WESTMORELAND COAL (WLBAQ) 10-K 2002 FY Annual report

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2002

OR

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

For the transition period from _______ to _______.

Commission File No. 001-11155

WESTMORELAND COAL COMPANY
(Exact name of registrant as specified in its charter)

Delaware	23-1128670
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

2 North Cascade Avenue, 14th Floor, Colorado Springs, CO 80903
(Address of principal executive offices)                               (Zip Code)

Registrant’s telephone number, including area code:(719) 442-2600

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

TITLE OF EACH CLASS	NAME OF STOCK EXCHANGE ON WHICH REGISTERED
Common Stock, par value $2.50 per share	American Stock Exchange
Depositary Shares, each representing    one-quarter of a share of Series A Convertible    Exchangeable Preferred Stock
Preferred Stock Purchase Rights

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

Series A Convertible Exchangeable Preferred
   Stock, par value $1.00 per share

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, 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 is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

                          X 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

                 Yes   X      No  ___

The aggregate market value of voting common stock held by non-affiliates as of June 28, 2002 was $83,118,000.

There were 7,731,083 shares outstanding of the registrant’s Common Stock, $2.50 Par Value (the registrant’s only class of common stock), as of March 3, 2003.

There were 827,333 depositary shares, each representing one quarter of a share of the registrant’s Series A Convertible Exchangeable Preferred Stock, $1.00 par value per preferred share, outstanding as of March 3, 2003.

The definitive proxy statement to be filed not later than 120 days after the end of the fiscal year covered by this Form 10-K is incorporated by reference into Part III.

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WESTMORELAND COAL COMPANY
FORM 10-K
ANNUAL REPORT
TABLE OF CONTENTS

Item Page

PART I

1	Business	2
2	Properties	14
3	Legal Proceedings	26
4	Submission of Matters to a Vote of Security Holders	32

PART II

5	Market for Registrant's Common Equity and Related Stockholder Matters	33
6	Selected Financial Data	36
7	Management's Discussion and Analysis of Financial Condition and Results of Operations	37
7A	Quantitative and Qualitative Disclosures About Market Risk	61
8	Financial Statements and Supplementary Data	63
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	108

PART III

10	Directors and Executive Officers of the Registrant	108
11	Executive Compensation	108
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	108
13	Certain Relationships and Related Transactions	108
14	Controls and Procedures	108

PART IV

15	Exhibits, Financial Statement Schedule, and Reports on Form 8-K	109
Signatures		116

1

Certain statements in this report which are not historical facts or information are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including, but not limited to, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations. Any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. For example, words such as “may,” “will,” “should,” “estimates,” “predicts,” “potential,” “continue,” “strategy,” “believes,” “anticipates,” “plans,” “expects,” “intends,” and similar expressions are intended to identify forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties and other factors, which may cause the actual results, levels of activity, performance or achievements of the Company, or industry results, to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others, the following: general economic and business conditions; healthcare cost trends; the cost and capacity of the surety bond market; the Company’s ability to manage growth and significantly expanded operations; the ability of the Company to implement its business strategy; the Company’s ability to pay the preferred stock dividends that are accumulated but unpaid; the Company’s ability to retain key senior management; the Company’s access to financing; the Company’s ability to maintain compliance with debt covenant requirements; the Company’s ability to successfully identify new business opportunities; the Company’s ability to achieve anticipated cost savings and profitability targets; the Company’s ability to negotiate profitable coal contracts, price reopeners and extensions; the Company’s ability to maintain satisfactory labor relations; changes in the industry; competition; the Company’s ability to utilize its tax net operating losses; the ability to reinvest excess cash at an acceptable rate of return; weather conditions; the availability of transportation; price of alternative fuels; costs of coal produced by other countries; demand for electricity; the effect of regulatory and legal proceedings; the claims between the Company and Montana Power; and the other factors discussed in Items 1, 3 and 7 below. As a result of the foregoing and other factors, no assurance can be given as to the future results and achievement of the Company’s goals. The Company disclaims any duty to update these statements, even if subsequent events cause its views to change.

References in this document to www.westmoreland.com, any variations of the foregoing, or any other uniform resource locator, or URL, are inactive textual references only. The information on our Web site or any other Web side is not incorporated by reference into this document and should not be considered to be a part of this document.

PART I

ITEM 1 - BUSINESS

Westmoreland Coal Company (“Westmoreland” or “WCC”) traces its origin as a coal company to businesses established in 1853 and incorporated in Delaware in 1910. The term “Company” as used herein includes WCC and its subsidiaries.

