maine Yankee according to the first step of the plan.

For further information, see Note 12 of the Notes to Consolidated Financial Statements, "Commitments, Contingencies, and Regulatory Matters - Capacity Arrangements - Maine Yankee".

Liquidity

The accompanying "Statements of Consolidated Cash Flows" reflect the Company's liquidity and financial strength. The statements report the net cash flows generated from or used for operating, financing, and investing activities.

Net cash flows provided by operating activities for 1999 were $5.3 million. The June 8, 1999 sale of the generating assets provided proceeds of $37.5 million which were deposited with the first mortgage trustee in accordance with mortgage indentures. At the end of 1999, a total of $18.0 million of the proceeds remained with the first mortgage trustee, after a $4.0 million drawdown was used for the final redemption of $2.5 million of the 9.6% Series of second mortgage bonds and a redemption of $1.4 million of the 1996 Series of tax-exempt bonds. In addition to the redemptions mentioned above, $1.3 million of scheduled principal payments were made, for a total of $5.2 million in long-term debt retirements. During 1999, the Company paid $1.3 million in dividends and spent $4.8 million for electric plant. The Company also withdrew the final $.4 million from the proceeds held in trust from the 1996 tax-exempt bond issuance and decreased short-term borrowings by $4.5 million with a portion of the asset sale proceeds.

In 2000, net cash flows provided by operations were $4.7 million. 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 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 flow provided by operating activities were $10.1 million in 2001. 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 amount for the construction of qualifying distribution property. As of December 31, 2001, approximately $5.7 million remains in the tax-exempt bond trust fund to be used for the construction of qualifying property. In 2001, $4.7 million was spent for electric plant.

For additional information regarding construction expenditures for 1999 to 2001 and anticipated construction expenditures for 2002, see Note 12 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. In October, 1999, the Company's credit agreement was reduced to $6 million. The agreement is secured by $6 million of first mortgage bonds and its due date has been extended to May, 2002. In September, 2000, the Company obtained an additional $2.5 million unsecured line of credit for a period of six months. This additional line of credit was required to cover the high costs of the W-S power contract during 2000. At the end of 2001, the Company had $3.95 million of short-term debt compared to $4.9 million and $3.6 million at the end of 2000, and 1999, respectively. During 1999 to 2001, the interest rates on these short-term borrowings were below the existing prime rate. For additional information on the short-term credit facility, see Note 6 of the Notes to Consolidated Financial Statements, "Short-Term Credit Arrangement". Based on current projections, the Company estimates that operating cash flows will be sufficient to cover its other sinking fund payments, construction activities, and other financial obligations.

(Page 10)Capital Resources

The sale of the Company's generating assets in June 1999, has significantly impacted the Company's capital structure. The after-tax proceeds from the sale of the generating assets and the liquidation of the Canadian subsidiary were used to reduce the Company's debt. In 1999, the Company reduced long-term debt by $3.9 million, redeeming the outstanding second mortgage bonds of the 9.6% Series of $2.5 million and $1.4 million of the 1996 Series of tax-exempt bonds for property sold which was previously financed with this tax-exempt issue. In 2000, the Company used $1.9 million to reduce short-term borrowings and redeemed its highest coupon debt, the 9.775% Series of first mortgage bonds of $15 million, and paid the associated early redemption premium.

As more fully explained in the "Regulatory Proceedings-MPUC Approves Elements of Rates Effective March 1, 2000", below, the recognition of the deferred gain on the generating asset sale of approximately $19.9 million at the end of 1999 began March 1, 2000, to reduce stranded cost revenue requirements, principally the power costs associated with the Wheelabrator-Sherman contract. In accordance with the rate decision, $5.4 million and $4.9 million of the gain were recognized during 2000 and 2001, respectively. In addition, $7 million was used to offset the remaining unrecovered costs on Seabrook. Based on the current ratemaking treatment, the deferred gain should be fully amortized in 2002.

After several years of negotiations, the Company restructured its Power Purchase Agreement (PPA) with the Wheelabrator-Sherman Energy Company (W-S). Under the terms of the original PPA, the Company was obligated to purchase the entire output up to 126,582 MWH of the 17.6 MW biomass plant owned by W-S through December 31, 2000. The PPA could be renewed by either party for an additional fifteen years at prices to be determined by mutual agreement or, absent mutual agreement, by the MPUC. In October 1997, the Company and W-S agreed to amend the PPA. Under the terms of this agreement, W-S agreed to accept an up-front payment of $8.7 million and reduce the price of purchased power by $10 million through December 31, 2000. The Company and W-S agreed to renew the PPA for an additional six years at set prices. In May 1998, the Company made the up-front payment of $8.7 million to W-S using the proceeds from a financing provided by the Finance Authority of Maine (FAME). Based on the MPUC rate order effective March 1, 2000, the Company began amortizing this regulatory asset and recovering this stranded cost in 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 increase in retail rates.

As previously mentioned, with the sale of the generating assets, the Company's long-term debt has been dramatically decreased over the three-year period ending with 2001. On January 1, 1999, the Company had $47.2 million of long-term debt compared to $34.9 million at the end of 2001. The Company's long-term debt consists of a 7.95% Series of first mortgage bonds in the amount of $1.825 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), and a series of bonds issued by FAME to provide 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, 2001 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, 2001, approximately $5.7 million is available. 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 2002, and the Company has asked for extensions. 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 $15.875 million in accordance with the original issue of $15 million in bonds. 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 were 3.60% and 3.06% for the 1996 Refunding Series and the 2000 Series, respectively. On November 17, 2000, the Company purchased an interest rate cap of 6% to cover both series at a cost of $36,386. At the end of 2001, the cumulative effective interest rate, which includes the weekly interest rate, LC fees and cost of issuance, were 5.49% for the 1996 Refunding Series and 5.65% 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 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 5.25%. 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 2001, the cumulative effective interest rate, including issuance costs and credit enhancement fees, since issuance for this Series was 6.28%.

The Company has the ability to finance 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

(Page 11)

Company can also issue second mortgage bonds of $14.3 million without bondable property additions.

Effective March 1, 2000, the Company is required to maintain a capital structure with 51% common equity for the determination of its delivery rates, in accordance with a stipulation approved by the MPUC on December 1, 1999, in the Company's rate design and stranded cost recovery cases. 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 and in accordance with previous repurchase programs, the Company did not acquire any stock during 2001.

Employees

At the end of 2001 and 2000, the Parent Company had 145 and 142 full-time employees, respectively. The Parent's Canadian subsidiary, Maine and New Brunswick Electrical Power Company, Ltd. (Maine and New Brunswick), has had no employees since the generating asset sale on June 8, 1999. Energy Atlantic, the Parent's unregulated marketing subsidiary, had 11 full-time employees at the end of both 2001 and 2000. Consolidated payroll costs were $7.0 million for 2001 and $6.7 million for 2000.

Local 1837 of the International Brotherhood of Electrical Workers ratified a three-year contract with the Parent Company, effective on October 1, 1999. The agreement included a 3.34% wage increase in the first year and a 3.5% increase in each of the last two years of the new contract.

Regulatory Proceedings

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 provided in Note 12 of the Notes to Consolidated Financial Statements, "Commitments, Contingencies, and Regulatory Matters - Industry Restructuring".

MPUC Approves Stranded Cost

Revenue Requirements Effective March1,2002

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 December31, 2001, the Company reflected the refund as a miscellaneous deferred credit. A stipulation placed before the MPUC in January, 2002 includes 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 the same. This stipulation was approved by the MPUC on January 7, 2002, and the appropriate order was issued on February 27, 2002.

MPUC Conducts Investigation of Rate Design

(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 believes its stranded costs should be recovered through fixed charges that its customers cannot avoid by reducing or eliminating their usage. Such a fixed charge would reduce the risk of the Company's ability to recover its stranded costs from customers. The Company, together with CMP and BHE, will be filing testimony in support of its position in early April, 2002.

The Company cannot predict the nature or the outcome of any decision in this proceeding.

MPUC Approves Elements of Rates Effective March1,2000

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.

(Page 12)

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. Furthermore, the Stipulation allowed the 3.66% foregone revenue increase as a result of a rate plan Stipulation approved by the MPUC in its April 6, 1999 Order in Docket 98-865 to be recovered through a reduction in the deferred gain on the asset sale. The Stipulation also provided that the Company's recovery of unamortized investment tax credits and excess deferred income taxes associated with the Company's generating assets must await a final determination ruling from the IRS, which ruling was sought by Central Maine Power Company (CMP). On December 1, 1999, the MPUC approved the October 15, 1999 Stipulation, as described above. In early January, 2000, CMP received its ruling from the IRS which concluded that the unamortized investment tax credits and excess deferred income taxes associated with the sale of the generating assets could not be used to reduce customer rates without violating the tax normalization rules for public utilities. Therefore, in 1999, the Company recognized these excess deferred taxes in income, which amounted to an increase in net income of approximately $389,000.

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 Note 12 of the Notes to Consolidated Financial Statements, "Capacity Arrangements--Generating Asset Sale") 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 originally 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 $961,000 and $380,000 of revenues and a corresponding regulatory asset in 2001 and 2000, respectively. These regulatory assets will be recovered in future rates. 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" for additional information.

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 against the Company as well as a Petition to Alter or Amend the MPUC's September 2, 1998 Order in Docket No. 98-138, which authorized the formation of Energy Atlantic, LLC.

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.

(Page 13)

Generating Asset Sale

On June 8, 1999 the Company sold its generating assets to WPS Power Development, Inc. The sale of the assets, 91.8 megawatts of generating capacity, for $37.4 million was required by the State's electric industry restructuring law. For further information, see Note 12 of the Notes to Consolidated Financial Statements, "Commitments, Contingencies, and Regulatory Matters -- Capacity Arrangements - Generating Asset Sale".

Four-Year Rate Stabilization Plan

The Maine Public Utilities Commission (MPUC) approved a stipulation on November 13, 1995 that established a multi-year rate plan, effective January 1, 1996 through March 1, 2000. The plan provided our customers with predictable rates and shared operating risks and benefits between the Company's shareholders and customers. For further information, see Note 12 of the Notes to Consolidated Financial Statements, "Commitments, Contingencies, and Regulatory Matters -- Four-Year Rate Stabilization Plan".

Accounting Pronouncements

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 declared their fair values as of December 31, 2001 to be $118,000. The corresponding unamortized regulatory assets as of December 31, 2001 are $133,000.

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 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 Company does not expect the adoption of either of these statements will have a material impact on its financial position or results of operations.

Forward-Looking Statements

The above discussion may contain "forward-looking statements", as defined in the Private Securities Litigation Reform Act of 1995, related to expected future performance or our plans and objectives. Actual results could potentially differ materially from these statements. Therefore, there can be no assurance that actual results will not materially differ from expectations.

Factors that could cause actual results to differ materially from our projections include, among other matters, electric utility restructuring; future economic conditions; changes in tax rates, interest rates or rates of inflation; and developments in our legislative, regulatory, and competitive environment.

(Page 14)

Shareholder Information

General

The Company's Common Stock is listed and traded on the American Stock Exchange. As of December 31, 2001 and 2000, Common Stock shares issued and outstanding were 1,573,510 and 1,572,898, respectively. As of December 31, 2001, shares were held by 1,001 shareholders or nominees in forty-six states, the District of Columbia, Canada, and the United Kingdom.

The annual meeting of shareholders is held each year on the second Tuesday in May at the Company's headquarters in Presque Isle. Market price and dividend information relative to the two most recent calendar years are shown in the tabulation below.

Income Tax Status of 2001 Dividends

The Company has determined that the Common Stock dividends paid in 2001 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.

	Market		Dividends	Dividends
	Price		Paid	Declared
	High	Low	Per Share	Per Share
2001
First Quarter	$26.63	$23.37	$.32	$.32
Second Quarter	$30.50	$26.00	.32	.32
Third Quarter	$29.60	$27.00	.32	.35
Fourth Quarter	$30.75	$27.75	.35	.35
Total Dividends			$1.31	$1.34
2000
First Quarter	$18.00	$16.00	$.30	$ .30
Second Quarter	$20.75	$17.38	.30	.30
Third Quarter	$25.60	$20.25	.30	.32
Fourth Quarter	$27.13	$23.75	.32	.32
Total Dividends			$1.22	$1.24

Dividends declared within the quarter are paid on the first day of the succeeding quarter.

Five-Year Summary of Selected Financial Data

	2001	2000	1999	1998	1997
Revenues	$49,698,040	$78,238,279	$67,456,117	$56,626,906	$55,072,196
Net Income (Loss) Available for Common Stock	$5,236,527	$5,300,632	$4,005,556	$2,252,915	$(2,177,137)
Net Income (Loss) Per Share of Common Stock	$3.33	$3.34	$2.48	$1.39	$(1.35)
Dividends Per Share of Common Stock:
Declared Basis	$1.34	$1.24	$1.10	$1.00	$1.00
Paid Basis	$1.31	$1.22	$1.05	$1.00	$1.21
Total Assets	$143,334,943	$150,856,876	$171,548,480	$164,295,548	$163,480,739
Long-Term Debt Outstanding	$34,940,000	$35,990,000	$42,015,000	$47,190,000	$39,805,000
Less amount due within one year	1,175,000	1,050,000	25,000	1,275,000	4,155,000
Long-Term Debt	$33,765,000	$34,940,000	$41,990,000	$45,915,000	$35,650,000

(Page 15)

Report of Independent Accountants

To The Directors and Shareholders of

MAINE PUBLIC SERVICE COMPANY:

In our opinion, the accompanying consolidated balance sheets and statements of capitalization and the related consolidated statements of income, common shareholders' equity and cash flows present fairly, in all material respects, the financial position of Maine Public Service Company and its Subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

PricewaterhouseCoopers, LLP

Portland, Maine

February 7, 2002

(Page 16)MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARIES

Statements of Consolidated Income

	Year Ended December 31,
	2001	2000	1999
Revenues
Operating Revenues	$47,551,157	$75,464,430	$67,456,117
EA Standard Offer Service Margin	2,146,883	2,773,849	--
Total Revenues	49,698,040	78,238,279	67,456,117
Operating Expenses
Energy Supply	14,983,899	43,593,025	40,264,089
T&D Operation and Maintenance	11,637,878	12,063,273	11,320,556
Depreciation	2,502,034	2,310,252	2,346,285
Amortization of Stranded Costs	9,259,657	8,905,707	--
Amortization	216,842	297,360	1,479,098
Taxes Other Than Income	1,344,299	866,259	1,439,870
Provision for Income Taxes	3,393,006	3,197,446	3,529,542
Total Operating Expenses	43,337,615	71,233,322	60,379,440
Operating Income	6,360,425	7,004,957	7,076,677
Other Income (Deductions)
Equity in Income of Associated Companies	299,299	334,136	491,024
Interest and Dividend Income	167,684	854,093	902,146
Allowance for Equity Funds Used During Construction	85,963	35,809	51,248
Benefit (Provision) for Income Taxes	46,702	(292,610)	130,592
Other - Net	(432,208)	(176,732)	(410,034)
Total	167,440	754,696	1,164,976
Income Before Interest Charges	6,527,865	7,759,653	8,241,653
Interest Charges
Long-Term Debt and Notes Payable	2,285,711	3,245,138	4,268,315
Less Stranded Cost Carrying Charge	(962,579)	(767,751)	--
Less Allowance for Borrowed Funds Used During Construction	(31,794)	(18,366)	(32,218)
Total	1,291,338	2,459,021	4,236,097
Net Income Available for Common Stock	$5,236,527	$5,300,632	$4,005,556
Basic and Diluted Earnings Per Share of Common Stock	$3.33	$3.34	$2.48
Average Shares Outstanding	1,573,294	1,588,009	1,617,250

See Notes to Consolidated Financial Statements.

(Page 17)

MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARIES

Statements of Consolidated Cash Flows

	Year Ended December 31,
	2001	2000	1999
Cash Flow From Operating Activities
Net Income	$5,236,527	$5,300,632	$4,005,556
Adjustments to Reconcile Net Income to
Net Cash Provided by (Used For) Operations:
Depreciation	2,502,034	2,310,252	2,346,285
Amortization	1,362,434	1,178,684	1,398,256
Amortization of Deferred Gain from Asset Sale	(4,863,027)	(5,439,750)	--
Deferred Income Taxes - Net	872,815	4,228,605	2,225,933
Deferred Investment Tax Credits and Excess Deferred Income Taxes	(32,580)	(35,539)	(438,270)
Allowance for Funds Used During Construction	(117,757)	(54,175)	(83,466)
Income on Tax-Exempt Bonds-Restricted Funds	(249,928)	(97,105)	(8,830)
Change in Deferred Regulatory and Debt Issuance Costs	(548,257)	84,633	(2,003,759)
Amortization of W/S Up-front Payment	1,451,000	--	--
Gain on Sale of Miscellaneous Property	--	(205,237)	(14,935)
Change in Deferred Revenues	--	--	(1,170,136)
Change in Benefit Obligations	(173,944)	86,395	(1,371,238)
Change in Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenue	5,860,682	(4,305,676)	(495,353)
Deferred Fuel and Purchased Energy Cost	--	--	(300,000)
Other Current Assets	255,210	(193,870)	92,371
Accounts Payable	(1,414,457)	2,308,867	1,079,246
Accrued Taxes and Interest	(342,082)	(823,025)	952,454
Other Current Liabilities	2,537	2,581	(7,375)
Other - Net	289,079	335,440	(912,023)
Net Cash Flow Provided By Operating Activities	10,090,286	4,681,712	5,294,716
Cash Flow From Financing Activities
Dividend Payments	(2,060,821)	(1,948,371)	(1,293,800)
Purchase of Common Stock	--	(921,763)	--
Bond Issuance Costs	--	(322,755)	(102,705)
Drawdown (Deposit) of Asset Sale Proceeds with Trustee, net	--	18,957,051	(17,998,000)
Deposit of Land Sale Proceeds with Trustee	--	(211,400)	--
Issuance of Long-Term Debt	--	9,000,000	--
Retirements of Long-Term Debt	(1,050,000)	(15,025,000)	(5,175,000)
Premium on Retirement of Long-Term Debt	--	(2,105,470)	--
Short-Term Borrowings, Net	(950,000)	1,300,000	(4,500,000)
Net Cash Flow Provided By (Used For) Financing Activities	(4,060,821)	8,722,292	(29,069,505)
Cash Flow From Investing Activities
Investment in Restricted Funds	--	(9,000,000)	--
Drawdown of Tax-Exempt Bond Proceeds	2,012,353	1,612,305	427,886
Proceeds from Sale of Generating Assets	1,050,679	--	37,547,381
Stock Redemption from Associated Co.	499,484	--	--
Payment of Taxes on Generating Asset Sale	--	(7,853,047)	(3,925,049)
Proceeds from Sale of Miscellaneous Property	--	208,319	19,800
Investment in Electric Plant	(4,707,152)	(4,746,144)	(4,763,782)
Net Cash Flow Provided By (Used For) Investing Activities	(1,144,636)	(19,778,567)	29,306,236
Increase (Decrease) in Cash and Cash Equivalents	4,884,829	(6,374,563)	5,531,447
Cash and Cash Equivalents at Beginning of Year	610,710	6,985,273	1,453,826
Cash and Cash Equivalents at End of Year	$5,495,539	$610,710	$6,985,273
Supplemental Disclosure of Cash Flow Information:
Cash Paid During The Year For:
Interest	$2,499,080	$3,198,874	$4,289,102
Income Taxes (2001, 2000, and 1999 are net of tax refunds
of $200,000, $499,201, and $208,836, respectively)	$1,499,654	$7,505,312	$5,273,330

See Notes to Consolidated Financial Statements.