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The Company’s current principal activities, all conducted within the United States, are: (i) the production and sale of coal from Montana, North Dakota and Texas; (ii) the development, ownership and management of interests in cogeneration and other non-regulated independent power plants; and (iii) the leasing of capacity at Dominion Terminal Associates, a coal storage and vessel loading facility, prior to its sale in March 2003. Refer to Item 8 - Financial Statements and Supplementary Data for more information regarding the Company’s operating segments.

COAL OPERATIONS

In 2001, the Company substantially expanded its coal business by acquiring the coal operations of Entech, Inc. a subsidiary of Montana Power Company (“Montana Power”) and MDU Resources Group, Inc.‘s subsidiary, Knife River Corporation. These operations are described below and in Item 2 – Properties.

Westmoreland Resources, Inc. (“WRI”) - WRI is owned 80% by the Company and 20% by Washington Group International (“WGI”), formerly known as Morrison Knudsen Company, Inc., which also mines the coal for WRI on a contract basis. WRI operates the Absaloka Mine, a surface operation located on approximately 15,000 acres containing subbituminous coal reserves in the Powder River Basin near Hardin, Montana. The Absaloka Mine was expressly developed to supply coal to Xcel Energy’s (formerly Northern States Power) Sherburne County Station near Minneapolis, Minnesota. Over the years, it has sold coal to several other upper Midwest utilities. WRI’s contract with Xcel expired at the end of 2002 and was replaced by two new base price escalating contracts, one for 3.4 million tons per year with the Sherburne County Station and one for 350,000-450,000 tons per year with the A.S. King Station. These new contracts were effective as of January 1, 2003 and will expire December 31, 2007. The Absaloka Mine has provided coal to Xcel since 1974. WRI also has a contract executed August 27, 1986 and last amended January 1, 2003 with Western Fuels Association, the fuel buyer for Southern Minnesota Municipal Power Agency (“SMMPA”), which owns a portion of the Sherburne County Station Unit 3. This contract currently provides for WRI to supply all SMMPA’s requirements at Unit 3 and expires at the end of 2007. WRI shipped a total of 5,160,000, 5,904,000, and 4,910,000 tons of coal in 2002, 2001 and 2000, respectively. Transportation is arranged and charges are paid by WRI’s customers. The Company received cash dividends from WRI of $4,960,000 in 2002, $4,400,000 in 2001 and $8,400,000 in 2000.

Westmoreland Coal Sales Company (“WCSC”) - WCSC is a wholly owned subsidiary of the Company responsible for the sales and marketing of coal. WCSC entered into a Sales Agency Agreement with WRI during 2002 under which WCSC provides sales, marketing, and contract administration services in exchange for a per ton fee from WRI. In addition to obtaining the new Sherburne County Station and A.S. King Station coal contracts for WRI, WCSC entered into a new coal contract with Xcel Energy for one million tons per year to be delivered to Sherburne County Station Units 1&2 commencing January 1, 2004 and expiring December 31, 2006. WCSC may source coal under this contract from either or both WRI or Western Energy Company (a wholly owned subsidiary of the Company). WCSC also sells third party coal to industrial and institutional accounts and provides contract sales management services for Arch Coal, Inc. under certain of Arch’s non-utility sales contracts.

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Westmoreland Mining LLC (“WML”)- WML is a wholly owned, separate subsidiary of WCC that was formed as required by the lenders providing financing for the acquisitions of the operating coal business of Entech, Inc. and the coal assets of Knife River Corporation. WML provides management and administrative support to its subsidiaries including legal, environmental, sales and accounting services. WML’s wholly owned subsidiaries are Western Energy Company, Northwestern Resources Co., Dakota Westmoreland Corporation, and Westmoreland Savage Corporation. WML is located in Billings, Montana.

Western Energy Company (“WECO”) -WECO was acquired in April 2001 as part of the acquisition of the coal business of Entech. WECO operates the Rosebud Mine in Colstrip, Montana, a surface mine in the Northern Powder River Basin. The Rosebud Mine is one of the largest coal mines in the United States and WECO sold 10,061,000 and 11,284,000 tons of subbituminous coal in 2002 and 2001 (7,610,000 tons for the eight months after the acquisition by Westmoreland). After mining the coal, WECO crushes it and sells it without further preparation. WECO’s primary customers are the owners of the four-unit, mine-mouth Colstrip Station, which has a combined electric generating capacity of approximately 2,200MW. This coal is sold under long-term contracts expiring in 2009 for Colstrip Units 1 and 2 and 2019 for Colstrip Units 3 and 4. The Colstrip Units 1 and 2 contract has a base price with adjustment provisions for certain costs and the Colstrip Units 3 and 4 contract is a cost-plus arrangement. WECO also supplies coal to Minnesota Power under a coal supply agreement that expires in 2003 and provides periodic fixed percentage increases to the price and to several smaller customers under contracts of varying term.

Northwestern Resources Co. (“NWR”) -NWR was also acquired in April 2001 as part of the acquisition of the coal business of Entech. NWR operates the Jewett Mine, located in central Texas, and supplies surface-mined lignite to the two electric generating units at the Limestone Electric Generating Station (“LEGS”), located adjacent to the mine. LEGS is owned by Texas Genco (“TGN”), a publicly-traded, majority-owned subsidiary of CenterPoint Energy, Inc. (“CNP”) formerly Reliant Energy, Inc. (“Reliant”). The lignite is sold under a long-term Amended Lignite Supply Agreement (“ALSA”) that expires in 2015. Since July 1, 2002, tonnages and price are determined sequentially on an annual basis pursuant to a procedure under which NWR and TGN commit to the number of tons to be supplied and a price determined according to a formula which estimates an equivalent value of Powder River Basin coal if delivered to the plant that year as described in Item 3 - Legal Proceedings. For 2002, NWR sold 7,105,000 tons of lignite under the ALSA. For the full year of 2001, NWR sold 7,138,000 tons of lignite (4,463,000 tons for the eight months since WCC’s acquisition).

Dakota Westmoreland Corporation (“DWC”) -DWC was formed in 2000 to acquire part of the coal assets of Knife River Corporation. DWC operates the Beulah Mine, a lignite surface mine near the town of Beulah, North Dakota. For 2002, DWC sold 3,006,000 tons of lignite under long-term coal agreements with the Heskett Generating Station in Mandan, North Dakota, and the Coyote Station adjacent to the mine. For the full year of 2001, the Beulah Mine sold 3,087,000 tons (2,014,000 tons for the eight months after WCC’s acquisition) of lignite. During 2002, approximately 84% of the tons were shipped to Coyote and the remainder to Heskett and several small non-utility customers. The Coyote agreement, which has a base price with adjustment provisions for certain costs, expires in 2016. The Heskett agreement, which is priced largely based on the Coyote agreement, expires in 2005 and has a five-year extension at expiration at DWC’s option.

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Westmoreland Savage Corporation (“Savage”) -Savage (formerly named WCCO-KRC Acquisition Corporation), was also formed in 2000, to acquire other parts of the coal assets of Knife River Corporation. Savage operates the Savage Mine near Sidney, Montana. This is a lignite surface mine which in 2002 sold a total of 337,000 tons of lignite primarily to the nearby Lewis and Clark Station under a full requirements, base price contract with an adjustment provision for certain costs. This contract expired on December 31, 2002 but was extended by the parties to March 31, 2003. Negotiations are on-going for a replacement contract, and the Company expects that this new agreement will continue the forty year relationship between the mine and plant and will include prices and terms similar to or better than those in the prior contract. Savage also has a contract, expiring August 31, 2003, with Sidney Sugars, Inc. (formerly the Holly Sugar Sidney plant), to provide lignite and ash disposal services for sugar beet processing. Savage also expects to renew this contract at prices and terms similar to or better than those in the prior contract.

The following tables show, for each of the past five years, tons sold and revenues derived from mines that were, at the time of production, owned by the Company. The Company had no export sales during the five-year period ended December 31, 2002.

Year	Coal Sales in Equivalent Tons (in 000’s)	Coal Revenues in Dollars (in 000’s)
2002	26,062	301,498
2001	20,503	231,048
2000	4,910	35,137
1999	5,466	38,539
1998	6,458	44,010

Tonnage sold by the Company pursuant to contracts calling for deliveries over a period longer than one year is considered a long-term contract. The table below presents the percentage of coal tonnage sold under long-term contracts for the last five years:

Sales Tonnage Under Long-Term Contracts
2002	100%
2001	99%
2000	100%
1999	100%
1998	98%

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The following table presents estimated minimum total sales tonnage under existing long-term contracts for the next five years from the Company’s existing mining operations. The prices for all future tonnage are subject to revision and adjustments based upon market prices, certain indices and/or cost recovery.