(Page 18)

MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets

Assets
	December 31,
	2001	2000
Utility Plant
Electric Plant in Service	$ 82,664,751	$ 78,824,891
Less Accumulated Depreciation	37,782,598	36,289,791
Net Electric Plant in Service	44,882,153	42,535,100
Construction Work-In-Progress	876,179	1,467,818
Total	45,758,332	44,002,918
Investments in Associated Companies	3,600,384	3,907,818
Net Utility Plant and Investments in Associated Companies	49,358,716	47,910,736
Current Assets:
Cash and Cash Equivalents	5,495,539	610,710
Accounts Receivable (less allowance for uncollectible
accounts of $216,500 in 2001 and $334,690 in 2000)	5,544,051	9,140,199
Unbilled Revenue	1,093,767	3,358,301
Inventory	623,543	465,314
Income Tax Refund Receivable	61,646	648,537
Prepayments	408,690	231,597
Total	13,227,236	14,454,658
Regulatory Assets:
Uncollected Maine Yankee Decommissioning Costs	24,708,311	28,055,741
Recoverable Seabrook Costs (less accumulated amortization of
$37,078,399 in 2001 and $35,968,399 in 2000)	16,108,611	17,218,611
Regulatory Assets-SFAS 109 & 106	7,597,091	8,101,240
Deferred Fuel and Purchased Energy Costs	12,106,818	11,977,239
Regulatory Asset - Power Purchase Agreement Restructuring	7,254,750	8,705,750
Unamortized Debt Expense (less accumulated amortization
of $1,132,358 in 2001 and $735,776 in 2000)	2,798,333	3,234,805
Deferred Regulatory Costs, less accumulated amortization	1,427,927	613,556
Total	72,001,841	77,906,942
Other Assets:
Restricted Investments (at cost, which approximates market)	8,104,005	9,876,037
Miscellaneous	643,145	708,503
Total	8,747,150	10,584,540
Total Assets	$143,334,943	$150,856,876

See Notes to Consolidated Financial Statements.

(Page 19)

Capitalization and Liabilities
	December 31,
	2001	2000
Capitalization (see accompanying statements):
Common Shareholders' Equity	$ 42,731,149	$ 39,585,951
Long-Term Debt	33,765,000	34,940,000
Total	76,496,149	74,525,951
Current Liabilities:
Long-Term Debt Due Within One Year	1,175,000	1,050,000
Notes Payable to Banks	3,950,000	4,900,000
Accounts Payable	5,415,525	6,675,215
Accounts Payable - Associated Companies	222,284	271,688
Accrued Employee Benefits	973,768	1,079,131
Dividends Declared	550,729	503,328
Customer Deposits	22,210	19,673
Taxes Accrued	417,160	12,187
Interest Accrued	188,556	948,610
Total	12,915,232	15,459,832
Deferred Credits:
Uncollected Maine Yankee Decommissioning Costs	24,708,311	28,055,741
Income Taxes	21,906,295	21,420,344
Investment Tax Credits	219,594	252,174
Deferred Gain & Related Accounts - Generating Asset sale	3,593,089	7,446,216
Miscellaneous	3,496,273	3,696,618
Total	53,923,562	60,871,093
Commitments, Contingencies, and Regulatory Matters (Note 12)
Total Capitalization and Liabilities	$143,334,943	$150,856,876

(Page 20)

MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARIES

Statement of Consolidated Common Shareholders' Equity

		Par Value	Paid-In	Retained	Treasury
	Shares	Issued	Capital	Earnings	Stock
Balance, January 1, 1999	1,617,250	$13,070,750	$38,317	$27,538,336	$(5,714,376)
Net Income				4,005,556
Dividends:
Common Stock ($1.10 per share)				(1,778,975)
Balance, December 31, 1999	1,617,250	13,070,750	38,317	29,764,917	(5,714,376)
Net Income				5,300,632
Dividends:
Common Stock ($1.24 per share)				(1,966,523)
Stock Repurchased:
Common Stock	(45,000)				(921,763)
Treasury Stock Reissued	648		1,351	(1,314)	13,960
Balance, December 31, 2000	1,572,898	13,070,750	39,668	33,097,712	(6,622,179)
Net Income				5,236,527
Dividends:
Common Stock ($1.34 per share)				(2,108,222)
Treasury Stock Reissued	612		3,794		13,099
Balance, December 31, 2001	1,573,510	$13,070,750	$43,462	$36,226,017	$ (6,609,080)

See Notes to Consolidated Financial Statements.

(Page 21)

MAINE PUBLIC SERVICE COMPANY AND SUBSIDIARIES

Consolidated Statements of Capitalization

	December 31,
	2001	2000
Common Shareholders' Equity
Common Stock, $7 Par Value-Authorized 3,000,000 Shares in 2001 and 2000;
Issued 1,867,250 Shares in 2001and 2000	$13,070,750	$13,070,750
Paid-In-Capital	43,462	39,668
Retained Earnings	36,226,017	33,097,712
Total	49,340,229	46,208,130
Treasury Stock-Total Shares of 293,740 in 2001 and 294,352 in 2000, at cost	(6,609,080)	(6,622,179)
Total	$42,731,149	$39,585,951
Long-Term Debt
First Mortgage and Collateral Trust Bonds:
7.95% Due Serially through 2003-Interest Payable,
March 1 and September 1 *	$ 1,825,000	$ 1,850,000
Maine Public Utility Financing Bank, Public Utility Revenue Bonds:
Refunding Series 1996: Due 2021-Variable Interest Payable Monthly	13,600,000	13,600,000
(1.75% as of December 31, 2001)
Series 2000: Due 2025-Variable Interest Payable Monthly	9,000,000	9,000,000
(1.75% as of December 31, 2001)
Finance Authority of Maine:
1998 Taxable Electric Rate Stabilization
Revenue Notes: Due 2008 - Variable Interest Payable Monthly	10,515,000	11,540,000
(2.0% as of December 31, 2001)
Total Outstanding	34,940,000	35,990,000
Less-Amount Due Within One Year	1,175,000	1,050,000
Total	$33,765,000	$34,940,000

Current Maturities and Redemption Requirements for the Succeeding Five Years and Thereafter Are as Follows:

Long-Term Debt:

2002	$1,175,000
2003	$3,085,000
2004	$ 1,450,000
2005	$ 1,625,000
2006	$ 1,830,000
Thereafter	$25,775,000

* Subject to early redemption premiums as defined in the bond indentures.

See Notes to Consolidated Financial Statements.

(Page 22)

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 marketing subsidiary, Energy Atlantic, LLC, (EA). All intercompany balances and transactions have been eliminated in consolidation.

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 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 March1, 2000. All other fuel and purchased power costs were expensed as incurred.

Revenue Recognition

Operating revenues include sales billed on a cycle billing basis and estimated unbilled revenues for electric service rendered prior to the normal billing cycle. In October 1999, in preparation for retail competition, the Company converted all residential customers to monthly meter reading while the majority had been previously read bi-monthly.

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 2001 and 2000, $961,000 and $380,000, respectively, were recognized as revenue as flexible pricing adjustments, as described in Note 12, "Commitments, Contingencies and Regulatory Matters -- MPUC Approves Elements of Rates Effective March 1, 2000".

On April 1, 1999, the Company began recognizing revenue from the foregone 3.66% rate increase, with an offset to the available value from the sale of the generating assets in accordance with the rate stipulations approved by the MPUC. During 2000 and 1999, $379,000 and $1.3 million, respectively, of revenue was recognized under these Stipulations, as discussed further in Note 12, "Commitments, Contingencies and Regulatory Matters -- Four-Year Rate Stabilization Program".

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 income 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 3.37%, 3.23%, and 2.66% for 2001, 2000, and 1999, respectively.

Bond issuance costs and premiums paid upon early retirements are amortized over the terms of the related debt. Recoverable Seabrook costs and deferred regulatory expenses are amortized over the period allowed by regulatory authorities in the related rate orders. Recoverable Seabrook costs are being amortized principally over thirty years (See Note 12, "Commitments, Contingencies, and Regulatory Matters - Seabrook Nuclear Power Project").

Income Taxes

Statement of Financial Accounting Standards No. 109 (SFAS 109), "Accounting for Income Taxes", requires an asset and liability approach to accounting and reporting income taxes. SFAS No. 109 prohibits net-of-tax accounting and requires the establishment of deferred taxes on all differences between the tax basis of assets or liabilities and their basis for financial reporting.

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 4, "Investments in Associated Companies") using the equity method.

(Page 23)

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.

Reclassifications

Certain reclassifications have been made to the 2000 and 1999 financial statement amounts in order to conform to the 2001 presentation.

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 does not expect the adoption of this statement to have a material impact on its financial position or results of operations.

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)".

	2001	2000	1999
Current income taxes	$ 2,489,429	$ (853,466)	$13,305,318
Deferred income taxes	889,455	4,379,061	(9,857,507)
Investment credits, net	(32,580)	(35,539)	(48,861)
Total income taxes	$ 3,346,304	$ 3,490,056	$ 3,398,950
Allocated to:
Operating income	$ 3,393,006	$3,197,446	$ 3,529,542
Other income	(46,702)	292,610	(130,592)
Total	$ 3,346,304	$ 3,490,056	$ 3,398,950

The effective income tax rates differ from the U.S. statutory rate as follows:

	2001	2000	1999
Statutory rate	34.0%	34.0%	34.0%
Excess Canadian taxes	.1	(1.7)	.7
Amortization of recoverable Seabrook costs	2.6	2.6	3.8
State income taxes	5.6	5.9	10.1
Other	(3.3)	(1.1)	(2.7)
Effective rate	39.0%	39.7%	45.9%

(Page 24)The elements of deferred income tax expense (credit) are as follows:

(Dollars in Thousands)

	2001	2000	1999
Temporary Differences at Statutory Rates:
Seabrook - costs	$ (186)	$ (188)	$ (200)
Liberalized depreciation	118	109	46
AFUDC-borrowed funds	--	(6)	(38)
Deferred fuel	(332)	196	455
Deferred regulatory expense	(27)	(44)	(113)
Flexible pricing revenue	383	--	--
Accrued pension and postretirement benefits	101	31	723
Wheelabrator-Sherman power purchase restructuring	(579)	1,344	1,344
Generating Asset Sale	1,538	2,320	(11,956)
Reacquired debt	(101)	765	--
Other	(26)	(148)	(119)
Total temporary differences - statutory rates	$ 889	$ 4,379	$ (9,858)

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. Dividends received from Maine and New Brunswick were $16,281,664 in 1999, while no dividends were received in 2001 or 2000. In addition to $1,481,644 of regular dividends in 1999, Maine and New Brunswick paid a liquidating dividend of $14,800,000. The regular dividends exceeded earnings by $932,304 in 1999.

The following summarizes accumulated deferred income taxes established on temporary differences under SFAS 109 as of December 31, 2001 and 2000.

	(Dollars in Thousands)
	2001	2000
Seabrook	$ 8,898	$ 9,511
Property	6,663	6,516
Flexible pricing revenue	535	--
Deferred fuel	4,140	4,472
Generating asset sale	(1,013)	(2,551)
Wheelabrator-Sherman Up-front payment	2,894	3,473
Pension and post-retirement benefits	(74)	(175)
Other	(137)	174
Net accumulated deferred income taxes	$21,906	$21,420

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. EA's net income was $897,000 for 2001 compared to $1,688,000 in 2000 and a loss of $354,000 for 1999. The decrease from 2000 reflects the expiration of several large competitive retail contracts in Central Maine Power's (CMP) service territory, as well as the expiration of most medium non-residential service in the Company's service territory. As discussed below, EA also recognized a settlement charge of $1.08 million.

(Page 25)

forth its position that an increase of this magnitude would give it grounds to cancel its contract with EA. EA responded by stating its view that the contract requires Engage to sustain the market risks of increases in the cost of supplying power and that the notice was in breach of the contract. Without agreeing with EA's position, Engage withdrew its notice letter. Subsequently, Engage alleged that EA previously breached the contract in certain respects. EA denied these allegations.

(i) Engage will continue to supply EA with all energy required to perform outstanding retail contracts and the SOS commitments.

(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 cannot be terminated by EA or Engage except upon the willful and material misconduct of the other party.

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.

The Company has determined that EA's activity and related energy contracts are considered non-trading in accordance with EITF 98-10, "Accounting for Companies Involved in Energy Trading and Risk Management Activities".

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. During the quarter ended March 31, 1999, the Company adopted SFAS No. 131, "Disclosure about Segments of an Enterprise and Related Information", which became applicable as a result of the start-up 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. 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. In June, 1999, Maine and New Brunswick sold its generating assets and ceased operations.

(Page 26)

(Dollars In Thousands)
	Twelve Months Ended December 31,
	2001			2000			1999
	EA	MPS	Total Company	EA	MPS	Total Company	EA	MPS	Total Company
Operating Revenues	$15,771	$31,780	$47,551	$38,021	$37,443	$75,464	$8,429	$59,027	$67,456
EA Standard Offer Service Margin	2,147	--	2,147	2,774	--	2,774	--	--	--
Total Revenues	17,918	31,780	49,698	40,795	37,443	78,238	8,429	59,027	67,456
Operations & Maintenance Expense	16,320	23,625	39,945	38,167	29,869	68,036	8,973	47,876	56,849
Taxes	592	2,801	3,393	1,113	2,084	3,197	(209)	3,739	3,530
Total Operating Expenses	16,912	26,426	43,338	39,280	31,953	71,233	8,764	51,615	60,379
Operating Income (Loss)	1,006	5,354	6,360	1,515	5,490	7,005	(335)	7,412	7,077
Other Income & Deductions	(103)	271	168	247	508	755	4	1,161	1,165
Income (Loss) Before Interest Charges	903	5,625	6,528	1,762	5,998	7,760	(331)	8,573	8,242
Interest Charges	6	1,285	1,291	74	2,385	2,459	23	4,213	4,236
Net Income (Loss)	$897	$4,340	$5,237	$1,688	$3,613	$5,301	$(354)	$4,360	$4,006
Total Assets as of December 31,	$5,632	$137,703	$143,335	$6,385	$144,472	$150,857	$1,445	$170,103	$171,548

4. 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 12, "Commitments, Contingencies, and Regulatory Matters -- Capacity Arrangements - Maine Yankee" regarding the closing and decommissioning of Maine Yankee.

Dividends received during 2001, 2000, and 1999 from Maine Yankee were $206,000, $470,000, and $453,750, respectively, and from MEPCO $7,249, $9,061, and $207,974, respectively. In 2001, Maine Yankee completed a stock redemption of $499,484. 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:

(Dollars in Thousands)	Maine Yankee			MEPCO
	2001	2000	1999	2001	2000	1999
Earnings
Operating revenues	$ 61,994	$43,813	$69,439	$4,514	$4,029	$2,936
Earnings applicable to Common Stock	$4,371	$4,640	$4,863	$1,152	$1,363	$3,309
Company's equity share of net earnings	$219	$232	$243	$ 86	$102	$248
Investment
Total assets	$802,118	$915,097	$998,308	$7,396	$6,771	$7,772
Less:
Preferred stock	--	15,000	15,000	--	--	--
Long-term debt	31,200	40,800	48,000	--	--	--
Other liabilities and deferred credits	707,643	788,703	860,330	1,320	1,761	4,043
Net assets	$63,275	$70,594	$74,978	$6,076	$5,010	$3,729
Company's equity in net assets	$3,164	$3,530	$3,749	$455	$375	$279

(Page 27)

5. INVESTMENT IN JOINTLY-OWNED UTILITY PLANT

As more fully explained in Note 12, "Commitments, Contingencies, and Regulatory Matters -- Capacity Arrangements -- Generating Asset Sale", the Company sold its 3.3455% ownership interest in a jointly-owned utility plant, W. F. Wyman Unit No. 4 (Wyman), an oil-fired generation plant on June 8, 1999, as required by the Maine utility industry restructuring legislation. The Company's proportionate share of the direct expenses of Wyman are included in the corresponding operating expenses in the statements of consolidated operations through June 8, 1999.

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 May 24, 2002. These agreements contain certain restrictive covenants including interest coverage tests and debt-to-equity ratios. As of December 31, 2001, 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. On September 15, 2000, the Company entered a temporary line of credit arrangement for $2.5 million with one of the banks that terminated on March 15, 2001. This temporary line was required for working capital needs during this period. 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. As of December 31, 2000, an A Loan for $2.4 million at 8.125% and temporary credit line loans of $1.3 million and $1.2 million at 7.8125% and 8.0%, respectively, were outstanding under these arrangements.

The unregulated subsidiary, Energy Atlantic, LLC (EA) has a revolving line of credit with a bank, established in January, 2000 for $600,000. In November, 2001, the line was increased to $1.2 million and extended until March 31, 2002. EA has requested an extension and an increase to the line of credit and expects renewal on or prior to March 31, 2002. Interest is based on the bank's prime lending rate. As of December 31, 2001, EA was in compliance with the covenants set forth by the line of credit agreement. The line was not used during 2001 and had no balance outstanding as of December 31, 2000.

The Canadian subsidiary, Maine and New Brunswick, cancelled their long-standing $200,000 (Canadian) bank line of credit in April, 2000. This line, which provided for interest at the bank's prime rate, is no longer necessary because of the sale of the generating assets in June 1999.

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. Previously, over a five-year period from September, 1989 to September, 1994, under a similar program, the Company purchased 250,000 shares at a cost of $5.7 million. During 2000, the Company purchased 45,000 shares at a cost of $922,000. Subtracting 612 and 648 shares issued to Company Directors during 2001 and 2000, respectively, as a component of their compensation, 293,740 shares are held as treasury shares with a cost of $6.6 million as of December 31, 2001.

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 $36,226,017 at December 31, 2001.

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. 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 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 2001, the cumulative effective interest rate of the 2000 Series, including issuance costs and credit enhancement fees since issuance was 5.65%.

Certain long-term debt is subject to restrictive covenants consistent with those discussed in Note 6.

(Page 28)

9. 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. No contribution was necessary for the 2001, 2000, and 1999 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, totalling approximately 11.6% in 2001. Effective with retirements after January 1, 1995, only retirees with at least twenty years of service will be eligible for these benefits. In addition, eligible retirees will contribute to the cost of their coverage starting at 60% for retirees with twenty years of service with the contribution phasing out over the next ten years of service so that retirees with thirty or more years of service do not contribute toward their coverage. The Company changed carriers effective January 1, 2002 to mitigate the health-care industry-wide increase in premiums, while maintaining essentially the same coverage.

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 December28,1999 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, 2001, the health care cost trend rate used was 10% in 2002 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:

(Dollars in Thousands)	One-Percentage-Point
	Increase	Decrease
Effect on total cost of service and
interest cost components	$ 84	$ (68)
Effect on postretirement benefit
obligation	$1,033	$(853)

The following table sets forth the plans' change in benefit obligation, change in plan assets, funded status and assumptions as of December 31, 2001 and 2000:

	Pension		Health Care
(Dollars in Thousands)	Benefits		Benefits
	2001	2000	2001	2000
Changes in benefit obligation
Benefit obligation at beginning of year	$15,115	$14,302	$5,343	$4,786
Service cost	342	350	108	86
Interest cost	1,105	1,072	431	381
Amendments	--	303	--	--
Actuarial (gain) loss	1,184	100	2,474	448
Benefits paid	(1,011)	(957)	(426)	(358)
Administrative Expenses	(130)	(55)	N/A	N/A
Benefit obligation at end of year	16,605	15,115	7,930	5,343
Change in plan assets
Fair value of plan assets at beginning of year	16,725	17,861	2,334	2,101
Actual return on plan assets	(853)	(124)	(164)	12
Employer contribution	--	--	901	579
Benefits paid	(1,011)	(957)	(426)	(358)
Administrative Expenses	(130)	(55)	N/A	N/A
Fair value of plan assets at end of year	14,731	16,725	2,645	2,334
Funded Status	(1,874)	1,610	(5,285)	(3,009)
Unrecognized transition (asset) obligation	(94)	(171)	2,327	2,541
Unrecognized prior service cost	749	839	(588)	(648)
Unrecognized net actuarial (gain)/loss	(506)	(3,885)	3,290	488
Accrued benefit cost	$(1,725)	$(1,607)	$ (256)	$ (628)
Weighted-average assumptions as of December 31 (measurement date)
Discount rate	7.00%	7.50%	7.00%	7.50%
Expected return on plan assets	8.50%	8.50%	8.50%	8.50%
Rate of compensation increase	4.50%	4.50%	N/A	N/A

(Page 29)

The following table sets forth the plans' net periodic benefit cost for 2001, 2000, and 1999:

(Dollars in Thousands)	Pension Benefits			Health Care Benefits
	2001	2000	1999	2001	2000	1999
Service cost	$342	$350	$377	$108	$86	$107
Interest cost	1,105	1,072	1,033	431	381	367
Expected return on plan assets	(1,277)	(1,229)	(1,136)	(192)	(182)	---
Amortization of transition obligation	(77)	(77)	(77)	213	213	213
Amortization of prior service cost	90	90	73	(60)	(60)	(15)
Recognized net actuarial (gain)	(65)	(85)	--	29	--	---
Net periodic benefit cost	$118	$121	$270	$529	$438	$672

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 $114,000, $59,000, and $58,000, in 2001, 2000, and 1999, respectively.

10. SFAS No. 133

11. FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company's financial instruments consist primarily of cash in banks, receivables, and debt. The carrying amounts for cash, receivables, and short-term debt approximate their fair value due to the short-term nature of these items. At December 31, 2001, the Company's long-term debt had a carrying value and a fair value of approximately $34.9 million.

12. COMMITMENTS, CONTINGENCIES, AND REGULATORY MATTERS

Industry Restructuring

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;

(Page 30)

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.

According to EITF 97-4, entities should cease to apply Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulations" when a deregulation plan is in place and the terms are known. With respect to the generation portion of the Company's business, this occurred in the fourth quarter of 1999, when the terms where substantially agreed upon by stipulations in the MPUC's proceeding on revenue requirements, rate design and stranded costs in Docket 98-577. This stipulation was approved by the MPUC on January 27, 2000. As more fully discussed in "Capacity Arrangements -- Generating Asset Sale", below, the Company sold all generating assets on June 8, 1999. Correspondingly, the Company adopted SFAS 101, "Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71" for the generation segment of its business in the fourth quarter of 1999. SFAS 101 requires a determination of impairment of plant assets under SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" and the elimination of all effects of rate regulation that have been recognized as assets and liabilities under SFAS 71. The Company has determined no such impairment exists.

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, 2001, $72.0 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.

(Page 31)

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. A stipulation placed before the MPUC in January, 2002 includes 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.

MPUC Investigating Rate Design

(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 cannot predict the nature or the outcome of any decision in this proceeding.

MPUC Approves Elements of Rates Effective March1,2000

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. Furthermore, the Stipulation allowed the 3.66% foregone revenue increase as a result of a rate plan Stipulation approved by the MPUC in its April 6, 1999 Order in Docket 98-865 to be recovered through a reduction in the deferred gain on the asset sale. The Stipulation also provided that the Company's recovery of unamortized investment tax credits and excess deferred income taxes associated with the Company's generating assets must await a final determination ruling from the IRS, which ruling was sought by Central Maine Power Company (CMP). On December 1, 1999, the MPUC approved the October 15, 1999 Stipulation, as described above. In early January, 2000, CMP received its ruling from the IRS which concluded that the unamortized investment tax credits and excess deferred income taxes associated with the sale of the generating assets could not be used to reduce customer rates without violating the tax normalization rules for public utilities. Therefore, in 1999, the Company recognized these excess deferred taxes in income, which amounted to an increase in net income of approximately $389,000.

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 $961,000 and $380,000 of revenues and a corresponding regulatory asset in 2001 and 2000, 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.

(Page 32)

Four-Year Rate Stabilization Plan

On November 13, 1995, the Maine Public Utilities Commission (MPUC) approved a stipulation signed by the Company, the Commission Staff, and the Office of the Public Advocate (OPA). This stipulation, effective January 1, 1996, established a multi-year rate plan for the Company that provided our customers with predictable rates until March 1, 2000, and shares operating risks and benefits between the Company's shareholders and customers. As described in the "Industry Restructuring" and "MPUC Approves Elements of Rates Effective March 1, 2000", above, March 1, 2000 was the beginning of industry restructuring and new rates.

Under the terms of the rate plan, as amended in January, 1998, which applies cost of service principles, the Company's retail rates were increased by 4.4%, 2.9%, and 3.9% on January 1, 1996, February1, 1997 and February 1, 1998, respectively. The Company agreed that it would seek no other increases, for either base or fuel rates, except as provided under the terms of the plan. There were no fuel clause adjustments for the duration of the plan. The rate plan also provided for adjustments resulting from the operation of a profit-sharing mechanism, as well as provisions for mandated costs and plant outage provisions, particularly the shutdown of Maine Yankee, as further explained in the "Capacity Arrangements-- Maine Yankee", below.

The Company was also permitted to defer $1,500,000 annually of the costs of its purchases from Wheelabrator-Sherman during each of the four years of the rate plan. The plan permitted the Company to recover this deferred amount, up to a total of $6,000,000, in rates beginning in the year 2001. The rate plan provided for the deferral until the year 2000, of approximately $1.3 million, net of income taxes, of uncollected retail fuel at the beginning of the rate plan, while an additional $300,000, net of income taxes, will be collected in rates over the rate plan period.

For the final year of the rate plan beginning February 1, 1999, the MPUC granted the Company's request to defer the increase to April 1, 1999, as well as extend the rate plan by one month to February 29, 2000, to coincide with the start of retail competition in Maine.

Subsequently, the MPUC approved a March 25, 1999 Stipulation between the Office of the Public Advocate (OPA) and the Company. Under this Stipulation, the Company was entitled to a 3.66% specified rate increase as of April 1, 1999. Rather than increase customer rates, the Company recognized the revenues that this increase would have generated and, correspondingly, recorded a deferred asset on the Company's books of account to offset the use in rates of available value from the asset sale. The Stipulation also resolved a dispute over the determination of Maine Yankee replacement power costs. The Stipulation allowed the Company to continue to recognize and defer Maine Yankee replacement power costs on an energy-only basis, offset by Wheelabrator-Sherman contract restructuring savings, through the end of the rate plan. The Company agreed to begin amortizing on April 1, 1999, Maine Yankee replacement power costs in the amount of $150,000 per month or a total of $1,650,000 for the remaining eleven months of the rate plan.

As described in "MPUC Approves Elements of Rates Effective March 1, 2000", above, the MPUC approved a Stipulation providing for the recovery in rates of stranded investment, which includes the deferrals allowed under the rate plan.

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, 2001 and 2000 are as follows:

	(Dollars in Thousands)
	2001	2000
Retail	$43,136	$43,136
Accumulated Amortization	(27,027)	(25,917)
Retail, Net of Amortization	$16,109	$17,219

In March 2000, the Company was allowed to offset $5.1 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 4, "Investments in Associated Companies"), the Company's share of any retrospective premium would not exceed approximately $3.2 million or $.5 million annually, without considering inflation indexing.

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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 is 3.2 times higher than the net book value of the assets. This sale of assets was required by the State's electric industry restructuring law. The gain from the asset sale will reduce 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:

	(Dollars in Millions)
Gross proceeds *	$ 38.6
Settlement adjustments	(.1)
Net proceeds	38.5
Net book value	(11.5)
Excess taxes on sale of Canadian Assets	(3.4)
Transition costs, net	(1.9)
Other	.7
Available deferred gain	22.4
Utilization of available value per MPUC orders	(19.0)
Remaining deferred gain, net of tax **	$ 3.4

* 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.

** The $3.4 million deferred gain above is the $3.6 million "Deferred Gain and Related Accounts -- Generating Asset Sale" as of December 31, 2001 reduced by the remaining deferral of transition costs allowed by the MPUC.

The Company offset a portion of its Recoverable Seabrook costs with available value from its deferred asset sale gain as follows:

		Deferred
	Seabrook	Gain
Write-off of recoverable Seabrook Costs	$5,060	--
Write-off of deferred tax liability associated with recoverable Seabrook costs	(3,644)	--
Recognition of deferred asset sale gain	--	$7,006
Recognition of deferred tax associated with deferred asset sale gain	--	(2,795)
Write-off of SFAS 109 Regulatory Asset associated with Seabrook	2,795	--
Net Change	$4,211	$4,211

With the partial liquidation of the subsidiary in December, 1999, approximately $18.0 million of the proceeds were transferred to the first mortgage trustee for paydown of long-term debt. Using these asset sale proceeds and accumulated interest, in 1999 the Company reduced long-term debt by $3.9 million, and, in 2000, the Company used $1.9 million to reduce short-term borrowings and reduced long-term debt by $15.0 million. In addition, the Company paid an early retirement premium of $2.1 million. Consistent with past treatment, the Company has deferred this premium and is amortizing the balance over the remaining life of the original debt issue.

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 Maine Agreement for the decommissioning of Maine Yankee requires the Maine owners, (Central Maine Power, Bangor Hydro-Electric Company and the Company) for the period from March 1, 2000 through December 1, 2004, to hold their Maine retail ratepayers harmless from the amounts by which the replacement power costs for Maine Yankee exceed the replacement power costs assumed in the report to the Maine Yankee Board of Directors that served as a basis for the Plant shutdown decision, up to a maximum cumulative amount of $41 million. The Company's share of the maximum amount would be $4.1 million for the period. For the year ended December 31, 2000, the Company selected the price based on the two-year entitlement auction which was allowed under the agreement. Since this price was below the assumed replacement power price, there was no liability for this period. The Company again selected the two-year entitlement auction price for the year ended December 31, 2001, but on October11, 2000, the Maine Agencies, (the MPUC and the Office of the Public Advocate) rejected the Maine Owners' selection of the sales auction price as the benchmark for calendar year 2001. On December 11, 2000, in separate negotiations, the Company reached an agreement in principal with the Maine Agencies. Under this Agreement, the

(Page 34)

Company incurred no liability for 2001. Pursuant to the Company's filing in early 2002, on January 24, 2002, the MPUC issued a notice of settlement for the remaining years 2002, 2003 and 2004. Since the replacement power benchmark prices for the three-year period were set below the Maine Yankee-assumed prices for these three years, the Commission concurred with the Company's assertion that, in effect, the calculations would result in no additional liability.

With the closing of Maine Yankee, a provision of the Company's rate plan allowing the deferral of 50% of the Maine Yankee replacement power costs went into effect on June 6, 1997. Beginning in May, 1998, Maine Yankee replacement power costs have been offset by net savings from the restructured Purchase Power Agreement with Wheelabrator-Sherman, in accordance with the rate plan stipulation.

From April, 1999 until February, 2000, the Company amortized an additional $150,000 per month as part of a stipulation as described in "Four-Year Rate Stabilization Plan", above. On March 1, 2001, the Company began amortizing $83,300 per month of the Maine Yankee replacement power cost balance and other deferred fuel. As of December 31, 2001, deferred fuel of $12.1 million is reflected as a regulatory asset, which includes the Maine Yankee deferral, as well as deferred Wheelabrator-Sherman fuel costs.

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, and again in December 2001, 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, 2001 is carrying on its consolidated balance sheet a regulatory asset and a corresponding liability in the amount of $24.7 million, which reflects the Company's 5% share of Maine Yankee's December 31, 2001 estimate of decommissioning costs.

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 costs, and the remaining Maine Yankee investment.

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 terminating the contract. 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 the 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 $38.5 million each in connection with the decommissioning operations contract, filed a declaratory judgement 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. That amount represents full payment under the performance bond, plus an additional amount under the payment bond reflecting certain payments 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. The deposit was reflected on its 2001 financial statements.

Maine Yankee is continuing 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 bankrupt estate. The hearing on the claim was held in late 2001, and Maine Yankee expects a decision from the court later in 2002. Recovery of such an additional amount in the Bankruptcy Court is contingent on a number of factors beyond Maine Yankee's control, including the extent to which the bankrupt estate has assets available to pay any amount determined to be recoverable. Maine Yankee therefore cannot predict what amount, if any, it will recover on this claim.

On February 27, 2002, Stone & Webster filed a claim for approximately $6.9 million against Maine Yankee in the Bankruptcy Court in Delaware for alleged breaches of contract and to subordinate Maine Yankee's claims. Maine Yankee cannot predict the outcome of the new claim.

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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.

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. The amended PPA has helped relieve the financial pressure caused by the closure of Maine Yankee as well as the need for substantial increases in its retail rates, and is, therefore, in the best interests of the Company, its customers and shareholders. Energy supply purchases under this contract through February 29, 2000 and all of 1999 were $2.6 million and $14.2 million, respectively. 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 $58.6 million from January 1, 2002 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 $37.1 million through 2006, assuming arrangements similar to the one with WPS-PDI and EA will be in place for that period.

Northeast Empire

On December 19, 1997, the Company announced the signing of an agreement for the purchase of power for approximately 3.4 cents per KWH until March 1, 2000 from Northeast Empire, a 38 MW biomass plant in Ashland, Maine, as a replacement for Maine Yankee energy. Expenses under this agreement during 2000 and 1999 were $1.5 million and $7.8 million, respectively.

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 against the Company as well as a Petition to Alter or Amend the MPUC's September 2, 1998 Order in Docket No. 98-138, which authorized the formation of Energy Atlantic, LLC.

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.