Projected Sales Tonnage Under
Existing Long-Term Contracts (in millions of tons)
2003	27.3
2004	26.7-27.7
2005	26.2-27.2
2006	25.2-26.2
2007	24.6-25.6

The tonnages in the table above represent backlog commitments under existing, signed contracts and generally exclude pending or anticipated contract renewals or new contracts. These projections reflect customers’ scheduled major plant outages where known. The projections also assume a range of 7.0-8.0 million tons per year under the ALSA between NWR and TGN. The ALSA, which expires in 2015, provides for eighteen month forward determinations of annual volumes on a Btu basis, as further described in Items 2 and 7 below. The parties have committed to 104 trillion Btu’s (approximately 8 million tons) for 2003 and are in the process of negotiating volumes for 2004, 2005 and potentially additional years. NWR supplied 7.1 million tons under the ALSA in 2002, 7.1 million tons in 2001, and 8.2 million tons in 2000.

The weighted average price under long-term contracts was $11.31 in 2002, $11.05 in 2001 and $7.16 in 2000.

In 2002, the Company’s two largest contracts accounted for 58% of its coal revenues. Colstrip 3 and 4 and TGN accounted for 20% and 38%, respectively. No other customer or contract accounted for as much as 10% of the Company’s 2002 coal revenues. The long-term contract with WECO’s largest customer, Colstrip Units 3 and 4, expires in 2019. NWR’s long-term contract with TGN expires 2015. The Company anticipates replacing sales as contracts expire with extensions, new contracts or spot sales over the life of the coal reserves.

Other Acquisition Assets.In connection with the 2001 acquisitions, the Company assumed ownership of Basin Resources, Inc. (“Basin”), North Central Energy Company (“North Central”), Horizon Coal Services, Inc. (“Horizon”), and Western Syncoal LLC (“SynCoal”). Basin formerly operated the Golden Eagle Mine west of Trinidad, Colorado and was a subsidiary of Entech. Basin ceased operations in 1995 and is inactive. Westmoreland is seeking to dispose of Basin’s assets and obligations. North Central holds the land and water rights associated with the mining operations of Basin as well as certain mineral rights for coalbed methane gas in southern Colorado. Horizon’s only asset is a royalty interest in coal reserves located in Campbell County, Wyoming at the Caballo Mine owned by Peabody Energy. The royalty of $.10 per ton covers the mining of 225 million tons of coal making the gross royalty amount $22,500,000. The latest mine plan delivered to Horizon by Peabody Energy in March 2003 indicates that mining of coal subject to the royalty will begin in late 2006. SynCoal was a synthetic coal production facility located in Colstrip, Montana and is inactive. In January 2003, SynCoal transferred ownership of its physical assets to Westmoreland Power, Inc. and then SynCoal was sold along with its intellectual property rights and bench demonstration equipment in exchange for assumption of certain liabilities and obligations by the buyer. In addition, in 2001 WCC acquired the right to develop the lignite deposits at Gascoyne, North Dakota in the Knife River acquisition.

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INDEPENDENT POWER OPERATIONS

Westmoreland Energy, LLC (“WELLC”) (formerly named Westmoreland Energy, Inc.) owns and manages interests in independent power projects. WELLC, through various subsidiaries, currently has interests in three such power projects, all of which are operational. Each project has a single purchaser of the power and a single steam host. The Company is scheduled to receive distributions from its ROVA plants in January and July of each year. Refer to Note 3 of the Consolidated Financial Statements for additional information concerning WELLC, including specific project operational statistics.

WELLC’S independent power projects sell electricity through long-term power sales contracts to utilities. There are three types of independent power projects: cogeneration projects which provide two types of useful energy (e.g., electricity and thermal energy, like steam) sequentially from a single primary fuel (e.g., coal); small power producers which utilize waste, biomass or other renewable resources as fuel; and exempt wholesale generators (“EWG”) which provide electrical energy without the requirement to sell thermal energy or use waste or renewable resources as fuel sources. WELLC has invested in cogeneration projects and in projects that are EWGs. For WELLC, the key elements of an independent power project are a long-term contract for the sale of electricity, long-term contracts for the fuel supply, a suitable site, required permits and project financing. Cogeneration projects require another long-term contract for the sale of the steam or other thermal energy. The economic benefits of cogeneration can be substantial because, in addition to generating electricity, a significant portion of the energy is sequentially used to produce steam or high temperature water (thermal energy) for industrial processes. Electricity is sold to utilities and, in certain situations, to end-users of electrical power, including large industrial facilities. Sequentially produced thermal energy from the cogeneration plant is sold to commercial enterprises and other institutions. Large industrial users of thermal energy include plants in the chemical processing, petroleum refining, food processing, pharmaceutical, pulp and paper industries.