(Page 36)

Construction Program

Expenditures on additions, replacements and equipment for the years ended December 31, 2001, 2000, and 1999, along with 2002 estimated expenditures, are as follows:

(Dollars in Thousands)		2002	2001	2000	1999
		(Unaudited Estimates)
Parent Company
	Generation	$ --	$ --	$ --	$ 12
	Transmission	932	759	1,162	1,277
	Distribution	3,498	3,317	2,660	2,342
	General	913	608	914	1,072
Total Parent		5,343	4,684	4,736	4,703
Energy Atlantic		--	23	10	61
Total		$ 5,343	$ 4,707	$ 4,746	$4,764

(Page 37)

13. QUARTERLY INFORMATION (unaudited)

Quarterly financial data for the two years ended December 31, 2001 is as follows:

	(Dollars in Thousands Except Per Share Amounts)
	2001 by Quarter
	1st	2nd	3rd	4th
Operating Revenues
Maine Public Service	$ 9,863	$ 6,458	$6,557	$8,902
Energy Atlantic	12,206	1,331	2,491	1,890
Total Revenues	22,069	7,789	9,048	10,792
Operating expenses	18,713	8,038	8,074	8,513
Operating income (loss)	3,356	(249)	974	2,279
Interest charges	429	367	299	196
Other income-net	112	(67)	28	95
Net income (loss)	$ 3,039	$ (683)	$ 703	$ 2,178
Earnings per common share	$ 1.93	$ (.43)	$ .44	$ 1.39

	2000 by Quarter
	1st	2nd	3rd	4th
Operating Revenues
Maine Public Service	$ 15,131	$ 6,989	$ 6,490	$ 8,833
Energy Atlantic	2,748	10,668	12,640	14,739
Total Revenues	17,879	17,657	19,130	23,572
Operating expenses	15,448	16,925	18,049	20,811
Operating income	2,431	732	1,081	2,761
Interest charges	942	565	404	548
Other income-net	402	183	152	18
Net income	$ 1,891	$ 350	$ 829	$ 2,231
Earnings per common share	$ 1.17	$ .22	$ .53	$ 1.42

(Page 38)

MAINE PUBLIC SERVICE COMPANY

and Subsidiaries (Unaudited)

Consolidated Financial Statistics

			Consolidated Financial Statistics
		2001	2000	1999	1998	1997
Capitalization Including Bank Borrowings (year-end)
	Debt (including amount due within one year)	52.35%	50.81%	55.11%	61.28%	57.82%
	Common Shareholders' Equity	47.65%	49.19%	44.89%	38.72%	42.18%
Times Interest Earned -
	Before Income Taxes	7.49	4.55	2.73	2.02	0.14
	After Income Taxes	4.96	3.14	1.94	1.52	0.39
Times Interest and Preferred Dividends Earned -
	After Income Taxes	4.96	3.14	1.94	1.52	0.39
Embedded Cost of Long-Term Debt (year-end)		6.33%	6.80%	7.91%	8.10%	7.96%
Common Shares Outstanding (year-end)		1,573,510	1,572,898	1,617,250	1,617,250	1,617,250
Earnings (Loss) Per Share of Common Stock
(average shares)		$3.33	$3.34	$2.48	$1.39	$(1.35)
Dividends Per Share of Common Stock
Declared Basis		$1.34	$1.24	$1.10	$1.00	$1.00
	Paid Basis	$1.31	$1.22	$1.05	$1.00	$1.21
Common Stock Dividend Payout Ratio - *		40.24%	37.13%	44.35%	71.94%	-
Book Value Per Share of Common Stock (year-end)		$27.16	$25.17	$22.98	$21.60	$21.21
Market Price Per Share of Common Stock
	High	$30.75	$27.13	$19 1/8	$17 3/16	$18 3/8
	Low	$23.37	$16.00	$12 7/8	$11 3/4	$10 1/4
	Close	$29.56	$26.38	$17 3/8	$15 1/4	$12
Price Earnings Ratio (year-end) *		8.88	7.90	7.01	10.97	-
Number of Common Shareholders (year-end)		1,001	1,075	1,175	1,436	1,436

* 1997 net losses produce ratios which are not meaningful.

2001 Sources of Income

Millions of Dollars (Total $49.8) and Percent of Total

Energy Atlantic

$17.9 Million [36.0%]

Other Electric Sales

$.8 Million [1.6%]

Other Income

$2.8 Million [5.6%]

Residential

$12.4 Million

[24.9%]

Commercial

$15.9 Million

[31.9%]

2001 Distribution of Income

Millions of Dollars (Total $49.8) and Percent of Total

Other Operating Expenses

$16.4 Million [33.0%]

Interest

$1.3 Million [2.6%]

Common Dividends

$2.1 Million [4.2%]

Retained Earnings

$2.7 Million [5.4%]

Fuel & Purchased Power

$15.0 Million [30.1%]

Wages and Employee Benefits

$7.2 Million [14.5%]

Taxes $5.1 Million [10.2%]

(Page 39)

MAINE PUBLIC SERVICE COMPANY

and Subsidiaries (Unaudited)

Consolidated Operating Statistics

	Consolidated Operating Statistics
	2001 (2)	2000 (2)	1999	1998	1997
Operating Revenues
Residential	$12,381,594	$14,604,703	$21,707,886	$20,592,662	$20,391,688
Small Commercial (1)	5,994,042	7,075,414	10,247,837	9,601,408	9,124,568
Medium Commercial (1)	5,242,061	5,907,941	9,577,895	9,103,982	8,631,470
Large Commercial	4,684,490	6,110,979	10,596,252	10,385,871	9,768,444
Street & Area Lighting	766,466	782,715	885,058	861,082	814,279
Sales for Resale (until 3/1/00)	--	1,797,924	12,536,286	4,229,874	4,307,528
Other Operating Revenues	2,711,471	2,130,646	1,904,903	1,852,027	2,034,219
Energy Atlantic Competitive Energy Supply	15,771,033	37,054,108	--	--	--
Total Operating Revenues	47,551,157	75,464,430	67,456,117	56,626,906	55,072,196
Energy Atlantic Standard Offer Service Margin	2,146,883	2,773,849	--	--	--
Total Revenues	$49,698,040	$ 78,238,279	$67,456,117	$56,626,906	$ 55,072,196
Number of Customers (average)
Residential	29,463	28,791	28,763	28,635	28,561
Small Commercial (1)	5,555	5,299	5,500	5,442	5,402
Medium Commercial (1)	217	194	193	192	188
Large Commercial	16	15	16	16	16
Street & Area Lighting	1,125	1,126	1,127	1,088	1,102
Sales for Resale (until 3/1/00)	--	3	7	8	11
Energy Atlantic Competitive Energy Supply	923	822	--	--	--
Total Customers	37,299	36,250	35,606	35,381	35,280
Energy Deliveries (MWH)
Residential	166,012	166,049	170,481	163,073	167,368
Small Commercial (1)	85,605	87,867	88,570	82,473	81,001
Medium Commercial (1)	107,207	103,914	99,121	94,730	92,078
Large Commercial	160,575	171,023	149,979	147,020	140,842
Street & Area Lighting	3,309	3,259	3,210	3,178	3,119
Sales for Resale (until 3/1/00)	--	38,010	390,587	123,394	110,226
Energy Atlantic Competitive Energy Supply	375,768	824,845	--	--	--
Total Deliveries	898,476	1,394,967	901,948	613,868	594,634

Notes:

(1) Rate class grouping changed to reflect those in effect beginning March 1, 2000.

(2) Revenues beginning March 1, 2000, the beginning of retail competition, reflect the transmission and delivery charges only, and are not comparable to previous years, while the number of customers and energy deliveries in 2001 and 2000 are comparable with prior years.

YEAR-END CAPITALIZATION

(Percent)

	1997	1998	1999	2000	2001
Total Debt	57.82	61.28	55.11	50.81	52.35
Common Equity	42.18	38.72	44.89	49.19	47.65

(Page 40)

Board of Directors

G. Melvin Hovey

Chairman of the Board and Retired President

Maine Public Service Company

Presque Isle, Maine

Pension Investment Committee

Budget and Finance Committee

Robert E. Anderson

Chairman of the Board, Chief Financial Officer and Former President

F. A. Peabody Company

Houlton, Maine

Pension Investment Committee

Budget and Finance Committee

Paul R. Cariani

President and CEO

Maine Public Service Company

Presque Isle, Maine

D. James Daigle

President

D & D Management Co.

Orlando, Florida

Executive Compensation Committee

Audit Committee

Richard G. Daigle

President and CEO

Daigle Oil Company

Cold Brook Energy, Inc., President

Fort Kent, Maine

Audit Committee

Executive Compensation Committee

J. Gregory Freeman

President and CEO

Pepsi-Cola Bottling Company

of Aroostook, Inc.

Presque Isle, Maine

Budget and Finance Committee

Nominating Committee

Deborah L. Gallant

President and CEO

D. Gallant Management Associates

Portland, Maine

Executive Compensation Committee

Nominating Committee

Nathan L. Grass

President

Grassland Equipment, Inc.

Presque Isle, Maine

Executive Compensation Committee

Nominating Committee

J. Paul Levesque

President and CEO

J. Paul Levesque & Sons, Inc.

(Lumber Mill) and

Antonio Levesque & Sons, Inc.

(Logging Operation)

Ashland, Maine

Audit Committee

Pension Investment Committee

Lance A. Smith

President and Co-Owner

Smith's Farm, Inc.

Presque Isle, Maine

No Present Committee Assignments

Maine Public Service Company's ten-member Board of Directors is composed of nine outside

directors and one inside director, Paul R. Cariani. Their diverse business, educational, professional,

and civic backgrounds are valuable assets that provide a broad perspective to the issues concerning the Company.

(Inside Back Cover)

Executive Officers

Paul R. Cariani

President & Chief Executive Officer

James Nicholas Bayne

President and Chief Executive Officer-Elect

William L. Cyr

Vice President

Power Delivery

Larry E. LaPlante

Vice President, Treasurer and Chief Financial Officer,

Secretary and Clerk

Michael A. Thibodeau

Vice President

Human Resources

Kurt A. Tornquist

Controller, Assistant Treasurer & Assistant Secretary

Walter J. Elish

Director of Economic Development

Director and Officer Changes

Donald F. Collins, stepped down from the Board of Directors in May, 2001 after 22 years of service to Maine Public Service. The outgoing director is a former Maine Senator and retired president of S. W. Collins Company, a lumber and hardware business located in Caribou and Presque Isle, Maine. Collins joined the Board on February 28, 1979, replacing his father, Samuel W. Collins, Sr., who was also a State legislator and member of the Board of Directors for 31 years, from 1947 to 1978, serving as Chairman and Honorary Chairman.

Lance A. Smith, 50, currently president and co-owner of Smith's Farm, Inc., joined the Board of Directors in January, 2002. A fifth-generation farmer, Smith is a 1972 graduate of the University of Maine and holds an Associate degree in Business Management. He has managed potato and broccoli farming and sales operations since the early 70's. Today, Smith's Farm, Inc., produces 2,500 acres of broccoli and approximately 3,000 acres of barley, wheat, and soybeans in Northern Maine, and approximately 1,000 acres of broccoli in Hastings, Florida.

In February, 2002, Vice President & General Counsel Stephen A. Johnson, accepted a position with Verrill & Dana, a law firm in Portland, Maine. He was employed at MPS nearly 17 years and will continue to represent the Maine Public Service in a legal advisory capacity.

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 will replace Paul R. Cariani as President on June 1, 2002, and upon Mr. Cariani's retirement effective September 1, 2002, he will also assume 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.

Transfer Agent

The Bank of New York

Shareholder Relations Dept. - 11E

P. O. Box 11258, Church Street Station

New York, NY 10286

Tel. No. 1-800-524-4458

E-Mail: Shareowner-svcs@bankofny.com

Stock Registrar

The Bank of New York

Annual Meeting

Tuesday, May 14, 2002

Form 10-K

The Company will provide shareholders with copies of the Form 10-K upon request.

(Outside Back Cover)

Maine Public Service Company

209 State Street

P. O. Box 1209

Presque Isle, Maine 04769-1209

Tel. No. (207) 768-5811 - FAX No. (207) 764-6586

Home Page: http://www.mainepublicservice.com - E-Mail: info@mainepublicservice.com

Exhibit 99(ag)

STATE OF MAINE

PUBLIC UTILITIES COMMISSION

Docket No. 2001-245

May 8, 2001

PUBLIC UTILITIES COMMISSION

Investigation of Rate Design

of Transmission and Distribution

Utilities

NOTICE OF INVESTIGATION

WELCH, Chairman; NUGENT and DIAMOND, Commissioners

Through this Notice, the Commission initiates an investigation into the rate design of Central Maine Power Company (CMP), Bangor Hydro-Electric Company (BHE), and Maine Public Service Company (MPS).

During the "megacase" proceedings to establish transmission and distribution (T&D) rates effective with the beginning of retail access, the Commission decided not to alter the utilities' basic rate designs so as to avoid customer confusion and disparate rate impacts among customer classes at the start of retail access. [1] See e.g., Order, Docket No. 97-580 at 113-114, 145-146 (Mar. 19, 1999). The Commission did indicate that, after some experience with restructuring, it would examine rate design in light of the fact that utilities now provide only T&D service. Id. at 116; Order, Docket No. 97-596 at 78-79 (Nov. 24, 1999).

The Commission hereby initiates an investigation into the rate designs of CMP, BHE, and MPS. We have decided to proceed, at least initially, through a single investigation because the fundamental issues regarding the design of rates for T&D-only utilities are expected to be common to the three utilities.

In initiating this rate design proceeding, the Commission is aware of the substantial increases in supply prices over recent months. These increases may constrain the extent to which any rate design changes that would further increase rates can be implemented in the near future. [2] For this reason, we are considering focusing our efforts in this proceeding on the following issues:

Notice of Investigation - 2 - Docket No. 2001-245

- to what extent should revenues (T&D and stranded costs) that are currently recovered in per kWh charges be shifted into fixed and/or demand charges;

- should time-of-use periods be set to be consistent with industry standards (i.e. 5 x 16 on-peak period) and, if so, how should revenues be allocated among time periods;

- should seasonal differentials be reduced or eliminated; and

- should any rate design changes be phased-in and, if so, how should the phase-in be accomplished in light of expected decreases in distribution rates under CMP's ARP and the general decline in stranded costs over time.

Under this limited scope approach, the investigation would not examine distribution cost class allocations or a redesign of standby rates. [3] By limiting the scope in this manner, we would hope to reduce controversy and maximize the prospects of accomplishing productive changes to T&D rate design. Prior to making any decisions on the appropriate scope of this investigation, however, we solicit comments from interested persons on this matter.

Any person who wishes to participate in this proceeding as a party must file a petition to intervene with the Commission's Administrative Director, Public Utilities Commission, 242 State Street, 18 State House Station, Augusta, Maine 04333-0018, by May 17, 2001. Petitions to intervene must be in writing and state the name and docket number of this proceeding and how the petitioner is affected by the proceeding. The petition should also include a short and plain statement of the nature and extent of the participation sought. Shortly after the deadline for petitions to intervene, the Commission will send to each proposed intervenor a copy of the service list in this case. Persons that do no want to be a party, but wish to monitor the proceeding may request to be placed on the Commission's interested person list by contacting the Commission's Administrative Director at the same address listed above.

A pre-hearing conference on this matter will be held on May 23, 2001 at 10:30 a.m. in the Commission's hearing room. The purpose of the conference is rule on petitions to intervene, and to discuss the scope of the proceeding, the need for and type of cost studies, and the schedule for processing this Investigation. Any objections to petitions to intervene and written comments on the other matters to be discussed at the pre-hearing conference must be filed by May 21, 2001.

Notice of Investigation - 3 - Docket No. 2001-245

Dated at Augusta, Maine, this 8th day of May, 2001.

BY ORDER OF THE COMMISSION

/s/ Dennis L. Keschl

Dennis L. Keschl

Administrative Director

COMMISSIONERS VOTING FOR:

Welch

Nugent

Diamond

____________

[1] The approach has been referred to as the "no losers" principle.

[2] Certain rate design changes could, however, mitigate supply price increases to those customers most adversely impacted. For example, supply price increases have had the greatest impact on high usage customers. A move away from recovering T&D costs through usage sensitive charges could mitigate to some degree the increases in supply prices for high use customers.

[3] We will consider the allocation of stranded costs among customer classes in our proceeding to re-set stranded costs.

Exhibit 99 (ai)

STATE OF MAINE

PUBLIC UTILITIES COMMISSION

Docket No. 2000-894

July 13, 2001

WPS ENERGY SERVICE, INC.

Complaint Requesting Commission Action to

Amend or Alter Commission Order of

September 2, 1998 in Docket No. 1998-138 and Determine Whether Maine Public Service Co. and/or Energy Atlantic Has Violated The Requirement of the Order or the Provisions of Chapters 301, 304, or 322

PROCEDURAL ORDER

A follow-up case conference in the above-referenced matter was held on July 5, 2001. Based on the presentations at the conference, the following orders are entered:

I. INTERVENTION OF THE IECG

On June 4, 2001, the Industrial Energy Consumers Group (IECG) filed a petition to intervene in this matter. In its petition, the IECG claimed that "it has been and continues to be substantially and significantly involved in the development in competitive markets for electricity, not just in southern Maine, but on a statewide, regional and national levels." At the initial case conference held on June 21, 2001, counsel for MPS argued that it was not clear from the face of the IECG's petition whether any of its members were customers of MPS and how the IECG would be directly affected by the outcome of this proceeding. A representative for the IECG was not present at the case conference. By way of a Procedural Order dated June 27, 2001, counsel for MPS and the IECG were instructed to attempt to resolve this issue informally and report back to the Examiner at the July 5, 2001 conference.

At the conference, counsel reported back that they had not been able to resolve the issue of the IECG's intervention since the last case conference. MPS argued that since the IECG had no members which were customers of MPS they were not directly affected by the outcome in this proceeding and, therefore, should not be given full party status in this matter. MPS indicated that it would agree to limited intervention similar to that granted to Central Maine Power Company (CMP) whereby the IECG would receive all filings and could brief and comment on legal and policy questions. In response, the IECG argued that while it did not have customers in MPS's service territory, its members in other parts of the state had a strong and direct interest in the competitive market and the outcome of this case could impact the ability of Energy Atlantic, which is a competitive energy provider operating statewide, to function in the competitive market.

Under section 720 of the Commission's Rules of Practice and Procedure, a person that is or may be substantially and directly affected by the proceeding shall be

Procedural Order -2- Docket No. 2000-894

allowed to intervene as a party. In addition, any interested person not entitled to intervene pursuant to section 720 may, in the discretion of the Commission, be allowed to intervene and participate as a full or limited party to the proceeding. MPUC Rules, ch. 110, section 72 1.

In this instance, while the IECG may not be substantially and directly affected by the outcome in this proceeding to warrant intervention under section 720, the Examiner finds that their interest is sufficient to warrant full party status pursuant to section 721. Therefore, MPS's objection to the IECG's petition to intervene is overruled and the IECG's petition is granted pursuant to section 721 of the Commission's Rules of Practice and Procedure.

II. ISSUES RESOLVED THROUGH DISPUTE RESOLUTION; REMAINING ISSUES

In the Commission's May 1, 2001 Order Denying in Part and Granting in Part Motions to Dismiss and for Summary Judgment issued in this matter, the Commission referred back to the parties for processing under MPS's dispute resolution procedure the following claims of violations made by WPS in its complaint:

1. disclosure of confidential WPS generation price

information provided in contract unbundling proceedings;

2 disclosure of customer enrollment information to EA;

3. disparate treatment concerning provision of large customer usage data; and

4. failure to include its name as the standard offer

provider on consolidated utility bills.

On June 29, 2001, William Devoe, the investigator selected to handle this dispute, issued his proposed findings and decision on these issues pursuant to MPS's Chapter 304 Implementation Plan. Under Section II(M)(iii) of MPS's Implementation Plan, MPS and the complainant may mutually agree to accept the investigator's findings as the full and final resolution of the dispute, but are not obligated to do so. At the July 5, 2001 conference, counsel for MPS and counsel for WPS indicated that they had agreed to accept the findings and recommendations of the investigator as the full and final resolution of the matters referred back for informal dispute resolution. Therefore, the issues raised by paragraphs 8, 9, 10 and 11 of the WPS complaint will not be addressed in this proceeding.

The remaining issues before the Commission then are:

Procedural Order -3- Docket No. 2000-894

1) Whether Mr. Johnson's involvement at Energy Atlantic exceeded

the "manage like a board of directors" set forth in Docket No. 98

138;

2) Whether experience suggests that Mr. Johnson's dual role is

inherently problematic;

3) Whether the conditions which supported the finding that employee

sharing was to have materially changed since the issuance of the

Commission's Order in Docket No. 98-138;

4) If MPS and EA are to continue to share employees, whether a

clarification of the "manage like a board of directors" standard is

warranted.

III. SCHEDULE

Given the narrowing of the issues in the case, the parties and the Examiner agreed that there was a reasonable likelihood that the case could be presented to the Commission with stipulated facts. Should the parties be able to reach agreement, or partial agreement on the facts, such stipulated facts should be submitted to the Commission on August 3, 2001. To the extent the facts are in dispute, MPS shall submit its pre-filed testimony on that date. A telephonic case conference has been scheduled for August 8, 2001 at 10:00 a.m. to develop the remainder of the schedule in this case.

IV. CHAPTER 307 AUCTION PROCESS

In Paragraph 12 of its complaint, WPS expressed concern about the Chapter 307 (Sale of Capacity and Energy) bidding process given Mr. Johnson's dual role. At the conference, counsel for MPS and WPS indicated that they had worked out a procedure for this year's Chapter 307 auction. The terms of the agreement have been memorialized in a letter dated July 9, 2001 from counsel for MPS.

The Advisory Staff concurs that the terms set forth in the July 9th letter for this year's Chapter 307 bidding process reasonably protect the interests of bidders and MPS's ratepayers and also are workable in terms of MPS's administration of the bid process.

Dated at Augusta, Maine, this 13th day of July, 2001.

BY ORDER OF THE HEARING EXAMINER

/s/ Charles Cohen

Charles Cohen

Docket No. 2000-894

STATE OF MAINE

PUBLIC UTILITIES COMMISSION

WPS ENERGY SERVICE, INC.

Complaint Requesting Commission

Action to Amend or Alter Commission

Order of September 2, 1998, in Docket No.

1998-138 and Determine Whether Maine

Public Service Co. and/or Energy Atlantic

Has Violated the Requirement of the Order

or the Provisions of Chapters 301, 304, or 322

PROPOSED

FINDINGS

AND DECISION

Pursuant to the Commission's Order Denying in Part and Granting in Part Motions to Dismiss and for Summary Judgment dated May 1, 2001, four specific issues were referred to the undersigned in accordance with the dispute resolution procedures set forth in the Implementation Plan for Standards of Conduct for Maine Public Service Company and Energy Atlantic dated July 9, 1999. The issues referred for investigation are identified in paragraphs 8, 9, 10, and 11 of the complaint filed by WPS Energy Service, Inc., with the Commission on or about October 30, 2000. (1)

(1) As a threshold matter, Maine Public Service Company ["MPS"] contends that the issues identified by WPS Energy Service, Inc. ["WPS Energy"] in its complaint are different from the issues advanced by WPS Energy before the Commission and, ultimately, in the context of the investigatory proceeding here. In particular, but without limitation, MPS contends that the allegations of misconduct identified in paragraph 8 of the WPS Energy complaint are materially different from the evidence subsequently adduced in the investigatory proceeding. This contention is rejected. Maine is a "notice pleading" jurisdiction, see, e.g., Shaw v. Southern Aroostook Community School, 683 A.2d 502, 503 (Me. 1996); Bowen v. Eastman, 645 A.2d 5, 7 (Me. 1994). The purpose of a pleading like the complaint submitted here is to fairly apprize the opposing party of the nature of the allegations against them. Except in clearly delineated areas where a more particularized statement of claim is required, as, for example, in areas of fraud or confidential relationships, a generalized statement of facts is sufficient to put the opposing party on fair notice of the claim. Shaw, 683 A.2d at 503;E.N. Nason, Inc. v. Land-Ho Development Corp., 403 A.2d 1173, 1177 (Me. 1979). In this proceeding, the parties are also governed by the notice requirements set forth in the MPS Implementation Plan. Section II (M) (ii) of the Implementation Plan provides that the complaint "need not conform to any particular form, but must be sufficient particularity [sic] to inform the Company of the precise conduct that is subject of the complaint . . . ." Paragraph 8 of the complaint alleges that MPS received information pertaining to WPS Energy bids for retail generation service made to two industrial customers when MPS received copies of Protective Orders in Docket Nos. 2000-441 and 2000-447. It alleges that Stephen Johnson, in his capacity as General Counsel to MPS, improperly disclosed the WPS Energy pricing information to Energy Atlantic employees. While the evidence pertaining to how Mr. Johnson ostensibly obtained WPS Energy pricing information did deviate

in the investigatory proceeding from the manner suggested in the complaint, this deviation is not material to the issue of fair notice to MPS. The alleged misconduct set forth in the complaint was not Mr. Johnson's or MPS's receipt of WPS Energy pricing information; rather, it was Mr. Johnson's alleged dissemination of that information to Energy Atlantic's employees. I find that the WPS Energy complaint gave sufficient notice to MPS of "the precise conduct that is subject of the complaint," as contemplated by the regulations and the MPS Implementation Plan.

Background Discussion

Section 3206 of Title 35-A of the Maine Revised Statutes permits an affiliated interest of a small investor-owned transmission and distribution utility to sell retail generation services to retail customers of electricity within or outside the service territory of the affiliated T & D utility, see 35-A M.R.S.A. section 3206 (1). Pursuant to directives contained in subsection (2) of this law, the Public Utilities Commission has promulgated rules governing the extent of separation between a small investor-owned T & D utility and affiliated competitive electricity provider in order to avoid cross-subsidization and market power abuses by the affiliated entities, see 35-A M.R.S.A. section 3206 (2). The rules promulgated by the Commission are contained in Chapter 304 (65 407 CMR 304-1 et seq.), entitled Standards of Conduct for Transmission and Distribution Utilities and Affiliated Competitive Electricity Providers.

Chapter 304 prohibits the employees of a distribution utility from sharing, with any affiliated electricity provider, market information acquired from any competitive electricity provider, other than information that is generally publicly available, without the permission of the competitive electricity provider. Ch. 304 section 3 (G) (1) at 65 407 CMR 304-4 - 304-5. Chapter 304 also prohibits the employees of a distribution utility from sharing, with any affiliated electricity provider, market information developed by the T & D utility in the course of responding to requests for distribution service, other than information that is generally publicly available. Ch. 304 section 3 (G) (2) at 65 407 CMR 304-4 - 304-5.

Chapter 304 prohibits, as a general rule, the sharing of employees between a distribution utility and its affiliated competitive provider, see Ch. 304 section 3 (K) at 65 407 CMR 304-6. An employee is deemed to be shared if the employee performs work for both of the affiliated utilities. Id. The Commission may approve an exemption from the employee-sharing prohibition if it finds that the proposed sharing arrangement is in the best interest of the public, will have no anticompetitive effect, and that the costs of the shared employees can be fully and accurately allocated between the T & D utility and the affiliated competitive provider. Ch. 304 section 3 (K) (1) at 65 407 CMR 304-6.

Chapter 304 prohibits a distribution utility from giving, through a tariff provision or otherwise, its affiliated competitive provider or customers of its affiliated competitive provider preference over nonaffiliated competitive electricity providers or the customers of nonaffiliated competitive electricity providers in matters relating to any regulated product or service. Ch. 304 section 3 (A) at 65 407 CMR 304-4. Chapter 304 requires that a distribution utility process all similar requests for information in the same manner and within the same period of time. Ch. 304 section 3 (F) at 65 407 CMR 304-4. It also prohibits the T & D utility from providing information to an affiliated competitive provider without a request when information is made available to nonaffiliated competitive providers only upon request. Id.

The WPS Energy Complaint

Pursuant to the Commission's May 1, 2001, order, the undersigned was retained to investigate four specific instances of alleged misconduct by MPS. Paragraph 8 of the WPS Energy complaint alleges that a key MPS employee improperly disseminated WPS Energy pricing information to Energy Atlantic. Paragraph 9 of the complaint alleges that MPS improperly gave to Energy Atlantic information about an aggregate retail customer group acquired when WPS Energy

sought to register the group with MPS. Paragraph 10 of the complaint alleges that MPS failed to include WPS Energy's name on Standard Offer customer bills as requested by WPS Energy, and that, when WPS Energy complained of the omission to MPS, MPS failed to take timely or appropriate corrective action. Paragraph 11 of the complaint alleges that MPS violated the request-for-information provisions contained in section 3 (F) of Chapter 304 of the Commission rules. Each of these allegations will now be considered seriatim. (2)

Paragraph 8 Allegations

Paragraph 8 of the WPS Energy complaint alleges that MPS received bid price information submitted by WPS Energy, and that Stephen Johnson, in his capacity as General Counsel for MPS, received or had access to the same information. Paragraph 8 alleges that Johnson disclosed the WPS Energy pricing information to employees of Energy Atlantic, thus thwarting the intended separation between MPS and its wholly-owned subsidiary, and subverting or threatening to subvert the regulatory framework designed to ensure fair competition for retail generation services. In support of these allegations, WPS Energy proffered testimony from three witnesses: Ed Howard, a Power Marketing Executive for WPS Energy; Tim Charette, also a Power Marketing Executive responsible for wholesale and retail issues; and Harold Durost, who is or was affiliated with McCain Foods, Inc.

(2) MPS has contended, periodically throughout this proceeding, that the allegations made by WPS Energy are but a thinly veiled attempt to take competitive advantage of the standards and restrictions imposed under Chapter 304 and its related statutory and regulatory framework. This contention was never proven, however. The environment in which Energy Atlantic and WPS Energy compete for business is admittedly one with significant regulatory oversight and restrictions. These restrictions serve the public interest, and allegations of misconduct, even when made by a competitor against another competitor, must be fairly weighed. The evidence adduced in the investigatory process here contains no suggestion of any subterfuge or ulterior motive. The conduct of the witnesses, and of counsel for both sides, has been uniformly exemplary and professional. I make no finding that the allegations brought by WPS Energy are frivolous, made for the purpose of gaining an unfair advantage in the marketplace, or to harass, because the evidence supports no such finding.

Mr. Howard has been employed at WPS Energy since approximately August, 1999. Before going to work for WPS Energy, he was employed as the director of wholesale power marketing at Energy Atlantic. Mr. Howard was closely involved with negotiations between WPS Energy and McCain's beginning in late September, 1999. During the course of their negotiations, WPS Energy offered a number of different pricing options to McCain's. One reason for the different pricing structures was that McCain's was considering co-generation as an option, and was in the process of preparing co-generation studies to assess that potential. Eventually, the different proposals were reduced to a single option. McCain's verbally consented to the WPS Energy pricing offer at a meeting that took place in Oak Brook, Illinois, on February 2, 2000. The verbal agreement between WPS Energy and McCain's was eventually reduced to a written contract, which was signed in June, 2000.

According to Howard, Harold Durost of McCain Foods attended a number of meetings with MPS representatives where the subject of electrical delivery to McCain's was discussed. Durost told Howard about an early meeting at MPS, during which Durost shared with MPS details of the WPS Energy bid price package. According to Howard, this information was presented verbally and not in writing. Mr. Howard could not relate the precise nature or content of the information. Durost told Howard that he did not understand or fully appreciate the issues involving separation between MPS and Energy Atlantic at that time. Durost's recollection, as reported by Ed Howard, was that Paul Cariani, President of MPS, reacted to the price information by saying "if we are going to talk about pricing, then we will have to ask Steve to leave."

Tim Charette started working for WPS Energy on April 10, 2000. Before going to work for WPS Energy, Charette worked as a wholesale trader for Energy Atlantic.(3) One day in February or March, 2000, while still employed at Energy Atlantic, he was present in the Energy Atlantic office, working at his computer on a forecasting model for loads within the Energy Atlantic service territory. Also present that day were Cal Deschaine, Barry Bartley, Annette Arribas, Tim Brown, Dawn Theriault, and Jan Currier. Charette heard Steve Johnson come into the office, and walk behind him toward the area where Bartley and Arribas had their desks. Bartley is (or was at the time) a retail account manager. Arribas is a marketing representative. Charette heard Johnson say, under his breath, something about WPS Energy pricing information, and then state "you didn't hear this from me." He said this was not an expression he was used to hearing Steve Johnson say.

Since he was behind Charette, Johnson was not visible to Charette when he made this statement. Johnson was some ten (10) feet away from Charette at this time. Johnson ostensibly faced Bartley and Arribas while he was talking, but it wasn't clear to Charette who he was talking to. Although Johnson spoke under his breath, it was loud enough for Charette and at least seven other Energy Atlantic employees to hear. Charette could not describe the details or the content of the WPS Energy pricing information. He said that he did not recall the substance of that information. Retail pricing is not something Charette was personally involved with. He did not work in marketing or sales, and had "no feeling for what it meant." He recalls Johnson asking Tim Brown whether Energy Atlantic had submitted a bid for the McCain load. Brown responded, "yes, but not for a five year term."

(3) It was suggested during Mr. Charette's testimony that he left Energy Atlantic under a cloud, due to certain unresolved issues pertaining to his vacation time, and that he therefore had an axe to grind against his former employer. I find no credible indication of bias on the part of Mr. Charette. Indeed, without exception, I found that, to the extent there were discrepancies in the accounts of various witnesses, those discrepancies can be resolved without resort to inferences about bias, ulterior motive, or outright fabrication on the part of any witness.

Harold Durost led the negotiations on behalf of McCain's with WPS Energy. He described a roughly six month negotiation leading to a November, 1999, meeting. Durost also had several face-to-face meetings with MPS representatives, around the time McCain's was negotiating its deal with WPS Energy. Present at the MPS meetings were Paul Cariani, Fred Bustard, and Steve Johnson. In the context of the WPS Energy negotiations, McCain's had done a number of co-generation studies. Co-generation would have allowed McCain's to get off the MPS transmission & distribution system altogether. The co-gen studies compared the cost of installing and operating an electrical co-generation system with the cost of staying with the T & D system. Durost believes the co-gen studies were eventually given to MPS.

Durost said the contract price with WPS Energy was never directly discussed at any meeting he had with MPS representatives. He felt it might be possible to glean the relevant pricing information from the co-generation studies. However, the authors of the co-gen studies were not privy to the specific price that WPS Energy would be charging McCain's. Instead, the co-gen studies assumed hypothetical prices suggested to the authors by McCain's. Durost denied telling Ed Howard that he had disclosed WPS Energy pricing information at the MPS meeting. He does recall speaking to Paul Cariani about Energy Atlantic. Durost expressed an interest in receiving a competitive bid from Energy Atlantic. He never disclosed any pricing information to Cariani. Cariani gave him the name of someone at Energy Atlantic that Durost could contact. He told Durost that he (Cariani) had to keep Energy Atlantic at arm's length. Durost is not aware of anyone at McCain's who would have disclosed WPS Energy pricing information to MPS.

For its part, MPS called six witnesses: Steve Johnson; Cal Deschaine; Tim Brown; Barry Bartley; Paul Cariani; and Fred Bustard.

Steve Johnson serves as General Counsel to MPS and as the "primary executive" for Energy Atlantic. As General Counsel, Johnson provides general in-house legal advice to MPS, primarily in the areas of regulatory and corporate law. As primary executive for Energy Atlantic, Johnson serves as the general executive authority within the company. Cal Deschaine, General Manager for Energy Atlantic, reports to Johnson. Johnson was involved in the 1999 negotiations between MPS and McCain's, in which Mr. Durost played a role. Initially, the focus of their negotiations was on the co-generation studies that were part of the McCain expansion plan. The co-gen emphasis "languished" for a period of time before being picked up again, according to Johnson.