Westmoreland Power, Inc. (“WPI”) was formed to acquire certain rights from Knife River Corporation and to pursue new independent power development. On February 28, 2001, the Company announced that it had submitted a proposal to develop, own and operate, either independently or in partnership, a new state-of-the-art 500 MW lignite-fired power plant near Gascoyne, North Dakota in connection with Lignite Vision 21 (“LV-21”). WPI acquired the right to develop the lignite deposits at Gascoyne from Knife River Corporation. LV-21 is a partnership between the state of North Dakota and the Lignite Energy Council (“LEC”) that is administered by the North Dakota Industrial Commission (“NDIC”) and is designed to encourage construction of a new baseload power plant in North Dakota. Project proposals were also submitted by MDU Resources Group, Inc. (“MDU”), Great River Energy and Great Northern Properties. During 2002, Great River Energy withdrew its project from consideration. MDU and WPI joined together to pursue development of a new lignite fired generation unit near Gascoyne, North Dakota and executed a joint development agreement. On September 27, 2001, the Industrial Commission approved the joint MDU-WPI project and awarded up to $10 million in matching funds to facilitate feasibility and various technical studies after approval of the joint project WPI and MDU each own a 50% interest in the project. In January 2003, MDU-WPI requested funding from the NDIC for additional feasibility studies. These additional studies related to substituting a proposed 250MW lignite fired plant for the proposed 500MW plant and include expansion of completed generation technology, air quality and lignite mine studies. In February 2003, the NDIC approved these additional feasibility studies which are expected to be completed in the third quarter of 2003.

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TERMINAL OPERATIONS

Westmoreland Terminal Company, a wholly owned subsidiary of the Company, owned a 20% partnership interest in Dominion Terminal Associates (“DTA”), the owner of a coal storage and vessel-loading facility in Newport News, Virginia, at December 31, 2002. The Company leased ground storage space and vessel-loading capacity and facilities to others and provided related support services. DTA’s annual throughput capacity is approximately 18,000,000 tons, with a ground storage capacity of 1,400,000 tons. DTA loaded 6,398,000, 7,980,000 and 7,160,000 tons in 2002, 2001 and 2000, respectively. The Company’s portion of these tons was 74,000, 197,000 and 163,000 in 2002, 2001 and 2000, respectively.

On January 29, 2003, the Company entered into a letter of intent with a subsidiary of Dominion Resources, Inc. to sell its 20% partnership interest in DTA and its industrial revenue bonds for total consideration of $10.5 million. A Purchase and Sale Agreement was executed on March 14, 2003. Under the terms of the Purchase and Sale Agreement, Westmoreland Terminal Company will guarantee throughput through the terminal for a period of three years. To secure the throughput commitment, the purchaser will deposit $6.0 million of the sale proceeds as collateral for a stand-by letter of credit for the purchaser. Westmoreland Terminal Company made certain representations about the status of its partnership interest, the industrial revenue bonds being purchased and the general condition of DTA and agreed to indemnify the purchaser for any loss incurred as a result of a breach of these representations. The liability for a breach of the representations and warranties is capped at $4.5 million. The representations and warranties will expire at various times over the next several years. Westmoreland has guaranteed Westmoreland Terminal Company’s obligations under the Purchase and Sale Agreement for a period of five years in an amount that will decline to $2.5 million after 2 1/2 years. As a result, the Company will recognize a pretax gain of approximately $4.5 million when the transaction closes. Closing is expected to take place promptly after receipt of all bank and partnership consents or following expiration of DTA partnership rights of first refusal. At closing, the purchaser will assume all of Westmoreland Terminal Company’s DTA partnership obligations. The Company will no longer incur DTA-related operating losses, which were $2,050,000, $1,922,000 and $1,800,000 in 2002, 2001 and 2000, respectively. Due to the sale of the Company’s investment, the financial results relating to DTA have been presented as Discontinued Operations in the accompanying Consolidated Statements of Operations.

OTHER OPERATIONS

On July 3, 2002, the Company formed Westmoreland Risk Management Ltd. (“WRM”), a wholly owned captive insurance subsidiary in Bermuda, for the purpose of providing risk management services to the Company and its subsidiaries. The captive company commenced providing a portion of property and casualty insurance effective October 1, 2002. The Company has elected to report it as a taxable entity in the United States.