Of the two primary co-generation studies, Johnson states that MPS received and relied upon the one by Silkman. It bore a date of May 6, 2000, which would have been after the conversation in Energy Atlantic's offices described by Tim Charette. The May 6, 2000, co-gen study contained no information concerning the WPS Energy offer to McCain's. According to Johnson, Silkman used an assumed price, and the assumed price was different than the WPS Energy offer as we now know it to be. Johnson does not believe that it is possible to extract anything meaningful about the WPS Energy offer from the Silkman co-generation study. Johnson states that he spoke to the author of that study, Mr. Silkman, quite recently, and Silkman agreed that the WPS Energy information could not be extrapolated by reading the co-gen study.(4)

4) Johnson states that Silkman told him he had spoken to Pat Scully, counsel for WPS Energy, told him that the information could not be gleaned from reading the co-gen study. Mr. Scully has indicated that all he and Silkman ever did was trade voice mail messages. I find nothing materially inconsistent between these two versions of the communications between Mr. Silkman and Mr. Scully, especially if we allow, as we must, for the "filtering effect" of Johnson's recollection of what he was told by Silkman. Based upon the proposed findings here, it is not necessary to reach the issue of whether a careful reading of the Silkman study would yield information about WPS Energy's bid price to McCain's.

Johnson does not deny that he was present at a meeting with Durost. He does not recall whether Durost shared pricing information with regard to WPS Energy. If those prices had been revealed, according to Johnson, they would have stayed with him, and he would not have divulged them to anyone employed at Energy Atlantic. Johnson states that he is unable to put Tim Charette's testimony into any sort of context. It is inconceivable, he says, that he would ever do what Charette suggests that he did. At the time of the purported appearance by Mr. Johnson at the Energy Atlantic offices, Energy Atlantic had already made a bid proposal to McCain's, which had been rejected.(5) He would not, therefore, have asked Tim Brown whether a bid had been submitted to McCain's.

Cal Deschaine has been the General Manager at Energy Atlantic since 1999. He was an employee at MPS before going to work for Energy Atlantic. Tim Charette reported to Deschaine in the February/March, 2000, timeframe described by Charette in his testimony. Deschaine understood the separation requirements between MPS and Energy Atlantic. One of his duties is to monitor compliance with the standards of conduct required by the Commission when it granted MPS an exemption from the employee-sharing prohibition. He is aware that no information of the type referred to by Charette can pass from the parent company, MPS, to Energy Atlantic. He has no recollection of the incident described by Charette. He states that, upon learning of Charette's allegations, he interviewed the other employees at Energy Atlantic, and that none of them could recall the incident described by Charette.

(5) According to documents submitted by the parties, on February 4, 2000, Barry Bartley wrote to Durost on Energy Atlantic stationery responding to McCain's solicitation of a bid from Energy Atlantic for electrical power supply to McCain's. Energy Atlantic offered to provide the full load requirements of McCain's Easton plant for 3.98 cents per kilowatt hour, and to provide power to McCain's Washburn facility and Caribou Grimes Road Storage Area for 4.24 cents per kilowatt hour. Durost responded by letter dated February 8, 2000, to Bartley, stating that "Obviously, your quote speaks for itself - Energy Atlantic does not wish to supply McCain with electricity. Perhaps we can discuss again in 5 or 10 years."

Tim Brown is Energy Atlantic's pricing manager. He recalls McCain's rejection of Energy Atlantic's bid to provide generation services. He does not recall the incident involving Steve Johnson related by Tim Charette during his testimony.

Barry Bartley is an account executive at Energy Atlantic. Bartley negotiated with Harold Durost in the context of Energy Atlantic's bid to provide generation services to McCain's. He learned of McCain's rejection of Energy Atlantic's bid when he received the February 8, 2000, letter from Durost. He immediately showed the letter to Deschaine and Brown. He has no recollection of the events surrounding Steve Johnson described by Mr. Charette in his testimony. Bartley says that he first learned the price negotiated between WPS Energy and McCain's in the context of the investigatory hearing in this case.

Paul Cariani recalls the discussions with McCain's that led to a discounted T & D rate from MPS. The co-generation alternative was an important element in those discussions. In the context of those discussions, Durost approached him expressing an interest in obtaining a competitive power supply bid from Energy Atlantic. Cariani told Durost that MPS could not talk with him about supply issues. He said that MPS was not in the supply business. At no time, according to Cariani, did Durost disclose WPS Energy pricing information to him or to anyone else at MPS in Cariani's presence. No one from McCain's ever disclosed this information, to his knowledge.

Fred Bustard has been retired from MPS for about one year. He was previously Vice-President in charge of System Operations and Power Supply there. He recalls that he participated in "all the 1999 meetings." Bustard believes that he saw at least one version of the co-generation study. He says that, for MPS to be able to offer McCain's a discounted T & D rate, it was necessary to evaluate and consider any information pertaining to co-generation alternatives. He does not recall Harold Durost ever disclosing WPS Energy prices in his presence. He knows of no such disclosure by anyone else at McCain's.

Paragraph 8 - Proposed Findings

The misconduct described by WPS Energy in paragraph 8 of the complaint consists of alleged improper dissemination of information, obtained by MPS with regard to WPS Energy pricing, to MPS's wholly owned subsidiary, Energy Atlantic. Numerous avenues have been suggested as to how MPS came by this information, including receipt of the information in the context of material subject to protective orders issued by the PUC; disclosure of the information by Mr. Durost during one or more meetings with representatives of MPS; or between-the-lines analysis of co-generation studies provided to MPS for the purpose of eliciting a discounted T & D rate from that utility. However, the manner in which MPS came to acquire this information, if indeed it did, is only relevant for remedial purposes if one concludes that such information was improperly disseminated to Energy Atlantic. For the following reasons, I do not reach that conclusion.

First, while not directly relevant to the dissemination issue, Harold Durost denied having disclosed WPS Energy pricing information to MPS representatives. Because a disclosure by Durost constitutes the most viable theory on how the information might have come into MPS's hands, his denial that a disclosure had been made seriously erodes the likelihood that MPS subsequently provided that information to its subsidiary. Mr. Howard's recollection of his conversation with Durost, while at odds with Durost's version of what happened, is not so definitive as to the purpose or content of what Durost reportedly told MPS representatives as to cast doubt on Durost's own recollection of those meetings.

Second, with regard to the conversation Mr. Charette says he overheard at the Energy Atlantic offices, the evidence does not allow a finding that MPS breached the standards of conduct in this case. Steve Johnson, in keeping with the exemption granted to MPS by the Commission, and by his own testimony, plays a critical role in the operations of Energy Atlantic. Accordingly, his mere presence in the Energy Atlantic offices on any given day, without more, is hardly deserving of comment. Mr. Charette describes Johnson entering the Energy Atlantic office area behind him, saying something to someone, or to the group as a whole, about prices, and then ending with the statement, "you didn't hear this from me." Mr. Charette could not recall what was said in a definitive way. The statement "you didn't hear this from me" could be interpreted any number of ways, but without a more definitive sense for the context in which it was made the statement becomes a free-floating comment that is devoid of any practical significance for this proceeding.

Accordingly, I find no improper dissemination of information by MPS to employees of Energy Atlantic, and no violation of the standards of conduct set forth in the regulatory framework or the implementation plan on this issue.

Paragraph 9 Allegations

Paragraph 9 of the complaint alleges that WPS Energy acquired the business of an aggregate retail customer group and sent the necessary electronic registration information to MPS. MPS, by necessary inference, then provided information regarding the customer group to Energy Atlantic, which in turn contacted the aggregator to see if the retail group might reconsider its decision and purchase electrical generating services from Energy Atlantic. Because the information regarding this customer group was not available to the public at large, the alleged provision of the information by MPS to Energy Atlantic violates the separation requirement implicit in Ch. 304 section 3 (K) at 65 407 CMR 304-6, and the MPS implementation plan. In support of these allegations, WPS Energy called three witnesses: Ken Borneman, the aggregator referred to in the complaint; Ed Howard; and Dwayne Conley.

Mr. Borneman is a state licensed aggregator who solicits energy supply proposals for potential customer groups, mostly sawmills. In early 2000 Mr. Borneman engaged in discussions with both WPS Energy and Energy Atlantic on behalf of different potential customer groups. On June 30 of that year, verbal consent was obtained for a contract between WPS Energy and a customer group spearheaded by Irving Forest Products. The parties were hoping to make the switch from Standard Offer to the new contract with WPS Energy on July 1, 2000, i.e. the following day. Mr. Borneman communicated IFP's verbal consent to the agreement to Tim Charette at WPS Energy. Later that same day, Mr. Borneman received a call from Tim Brown at Energy Atlantic. Borneman had been in contact with Brown via e-mail in the days preceding the June 30th phone call. Those communications, however, were with respect to a larger group of customers and not specific to the IFP situation.

According to Borneman, Mr. Brown asked Borneman what account he was working on. Mr. Borneman "got the impression" that Mr. Brown was referring to the Irving Forest Products group. Brown wanted to know how long he had been working on this issue. Borneman refused to give him the information he was seeking. Mr. Brown made no specific reference to WPS Energy during this call. Borneman found it odd that he should receive such a call on the same day that WPS Energy was finalizing its agreement with IFP. In Borneman's own mind, "there was a connection." He had no further communications with Tim Brown. After hanging up with Brown, Borneman called Ed Howard to tell him that he had just received "an odd call."

Borneman stated that he was not aware of any violations of the confidentiality rules by MPS or Energy Atlantic. He said that Brown did not reveal any confidential information during

his telephone conversation with Borneman. He characterized Brown's call as "mostly asking questions," and that the questions were general in nature. Brown did refer to a "proposal," but was not specific. Brown did not ask for an opportunity to submit a bid to Borneman's group on behalf of Energy Atlantic. Borneman said that his primary contact at IFP throughout this process was Bruce Nicholson, who was located in St. John, New Brunswick. Borneman also occasionally spoke to others at IFP to whom Mr. Nicholson, at that time, reported.

Ed Howard provided a good deal of the background information concerning the negotiations between WPS Energy and the Borneman aggregate group. On June 30, 2000, at 10:33 A.M., verbal consent to the contractual arrangement with WPS Energy was received from IFP via e-mail. Signatures, however, would not be available until July 10th. Howard spoke to Borneman, telling him that WPS Energy would like to begin the switchover on July 1. Dwayne Conley at WPS Energy contacted Mike Eaton at MPS to see if the switchover could be achieved through a verbal enrollment of the accounts. Eaton got back to him later saying that an accelerated switchover in the manner suggested by Conley would not be done, and that electronic registration would take several days at least. The accounts were eventually registered on July 5 or 6, and service pursuant to the contract began on August 1, 2000.

Howard said that June 30th was a Friday. It was after 4:00 P.M. that he received a call from Ken Borneman, who told him "you'll never guess who just called me." Borneman described his call from Tim Brown, but Howard was unable to recall the specifics. He assumed from Borneman's comments that Brown had called in connection with the Irving Forest Products account. Howard said that he was not sure who at IFP might have provided Brown with information about the contract. The only one Howard ever dealt with on this issue was Ken Borneman, who represented the customer group. Both Bruce Nicholson and Randy McMullin at

IFP had indicated, through Borneman, that individuals at the mills were not told specifics of the contractual arrangement prior to the final deal being struck with WPS Energy.

Dwayne Conley is a Power and Marketing Executive for WPS Energy. Before going to work for WPS Energy, he worked at MPS for a little over ten years. He received the e-mail conveying IFP's verbal consent to the WPS Energy contract from Ken Borneman at 10:33 A.M. on Friday, June 30th. He was instructed to begin the registration process. He knew from experience that electronic registration was slow. He phoned Mike Eaton at MPS to see if there was any way the accounts could be signed up so that service could begin on the first of the month. Eaton called him back in early to mid-afternoon, to say that MPS would not be able to accommodate his request. The enrollment would have to occur electronically. When he spoke to Mike Eaton, Conley is quite sure that he gave Eaton general account information, including the name of the customer group. Conley was present in Ed Howard's office when Howard received the call from Ken Borneman. He is not sure how long after his call with Eaton the call from Ken Borneman came in.

For its part, MPS called four witnesses: Tim Brown; Barry Bartley; Mike Eaton; and Brent Boyles.

Brown testified that, sometime in June, 2000, Energy Atlantic made an offer to provide retail generation services to a group of customers that included Pinkham Lumber. Energy Atlantic's contact at Pinkham was Randy Caron. On either June 28th or 29th, Barry Bartley received correspondence from Caron. Bartley provided Brown with pricing information he had received from Caron. He told Brown that negotiations between the mills and WPS Energy were on a "fast track." Brown called Ken Borneman to inquire as to the status of the negotiations. Brown testified that the group he was specifically interested in was the so-called IFP group. Brown said, however, that had he known WPS Energy had tried to enroll the group with MPS on the 30^th of June, he would have assumed that there was a contract between that group and WPS Energy, and would not have made further attempts to solicit the group's business.

Mr. Bartley testified that he dealt with Randy Caron on the sawmill customer group issue. Caron told Bartley that "St. John" had left it up to him to "do all the wheeling and dealing." Caron expressed an interest in receiving a bid from Energy Atlantic. On June 23, 2000, Energy Atlantic sent a letter to Mr. Caron. Caron said that he would forward the letter on to St. John. Caron called Bartley back on either the 28th or 29th of June. He said that St. John had already received an offer from WPS Energy, and he gave Bartley the prices that Energy Atlantic would have to beat. Bartley asked Caron for the numbers twice to be sure. He wrote the prices down on a piece of paper. He subsequently transferred the numbers onto another sheet of paper that was intended to memorialize his phone conversation with Caron. He said he has no set practice when it comes to keeping records of telephone conversations. Bartley stated that he did not receive any information from MPS on these issues; rather, the source of his information was Mr. Caron.

Mike Eaton is Manager of Information Systems at MPS. He said that he vaguely recalls a conversation with Dwayne Conley in which Conley sought to enroll some accounts on June 30th, the day that meters were being read. He recalls having to check and get back to him. He then spoke to Brent Boyles. Eaton was aware that MPS had accommodated this sort of request once before, and that it had wreaked havoc with their billing system. He acknowledged that Conley may have given him the names of customers in the customer group during their telephone conversation, noting that this was a common practice. After speaking to Boyles, however, he called Conley back and told him that MPS should not accede to WPS Energy's request for verbal registration of the customer group, telling him that it would be "outside the rules." He denied giving any information about the proposed customer group to Energy Atlantic.

Brent Boyles is Manager for Planning and Systems Operations at MPS. He could not recall the conversation with Mike Eaton. He found a copy of an e-mail from Eaton reporting the enrollment request that Eaton had received from Dwayne Conley. The e-mail is dated June 30, 2000, at 1:22 P.M. The e-mail suggests that Eaton told Conley in their initial telephone conversation that the request for manual registration of the customer group would be denied. Boyles said that he never spoke to anyone at Energy Atlantic with respect to this customer group.

Paragraph 9 - Proposed Findings

The misconduct described in paragraph 9 of the complaint consists of alleged wrongful dissemination of information, obtained by MPS with regard to an aggregate retail customer group that had been acquired by WPS Energy, to MPS's wholly owned subsidiary, Energy Atlantic. WPS Energy concedes that it has no direct evidence of communications from MPS to Energy Atlantic on this issue, but points to the timing of the phone call from Tim Brown to Ken Borneman on June 30th, which followed by a very short period of time the conversations between Dwayne Conley and Mike Eaton regarding registration of the customer account. WPS Energy asks that an inference be drawn that Brown placed his call based upon information given to him by MPS. For the following reasons, the evidence does not support such an inference.

First, Ken Borneman's description of his telephone conversation with Tim Brown is, at best, a bit hazy. Although Brown later conceded that he called Borneman to inquire about the IFP account, Borneman could not relate much of the substance of that discussion. Accordingly, nothing about the discussion itself leads to an inference that the only potential source of information for Mr. Brown was MPS. Borneman states that Brown revealed no confidential information during the course of their telephone call; rather, he mostly asked questions.

While it is apparent that Mr. Conley gave MPS information about the customer group when he tried to enroll the group in time for a July 1 switchover, it is also apparent that there were other potential sources of information from whom Mr. Brown could have acquired the basic facts leading to his telephone call with Borneman. It is evident, for one thing, that negotiations were on-going with both Energy Atlantic and WPS Energy with respect to various aggregates of potential retail customers at this time. It is equally apparent that, depending upon the configuration of the group and issues relating to service territory and the like, Irving Forest Products was an entity to whom both Energy Atlantic and WPS Energy were seeking to market their electrical generating services at this time. The prior communications between Borneman and Brown speak to this issue, as do the communications between Brown and Mr. Caron.

It is unclear how many people within the Irving Forest Products system had access to information concerning contract negotiations with WPS Energy. Borneman's statement that he dealt mainly with Bruce Nicholson is tempered by his comment that he also dealt with others in St. John to whom Nicholson reported. Ed Howard's statement that both Nicholson and McMullin told him that individuals at the mills were never told specifics about the contract prior to the final deal being struck is not entirely reliable, both because the assurances were being given second-hand, and because terms like "specifics" and "the final deal being struck" were never defined. It is a common experience in many organizations that senior management believe they hold tighter control over information than, in actuality, they do. Whether this was the case with Irving has not been established, but the evidence speaks to this possibility.

Barry Bartley claims to have received information about the status of IFP negotiations with WPS Energy from Randy Caron. Caron ostensibly gave Bartley the prices that Energy Atlantic would have to beat. WPS Energy casts doubt upon this explanation by noting that the

prices do not accurately reflect the actual deal struck between the IFP group and WPS Energy. However, the information was evidently transferred from Mr. Caron, who may or may not have been an accurate source to begin with, to Mr. Bartley, who then recorded the information twice on two different pieces of paper before conveying the basic facts to Mr. Brown. We might have a better sense of whether the information came to Mr. Brown via the Caron-Bartley route or via the Conley-Eaton route if Mr. Brown had been more specific in his telephone conversation with Borneman.

One cannot conclude, on this record, that the probable source of Mr. Brown's information regarding the deal between the IFP group and WPS Energy was MPS. Accordingly, I find no improper dissemination of information by MPS to employees of Energy Atlantic, and no violation of the standards of conduct set forth in the regulatory framework or the implementation plan on this issue.

Paragraph 10 Allegations

Paragraph 10 of the complaint alleges that for a period of time after March 1, 2000, MPS omitted WPS Energy's name on its Standard Offer customer bills in violation of Chapter 301 of the PUC regulations. WPS Energy also contends that, once notified of the omission, MPS failed to take proper or timely corrective action. Notably, MPS listed WPS Energy simply as "WPS/ESI" on the backs of its customer bills which, in WPS Energy's assessment, does not properly identify WPS Energy in the manner contemplated by Chapter 322 of the Commission rules. WPS Energy contends that the improper identification of WPS Energy on customer bills prevented it from developing name recognition with MPS customers that it serves, a fact that worked to the competitive advantage of Energy Atlantic.

MPS has conceded the error in its billing statements, albeit with certain qualifications. MPS notes that the violation with respect to a complete omission of WPS Energy's name lasted for only two months. MPS contends that, once notified of the problem, it took prompt corrective action, even if it was not precisely what WPS Energy deems acceptable. WPS Energy notes that identifying the electrical provider merely as "WPS/ESI" is not only inaccurate, since the corporation does not refer to itself this way, but it is inconsistent with the manner in which MPS's wholly-owned subsidiary, Energy Atlantic, is identified on MPS bills - there is called "Energy Atlantic," and not simply "EA."

Both parties provided brief testimonial evidence on the issues.

Mike Eaton testified, on behalf of MPS, that once notified of the error, he took corrective action within two days. He was in touch with WPS Energy representatives about the problem, and believes that he obtained approval for the initial corrective action from Dwayne Conley at WPS Energy. He did not become aware that the "WPS/ESI" designation was still a problem until October or November, 2000.

Dwayne Conley recalls talking with MPS about the billing identification issue, but does not recall the content of that discussion.

Ed Howard does not recall being consulted on the issue. He noted that WPS Energy is charged 27 cents per bill by MPS for its billing services. The problem with billing identification presents a lost opportunity for WPS Energy to get its name out to potential customers. He conceded that the loss is hard to quantify.

Both sides have submitted proposals with respect to remediation of the stipulated violation by MPS. WPS Energy proposes that MPS be required to put WPS Energy's logo on MPS bill for a nine month period, corresponding to the period of time that the problem was

unresolved, and that MPS be made to increase the font size of WPS Energy's name to match the font size of MPS itself. In the alternative, WPS Energy proposes that MPS be required to refund part or all of the billing charge, amounting to some $9,180 per month, for the nine months when the name identification problem was on-going. MPS states that putting the WPS Energy logo on MPS bills would lead to potential confusion among their customers, especially if the font size is increased so that it approximates that of the primary billing entity, MPS. MPS also states that such a remedy would force MPS to purchase a high-speed printer at an additional cost of some $40,000, noting that the lack of such a printer today is the reason MPS does not include its own logo on its billing statements. (WPS Energy suggests, in response to this contention, that if MPS acquires the technology in the future to put logos on its bills, it should be made to incorporate the WPS Energy logo at that time. This investigator declines to issue a ruling dependent upon such future contingencies.) Finally, MPS contends that the WPS Energy complaint verges on bad faith, and that, therefore, no monetary sanction is appropriate in these circumstances.

Paragraph 10 - Proposed Findings

For the reasons stated previously, this investigator finds no evidence of bad faith on the part of WPS Energy. Allegations framed in a complaint often differ, sometimes materially, from the evidence presented in a fact-finding proceeding, without any suggestion of bad faith on the part of the complaining entity. Both sides concede that the environment in which they do business is fiercely competitive; it is clear that neither party views the presence of the other as a business competitor in casual terms. The statutory and regulatory framework in which MPS operates requires a studious separation between the T & D utility and its subsidiary competitive provider. This framework forbids employee sharing between related utilities, and the fact that MPS has obtained a conditional exemption from this requirement suggests only that MPS should reasonably anticipate more, not less, scrutiny in the context of its day-to-day operations.

While it is theoretically possible for a competitor like WPS Energy to take advantage of the regulatory framework in order to distract and divert resources that its competitor would otherwise use in the pursuit of business objectives, this begs at least two important questions. The first is the extent to which such an commitment also distracts and diverts the resources of the one registering a complaint against its competitor. The second is the degree to which such accusations, to the extent they are unproven, may, with undue repetition, serve to erode one's credibility before the Commission. There is nothing about the allegations of misconduct in paragraphs 8, 9, 10, or 11 that even remotely suggests that the latter issue is relevant. In any event, both sides concede that a violation of the billing identification requirements occurred. The only remaining issue, therefore, is that of remediation.

There is merit to WPS Energy's contention that the billing statement problem cost WPS Energy an opportunity to develop name recognition with its customers. That is an issue, as WPS Energy readily concedes, that is hard to quantify. The merits of MPS's contention that placing the WPS Energy logo on its billing statement would require the purchase of a high speed printer is difficult to assess, but placing a specific logo, for remedial or other purposes, is not one expressly contemplated by the rules in any event. WPS Energy identifies the period during which the billing statement issue persisted as nine months. MPS notes that the actual period when WPS Energy wasn't identified at all lasted only two months, after which it was identified but in a manner that WPS Energy deems unsatisfactory. MPS also observes that, during the seven month period when this issue remained less than fully resolved, it received no actual complaints from WPS Energy. WPS Energy did not indicate, in its testimony or otherwise, that a complaint had been lodged with MPS during this timeframe.

Accordingly, I find that the billing statement omissions by MPS during the first two months after March 1, 2000, constitute a violation of the Commission rules and, by necessary implication, of the MPS implementation plan. I find that the violation had an anticompetitive effect upon WPS Energy for which WPS Energy deserves compensation from MPS. I propose that MPS reimburse the full amount of its billing charges to WPS Energy for the two month period during which WPS Energy was not identified in any manner on the MPS bills, for a total payment of $18,360.00.

Paragraph 11 Allegations

Paragraph 11 of the complaint alleges that, since deregulation, MPS has routinely provided large customer load or usage information to Energy Atlantic for customers who have been removed from Standard Offer service. WPS Energy requested the same information for customers whom WPS Energy removed from Standard Offer, but was told that it would be too difficult for MPS to provide WPS Energy with this data. WPS Energy informed MPS that it was aware that MPS provided similar information to Energy Atlantic, and only after this disparate treatment was brought to MPS's attention did MPS agree to provide the requested information to WPS Energy. WPS Energy called two witnesses in support of the allegations.

Tim Charette testified that, beginning on March 1, 2000, and going forward, Energy Atlantic was able to obtain telemetered hourly load data that was e-mailed to it in an Excel spreadsheet. This information is useful as a forecasting tool to anticipate load requirements per customer. In the early days, Charette was involved in this process on behalf of Energy Atlantic. Charette does not believe that Energy Atlantic ever made a formal written request for the information. At that time, no such information was being provided to WPS Energy, nor did WPS Energy request such information from MPS.

Dwayne Conley testified that in approximately July, 2000, WPS Energy asked MPS to provide this information for large retail customers outside Standard Offer. Up until that time, Conley was unaware that you could obtain such information from MPS. Charette told Conley that the information was available and could be provided. During the last week of July or the first week of August, Conley spoke to Ward Gerow at MPS. Gerow told him that they were not set up to handle such requests. Conley told him he was aware that Energy Atlantic was receiving similar data for its customers. Gerow responded that this was correct, they were. Gerow then promised to look into it. One week later, on August 9, 2000, WPS Energy began to receive telemetered load information for its large retail customers.

Conley noted that his request was never actually denied by Mr. Gerow. He also noted that no one else at WPS Energy, to his knowledge, had made such a request prior to his conversation with Ward Gerow. Conley never told Gerow that there was any particular urgency to the request. In Conley's view, the one week delay in responding to the request was reasonable. WPS Energy has received this information ever since. Conley indicated that the content of the information they were getting was satisfactory.

MPS called two witnesses on its behalf to speak to the issue. Brent Boyles testified that providing this information fell within his area of supervision, although he had no direct involvement with WPS Energy's request. He said it was accurate to characterize the provision of this data as somewhat burdensome. Boyles said that Ward Gerow did not interpret the WPS Energy request as having any particular urgency. Boyles notes that, while MPS has no affirmative duty to provide this information, it does have a duty to treat the two requests for information equally.

Paragraph 11 - Proposed Findings

The duty to respond equitably to information requests is clear. Without doubt, there was a period of time when retail customer load information was being provided to Energy Atlantic alone. Nothing in the regulations, however, affirmatively requires MPS to provide this information. The only issue is the propriety of the response made by MPS once WPS Energy asked that retail customer load information be given to it. The evidence here suggests that the response made by Mr. Gerow was not proper, in that he initially balked at providing the information, and only made the information available once it was brought to his attention that WPS Energy was aware that similar information was being provided to Energy Atlantic. Mr. Gerow has been characterized as "not very customer-relations oriented." In the absence of any other explanation for Mr. Gerow's response to WPS Energy's request, the investigator accepts this characterization.

The investigator also accepts WPS Energy's own statement that its request for retail customer load information was not marked by any particular urgency, and that the one week delay in implementing delivery of such information was not unreasonable in the attendant circumstances. While the argument can certainly be made that the initial response by Mr. Gerow, coupled with a week's delay in implementing delivery of the information, constitutes a technical violation of the rules, this investigator declines to make such a ruling. The finding of a technical violation without any demonstrated prejudice and with no showing of prejudicial intent or anticompetitive strategy on the part of MPS, serves no useful purpose, and could skew the analysis of more significant issues to which such a ruling might be applied. To the extent there was a demonstrated violation here, it does not rise to the level of materiality implicit in the rules.

Accordingly, I find no violation of the standards of conduct set forth in the regulatory framework or the implementation plan on this issue.

Respectfully submitted this 29^th day of June, 2001.

/s/ William B. Devoe

William B. Devoe, Esq.

Exhibit 99(aj)

STATE OF MAINE

PUBLIC UTILITIES COMMISSION

Docket No. 2001-384

November 20, 2001

MAINE PUBLIC SERVICE COMPANY

Request for Approval of RFP Pursuant to

Chapter 307(6)(B)(3) For Soliciting Bids

On Energy and Capacity Entitlement

ORDER REGARDING

ENTITLEMENT

AGREEMENTS

WELCH, Chairman; NUGENT and DIAMOND, Commissioners

I. SUMMARY

Through this Order, we inform Maine Public Service Company (MPS) that it should enter the agreements it filed on November 6, 2001 to sell capacity and energy entitlements from the Wheelabrator-Sherman Energy Company facility to Energy Atlantic, LLC (EA) and WPS Energy Services, Inc. (WPS).

II. BACKGROUND

On June 6, 2001, MPS filed a proposed request for proposals package (RFP) in accordance with Chapter 307 of the Commission's rules. The purpose of the RFP was to solicit proposals for the purchase of MPS's entitlement to capacity and energy from the Wheelabrator-Sherman Energy Company facility, located in Sherman, Maine, for a term beginning on March 1, 2002. Pursuant to 35-A M.R.S.A. section 3204(4), MPS must sell the entitlement to capacity and energy from any generation asset or contract it does not divest. Wheelabrator-Sherman is MPS's only remaining generation entitlement.

In response to discussions with staff, MPS submitted a revised RFP package on July 24, 2001. On August 2, 2001, the Director of Technical Analysis approved the revised RFP pursuant to Chapter 307, section 6(B)(3).

On October 19, 2001, MPS filed its analysis of the bids. MPS concluded that the value of its Wheelabrator-Sherman entitlement would be maximized by selling 60% to WPS and 40% to EA. Both transactions would be for a two-year period beginning March 1, 2002. On November 6, 2001, MPS filed unexecuted power purchase agreements it negotiated with WPS and EA.

III. DECISION

We have reviewed MPS's analysis of the bids and its agreements with the winning bidders. We concur that the value of Wheelabrator-Sherman entitlements are maximized by selling 60% to WPS and 40% to EA for two years beginning March 1, 2002.

Order - 2 - Docket No. 2001-384

Accordingly, pursuant to Chapter 307, section 7(I), we inform MPS that it should enter the contracts with WPS and EA that it filed on November 6, 2001.[1]

Dated at Augusta, Maine, this 20th day of November, 2001.

BY ORDER OF THE COMMISSION

/s/ Dennis L. Keschl

Dennis L. Keschl

Administrative Director

COMMISSIONERS VOTING FOR:

Welch

Nugent

Diamond

Order - 3 - Docket No. 2001-384

NOTICE OF RIGHTS TO REVIEW OR APPEAL

5 M.R.S.A. section 9061 requires the Public Utilities Commission to give each party to an adjudicatory proceeding written notice of the party's rights to review or appeal of its decision made at the conclusion of the adjudicatory proceeding. The methods of review or appeal of PUC decisions at the conclusion of an adjudicatory proceeding are as follows:

1. Reconsideration of the Commission's Order may be requested under Section 1004 of the Commission's Rules of Practice and Procedure (65-407 C.M.R.110) within 20 days of the date of the Order by filing a petition with the Commission stating the grounds upon which reconsideration is sought.

2. Appeal of a final decision of the Commission may be taken to the Law Court by filing, within 30 days of the date of the Order, a Notice of Appeal with the Administrative Director of the Commission, pursuant to 35-A M.R.S.A. section 1320(1)-(4) and the Maine Rules of Appellate Procedure.

3. Additional court review of constitutional issues or issues involving the justness or reasonableness of rates may be had by the filing of an appeal with the Law Court, pursuant to 35-A M.R.S.A. section 1320(5).

Note: The attachment of this Notice to a document does not indicate the Commission's view that the particular document may be subject to review or appeal. Similarly, the failure of the Commission to attach a copy of this Notice to a document does not indicate the Commission's view that the document is not subject to review or appeal.

___________________

[1] On November 19, 2001, MPS filed a letter requesting approval pursuant to 35-A M.R.S.A. section 707(3) to enter the entitlement agreement with EA to the extent the section applies to the transaction. To the extent necessary, such approval is granted.

Exhibit 99(ak)

STATE OF MAINE

PUBLIC UTILITIES COMMISSION

242 STATE STREET

18 STATE HOUSE STATION

AUGUSTA, MAINE

04333-0018

		WILLIAM M. NUGENT
THOMAS L. WELCH		STEPHEN L. DIAMOND
CHAIRMAN	January 24, 2002	COMMISSIONERS

Stephen A. Johnson, Esq.

Maine Public Service Company

P.O. Box 1209

Presque Isle, ME 04769

RE: Further Settlement Agreement with Maine Parties,

FERC Docket Nos. ER 98-5708 and EL 98-14

Dear Steve:

By letter received on January 10, 2002, and pursuant to the 1998 Further Settlement Agreement with Maine Parties and the January, 2001 Letter Agreement that modifies the 1998 Further Settlement, MPS designated the sale of CMP and BHE power entitlements to Constellation Power Source, Inc. (CPS) for the period March 1, 2002 to February 28, 2005 as the Maine Yankee replacement power benchmark within Article 4 of the Further Settlement for the years 2002, 2003 and 2004.(1)

As you know, after 2001, the Article 4 "account balance" is approximately zero (a debit balance of approximately $100,000). Using the CPS entitlement prices, the replacement power benchmark prices are 3.591cents for 2002, 3.48cents for 2003, and 3.275cents for 2004, compared to the Maine Yankee-assumed prices of 3.86cents, 4.07cents and 4.18cents, respectively. The CPS prices thus produce significant credit balances for all three years, 2002, 2003 and 2004, resulting in an overall credit balance, and no adjustment to MPS' Maine Yankee-related stranded cost recovery.

The Commission has reviewed your benchmark designation analysis. The Maine agencies (the Commission and the Public Advocate) retain the right to object to your benchmark designation if it fails to meet the Article 4 criteria. The Commission believes that the CPS prices may fail to meet the Article 4 criteria. However, even if we adjust the CPS prices as we believe is necessary to meet the Article 4 criteria, or calculate any reasonable market-based cost of replacement energy and capacity for the years 2002, 2003, and 2004, the benchmark replacement

(1) MPS offers two alternatives, one that includes the MPS sale of its Wheelabrator-Sherman entitlement and one that does not.

Stephen A. Johnson Esq.

January 24, 2002

Page 2

power costs are less than the Maine Yankee-assumed prices for all three years. Thus, we concur with MPS's assertion that the resulting Article 4 account balance will be a credit, obviating the need for MPS and the Maine agencies to agree on a calculation of the account balance after each year. In addition, I believe that this letter eliminates the need for MPS to calculate and submit a final calculation, on or before February 1, 2005, of the cumulative Article 4 account balance.

Sincerely,

/s/ James A. Buckley

James A. Buckley

Special Counsel for Restructuring

cc: Stephen G. Ward, Esq.

Exhibit 99(al)

STATE OF MAINE

PUBLIC UTILITIES COMMISSION

Docket No. 2001-240

MAINE PUBLIC UTILITIES COMMISSION

February 27, 2002

Investigation of Maine Public Service

Company's Stranded Cost Revenue

Requirement

ORDER APPROVING

STIPULATION

WELCH, Chairman; NUGENT and DIAMOND, Commissioners

______________________________________________________________________

I. SUMMARY

By way of this Order, we approve a Stipulation entered into between Maine Public Service Company (MPS or Company) and the Office of the Public Advocate (OPA) which establishes a stranded cost revenue requirement for the Company for the period of March 1, 2002 through February 29, 2004. Under the terms of this Stipulation, the Company's distribution delivery rates will stay at current levels on the date that the new revenue requirement goes into effect, March 1, 2002.

II. PROCEDURAL HISTORY

See Appendix A.

III. BACKGROUND

On March 1, 2000, Maine consumers were provided with the opportunity to purchase generation services from the competitive market and, as of that date, the generation portion of electricity service was no longer subject to rate regulation in Maine. As a part of the Restructuring Act, the Commission was required to determine and permit recovery of each utility's stranded costs, defined to be the "legitimate, verifiable and unmitigable costs made

unrecoverable as a result of the restructuring of the electric industry..."35-A M.R.S.A. section 3208.

In Public Utilities Commission, Investigation of Maine Public Service Company's Stranded Costs, Transmission and Distribution Utility Revenue Requirements and Rate Design, Docket No. 98-577 (MPS's so-called "megacase"), the Commission established transmission and distribution (T&D) rates for MPS which reflected a 2-year stranded cost revenue requirement. The 2-year period, which expires on February 28, 2002, was chosen to coincide with the period of time for which MPS had sold its non-divested generation asset entitlements pursuant to Chapter 307 of the Commission's Rules.

Given the pending expiration of MPS's initial sale of entitlement output, the Commission initiated this case on May 8, 2001. As discussed in Section II, infra., since much of the information needed to decide this case was not available at the time we

Order Approving Stipulation 2 Docket No. 2001-240

initiated it, the schedule was segmented into two phases: Phase I involved the identification of major issues, and Phase II included actual rate recommendations using the results from the Chapter 307 bid sale.

On July 12, 2001, the Company filed its Phase I case in this matter. As part of its filing, the Company proposed to flow-through to ratepayers the refund of premium payments made to the Nuclear Electric Insurance Limited (NEIL). At a technical conference held July 24, 2002, however, the Company indicated that it was reversing its position on the NEIL refund and proposing that it be allowed to retain the full amount of the refund for its shareholders. As part of its filing, the Company also proposed that it be allowed to recover in rates over eight years $1.7 million in uncollected revenue resulting from discounts given to two large industrial customers (Huber and McCain Foods). According to the Company, the Commission had approved these deferrals in its "Mega-Case," Docket No. 98-577. The Company projected that its sales would increase by .5% during each of the next two years. The Company estimated that no overall change in its stranded cost revenue requirement from the level set by the Commission in Docket No. 98-577 would be necessary.

The OPA, the IECG and the Advisory Staff filed comments in response to the Company's filing. These comments identified the following issues for future discussion with the Company, the share of ratepayers' responsibility for certain promotional tariffs; the Company's revised treatment of the NEIL termination payment given ratepayers' historical payment of the mutual insurance type premiums; and the level of O&M expenses estimated by Maine Yankee.

On November 19, 2001, in Docket No. 2001-384, the Commission approved Maine Public Service Company's sale of its purchased power entitlements for a period of two years pursuant to Chapter 307 of the Commission's Rules. The Company submitted its updated stranded cost filing on November 28, 2001, which reflected the actual entitlement sale revenues, as well as updates on the Company's Maine Yankee costs, the proceeds received as a result of its Wyman 4 settlement with Central Maine Power Company, revised estimates of the impact of

discounts given to McCain and Huber and updates to its sales forecast to reflect actual sales through September 30, 2001. The Company proposed in this filing that its core T&D rates not change on March 1, 2002 as a result of the resetting of stranded costs.

On December 28, 2001, we received a Stipulation entered into between the Company and the OPA which resolved all of the outstanding issues in this matter.

IV. DESCRIPTION OF THE STIPULATION

The December 28, 2001 Stipulation establishes an annual stranded cost revenue requirement for the period of March 1, 2002 through February 29, 2004 (the rate effective period) of $11,540,000. The agreed-upon rate effective period coincides with the period of the Company's recent Chapter 307 sale. Stranded cost rates would be based on sales of 524,524 MWh in the first year of the rate effective period and 527,147

Order Approving Stipulation 3 Docket No. 2001-240

mWh in the second year. Based on the agreed-upon revenue requirement and level of sales, the Company's distribution delivery rates will not change on March 1, 2002 and the Company's stranded cost rates will decrease by approximately .5% as of March 1, 2003.

To achieve the revenue requirements and rates proposed in the Stipulation, the parties agreed to amortize the remaining balance of the Company's Asset Sale Gain Account during the first year of the rate effective period and to defer for future collection $1,292,000 in stranded costs in year 1 and $4,333,000 in year 2 of the rate effective period. The Company projects that to achieve long-term level stranded cost revenue requirements, it will be necessary to defer additional amounts through 2007, when the Company's contract with Wheelabrator Sherman expires. At that point, the Company's ongoing stranded costs drop significantly, and it will be possible to collect the deferred stranded cost balances without adverse rate impacts.

Regarding Maine Yankee issues raised by the Advisory Staff and the OPA, MPS would retain for its shareholders 15% of the Maine Yankee NEIL terminating refund and flow through to ratepayers, through a reduction in its deferred stranded cost balance, the remaining 85%. In addition, for purposes of calculating the Company's stranded costs, Maine Yankee's total O&M budget for calendar year 2002 was established at $2 million and $1.5 million for each of

calendar years 2003 and 2004.

As part of the Stipulation, the Company has agreed to absorb $135,000 in lost revenues associated with several discounted rate programs and various special rate contracts. Since this amount was already in the Company's T&D rates, MPS agreed to record $135,000 annually as a regulatory liability to be flowed back to ratepayers in the Company's next T&D rate case.

Finally, the parties to the Stipulation agreed to various accounting treatments to be reflected as accounting orders upon the Commission's approval of the Stipulation. Included in the agreed-upon accounting treatments were the carrying costs to be applied to the deferred stranded cost balances; the amortization period for deferrals of lost revenues under special rate contracts previously approved for recovery to the Commission in Docket Nos. 2000-441 and

2000-447; and authority to defer stranded costs in amounts necessary, as discussed above, to maintain the Company's stranded cost revenue requirement at $11,540,000.

V. DECISION

As we have now stated on numerous occasions, to approve a stipulation the Commission must find that:

1. the parties joining the stipulation represent a sufficiently broad spectrum of interests that the Commission can be sure that there is no appearance or reality of disenfranchisement;

Order Approving Stipulation 4 Docket No. 2001-240

2. the process that led to the stipulation was fair to all parties; and

3. the stipulated result is reasonable and not contrary to legislative mandate.

See Central Maine Power Company, Proposed Increase in Rates, Docket No. 92-345(II), Detailed Opinion and Subsidiary Findings (ME. P.U.C. Jan. 10, 1995), and Maine Public Service Company, Proposed Increase in Rates (Rate Design), Docket No. 95-052, Order (Me. P.U.C. June 26, 1996).

We have also recognized that we have an obligation to ensure that the overall stipulated result is in the public interest. See Northern Utilities, inc., Proposed Environmental Response Cost Recovery, Docket No. 96-678, Order Approving Stipulation (Me. P.U.C. April 28, 1997). We find that the proposed Stipulation in this case meets all the above criteria.

The Stipulation before us was entered into between the Company and the OPA. In past cases, we have found that these two entities, representing often opposite views in the ratemaking process, constitute a sufficiently broad spectrum of interests to satisfy the first criterion. See Public Utilities Commission, Investigation of Stranded Cost Recovery, Transmission and

Distribution Utility Revenue Requirements and Rate Design of Bangor Hydro-Electric Company (Phase II), Docket No. 99-185, Order Approving Stipulation (Maine Public Service Company) at 3 (Aug. 11, 2000). We note that while the other parties to this matter, the IECG and the IEPM, did not join the Stipulation, they have not objected to it. We are, therefore, satisfied that a

broad spectrum of interests are represented by the Stipulation.

Based on the record before us, we believe that the process that led to this Stipulation was fair and open. We therefore find that the second criterion for approval has also been satisfied.

Finally, we conclude that the result of the Stipulation is reasonable, not contrary to legislative mandate and consistent with the public interest. The Stipulation resolves the most controversial revenue requirement issue, the flow-through of the NEIL refund, in a manner which we find reasonable and fair. All other revenue requirement issues are also resolved in a manner

which is reasonable and consistent with the public interest. We find the parties efforts, as reflected in the Stipulation, to maintain level stranded cost rates during the next stranded cost rate effective period to be laudable and consistent with the public interest. As we recently noted in Maine Public Utilities Commission, Investigation of Central Maine Power Company's Stranded

Cost Revenue Requirement, Docket No. 2001-232, Order Approving Stipulation at 9, (Feb. 15, 2002) rate stability remains a significant concern as we go forward with the restructuring process.

Accordingly, we

O R D E R

Order Approving Stipulation 5 Docket No. 2001-240

That the Stipulation entered into between the Maine Public Service Company and the Office of the Public Advocate and submitted to us on December 28, 2001 is hereby approved. A copy of the Stipulation is attached hereto[1] and is incorporated by reference.

Dated at Augusta, Maine, this 27th day of February, 2002.

BY ORDER OF THE COMMISSION

_____________________________

Raymond J. Robichaud

Assistant Administrative Director

COMMISSIONERS VOTING FOR: Welch

Nugent

Diamond

THIS DOCUMENT HAS BEEN DESIGNATED FOR PUBLICATION

________________________

[1]One of the exhibits attached to the Stipulation contains confidential information. We have included a redacted copy of that exhibit with the Stipulation attached to this Order. The original Stipulation with the confidential exhibit will be kept in the Commission files, subject to terms of the Protective Order.

Order Approving Stipulation 6 Docket No. 2001-240

NOTICE OF RIGHTS TO REVIEW OR APPEAL

2. Appeal of a final decision of the Commission may be taken to the Law Court by filing, within 21 days of the date of the Order, a Notice of Appeal with the Administrative Director of the Commission, pursuant to 35-A M.R.S.A. section 1320(1)-(4) and the Maine Rules of Appellate Procedure.

Order Approving Stipulation 7 Docket No. 2001-240

APPENDIX A

On May 8, 2001, the Commission issued a Notice of Investigation initiating this docket. That notice identified the likely issues to be addressed and also provided interested persons with an opportunity to intervene.

Timely petitions to intervene were filed by the Industrial Energy Consumers Group ("IECG") and the Office of the Public Advocate ("OPA"). An oral petition to intervene was made by the Independent Energy Producers of Maine ("IEPM") at the initial case conference held on May 23, 2001. There being no objections and good cause appearing to exist, the above-referenced petitions to intervene were all granted in a Procedural Order dated May 29, 2001.

In addition to the above-referenced petitions to intervene, the Commission received requests from Central Maine Power Company ("CMP") and from Bangor Gas Company, LLC ("Bangor Gas") that they be added to the service list in this case as interested persons and receive copies of all filings. These requests were granted without objection subject to the terms set forth in a procedural order issued in Docket No. 2001-232 on May 29, 2001.

A teleconference to discuss scheduling was held on June 5, 2001. Based on the discussions at the conference, a schedule governing the first two phases of the case was established. As set forth in a procedural order of June 27, 2001 the Company's Phase I filing was to address:

1) Stranded cost class cost allocation methodology;

2) A proposal for the treatment of revenue from non-core customers;

3) A proposal for an appropriate QF incentive mechanism on a prospective basis;

4) A comparison of budgeted nuclear expense figures used in the stranded cost calculations developed in the rate case to actual nuclear expenses;

5) MPS's Fall 2000 sales forecast for the three-year period 2001-2003 with a comparison to 2001 actual results;

6) A performance-based ratemaking proposal for resetting stranded cost prices and providing proper incentives;

7) An update of the ASGA balances including amounts amortized for targeted ASGA uses; and

8) Amounts deferred pursuant to the Commission's Order in Docket No. 98-577.

As part of its Phase II filing, the Company was to address:

1) QF cost data and volumes;

2) If available, the sale of the purchased power entitlements;

3) MPS's Fall 2001 sales forecast;

4) Current data regarding MPS's nuclear obligations; and

Order Approving Stipulation 8 Docket No. 2001-240

5) MPS's approach for rate design using illustrative bid revenue and forecasted billing units.

On July 12, 2001, MPS submitted its Phase I filing, consisting of the prefiled direct testimonies of Larry LaPlante/Paula Sperry and Brent Boyles. Technical conferences on the Company's Phase I case were held on July 24, 2001, and on August 9, 2001. On August 16, 2001, the Advisory Staff, the OPA and the IECG filed comments on the Company's Phase I fling. On September 21, 2001, the Company filed rebuttal comments in response to the Staff and intervenor comments.

Technical and settlement conferences were held on October 18, 2001. Based on the discussions at these conferences, the parties and the Examiner agreed that MPS would submit an updated Phase II filing shortly after the results of Company's Chapter 307 auction process became publicly available. On November 19, 2001, the Commission approved the Company's sale of its purchased power entitlements pursuant to Chapter 307 of the Commission's Rules.

The Company submitted its updated Phase II filing on November 28, 2001. This filing consisted of revised pre-filed testimony from Company witnesses LaPlante/Sperrey and Brent Boyles. On December 28, 2001, the Commission received a Stipulation entered into between the Company and the OPA. The other parties to this matter, the IECG and the IEPM, did not object to the Stipulation.

State of Maine

Public Utilities Commission

Docket No. 2001-240

December 26, 2001

Maine Public Utilities Commission

Investigation of Maine Public Service

Company's Standard Cost Revenue

Requirement

Stipulation

The undersigned, being parties to this proceeding, agree as follows:

1. Purpose. This Stipulation is intended to finally and completely resolve the level of recovery of Maine Public Service Company's (MPS) recoverable stranded cost during the period March 1, 2002 through February 29, 2004 (The Rate Effective Period).

2. Stranded Cost Recovery. MPS's total recoverable stranded cost for the Rate Effective Period is the amount shown on Attachment A to this Stipulation, which Attachment is made a part of this Stipulation. The total annual amount of MPS's stranded cost recoverable through the Rate Effective Period shall be $11,540,000 as shown on ST-1, p. 1 of Attachment A to this Stipulation.

3. Special Rate and Contract Discounts. The deferred amount of $1,654,164, from the special discount contracts between MPS, on the one hand, and McCain Foods, Inc. and J. M. Huber Corporation, on the other, will be amortized over eight years and included in stranded cost as shown on ST-1, p. 2 of Attachment A.

4. Sales Forecast. For the purpose of this Stipulation only and for the purpose of calculating stranded cost recovery during the Rate Effective Period, the parties agree that MPS's total retail sales shall be:

3/1/02 - 2/28/03	524,524 MWH
3/1/03 - 2/29/04	527,147 MWH

In order to maintain its annual stranded cost revenue recovery at $11,540,000 during the second year of the Rate Effective Period, MPS shall reduce its stranded cost rate to reflect the additional 2,623 MWH in sales in that year.

4. Maine Yankee Adjustments. For the purpose of this Stipulation only and in order to calculate the Maine Yankee recoverable stranded cost during the Rate Effective Period, the parties agree as follows:

(a) Maine Yankee's total O&M Budget shall be deemed to be $2 million for calendar year 2002 and $1.5 million for each of calendar years 2003 and 2004 subject, however, to any adjustments that may be required as a result of paragraph (c) below;

(b) Recoverable stranded cost shall not include the costs of the ISFSI collections, Texas low level waste compact payments and any increase in decommissioning expense beyond that included in Maine Yankee stranded costs shown on Attachment A, ST-4, p. 1. If any of these costs are charged to MPS after March 1, 2002, MPS will defer these costs and shall be entitled to seek this recovery in rates in the next general rate case following such charge;

(c) MPS agrees to be bound by the Commission's Order for the other Maine owners of Maine Yankee in Dockets 2001-239 and 232 regarding the inclusion of certain DOE litigation expenses and FERC rate case expenses within Maine Yankee's annual O&M budget; and

(d) MPS shall be permitted to retain for its shareholders 15% of its share of the Maine Yankee NEIL terminating distribution refund; it shall flow through to its customers the remaining 85% of its share of this refund by reducing its deferred fuel revenues. This adjustment is shown on Attachment A, ST-3, p. 3.

5. Rate Treatment of Certain Special Discounts. MPS shall not recover from customers $135,000 of the revenue delta, annually, for discounted rates Rate AH, special Rate C, Rate F and EDR and various special rate contracts with industrial customers. Because these amounts are already reflected in MPS's T&D rates, MPS shall record this $135,000, on an annual basis, on its books of account as a regulatory liability and shall reflect this disallowance as an adjustment to its overall T&D revenue requirement at the time of its next T&D rate case.

6. Accounting Orders. In determining the amount of stranded cost recovery for the Rate Effective Period shown on Attachment A, MPS has incorporated certain accounting methodologies to the various elements of stranded costs. Consequently, MPS has requested, and by approval of this Stipulation, shall receive the following accounting orders:

(a) Consistent with its January 24, 2000 Stipulation in Docket 98-577 (as approved by this Commission by Order dated February 17, 2000), (i) MPS will accrue carrying costs on its unrecovered fuel balance during the Rate Effective Period at its net of tax cost of capital rate as authorized by the Commission from time to time during that Period, which rate is presently 7.98% and (ii) during the Rate Effective Period, MPS will amortize the Wheelabrator-Sherman buydown costs at the rate of $1,451,000 per annum.

(b) MPS will amortize over eight years, as shown on Attachment A, the deferred amount of $1,654,164, representing the discount resulting from a May 22, 2000 Power Purchase Agreement between MPS and J. M. Huber Corporation and an April 28, 2000 Power Purchase Agreement between MPS and McCain Foods, Inc., which contracts were approved by this Commission in Docket Nos. 2000-447 and 2000-441, respectively. MPS will also accrue carrying costs on its unrecovered special contract discounts at its net of tax cost of capital rate as authorized by the Commission from time to time during the Rate Effective Period, which rate is presently 7.98%.

(c) In order to attain an annual revenue requirement of $11,540,000 during the Rate Effective Period, MPS will increase its deferred fuel balance as reflected on Attachment A, ST-3, p. 3.

(d) In order to accomplish the disallowance described in paragraph 5 above, MPS will record $135,000, annually, on its books of account as a regulatory liability until its next general T&D rate case.

7. Stipulation Not Precedential. The making of this Stipulation by the parties shall not constitute precedent as to any matter of law or fact, except as provided herein, nor shall it prevent any party from making any contention or exercising any right, including rights of appeal, in any other Commission proceeding or investigation or other trial or action.

In Witness Whereof, the Parties have caused this Stipulation to be signed by their respective attorneys.

MAINE PUBLIC SERVICE COMPANY

December 26, 2001

By______________________________

Stephen A. Johnson, General Counsel

OFFICE OF THE PUBLIC ADVOCATE

December , 2001

_______________________________

Stephen G. Ward, Public Advocate

Stipulation 2001-240