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The Company idled the Virginia Division in 1995 and completed the sale of substantially all its assets by 1999. No tons were shipped from the Virginia Division during 2002, 2001 or 2000. There were no asset sales during 2002, 2001 or 2000. The Company transferred the Bullitt refuse area permit in November 2002. The remaining Virginia assets had no recorded book value and the purchaser assumed the remaining reclamation obligation.

Refer to Note 13 of the Consolidated Financial Statements for additional information regarding the Company’s business segments.

GENERAL

Employees and Labor Relations

The Company, including subsidiaries, directly employed 882 people on December 31, 2002, compared with 918 people on December 31, 2001.

Westmoreland was party to a wage agreement with the United Mine Workers of America (“UMWA”), which was effective December 16, 1993 and expired on August 1, 1998. Basin was also a party to a separate wage agreement with the UMWA which was also effective December 16, 1993 and expired on January 1, 1998. The Company is not a party to any successor or subsequent national wage agreement with the UMWA. WECO is, however, a party to an agreement with Local 400 of the International Union of Operating Engineers (“IUOE”). DWC and Savage assumed agreements with Local 1101 of the UMWA and Local 400 of the IUOE, respectively, when the coal assets were purchased from Knife River Corporation.

Competition

The coal industry is highly competitive. The Company competes principally on price and quality of coal with other coal producers of various sizes. However, the Company has a transportation advantage where its mines are located adjacent to its customers’ power plants. The Company’s production accounted for approximately 3% of coal production in the United States in 2002. Coal-fired generation was responsible for more than 50% of all electricity generated within the United States in 2002.

The Company’s steam coal production also competes with other energy sources in the production of electricity. Factors such as the price of natural gas and the cost of environmental compliance are major considerations in the decision to operate or build and bring on line substantial new coal-fired generation. The price of natural gas has been volatile over the past year (ranging from a low of $2.26 per MMBTU in February 2002 to a high of $4.65 per MMBTU at year end 2002 and increasing to $8.51 as of March 3, 2003) making the relative price stability in the coal market a significant contributor to renewed interest in constructing new, more environmentally friendly coal-fired generation.

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The Company also generates electricity directly from projects in which WELLC owns an interest, and sells it on a wholesale long-term contract basis to utilities under rates established in power purchase agreements and approved by regulatory agencies. The independent power industry has grown rapidly over the past twenty years, accelerating in the 1990‘s due, in part, to electric utility deregulation initiatives. In the initial years following implementation of deregulation, prices for electricity were quite competitive in some states as a result of low fuel prices and a relatively high level of surplus capacity. Increasing energy demand, volatile fuel prices, and the failure of growth in generating capacity to keep pace with the increase in demand for power converged in 2000 to result in power shortages and higher electricity prices in many parts of the country. This combination of factors, coupled with price volatility in the natural gas market, helped create renewed interest in coal-fired capacity.

The principal sources of competition in this market include traditional regulated utilities seeking to maximize utilization of existing capacity, unregulated subsidiaries of regulated utilities, energy brokers and traders, energy service companies in the business of developing, operating, and marketing energy-producing projects, equipment suppliers and other non-utility generators like WELLC and WPI. Competition in this industry is substantially based on price. The lowest cost generating units will be the most competitive in the market place and will run more frequently. Today new generating capacity must compete on a cost per kilowatt basis and be capable of complying with stringent and ever-changing environmental regulations.

Mining Safety and Health

Westmoreland places the safety of its employees above all else and has an active safety and education program at every operation. Savage and Beulah had worked 340 and 285 days, respectively, without a lost time accident as of December 31, 2002. Other mines had more recent lost time accidents but the Company’s overall average remains below national averages. The Company’s mining operations are subject to state and federal legislation including the Federal Coal Mine Safety and Health Act of 1969 and the 1977 Amendments thereto, which prescribes mining health and safety standards. In addition to authorizing fines and other penalties for violations, the Act empowers the Mine Safety and Health Administration to suspend or halt offending operations.

Energy Deregulation

The highly publicized California energy crisis in early 2001 sparked renewed interest in a national energy policy based on a multi-pronged strategy involving energy efficiency and conservation, and maximizing domestic resources. Increased coal utilization and additional federal funding for clean coal research and technologies are prominently featured in the national energy policy debate. As a direct consequence, interest in building new coal-fired generation has increased. Many new generating facilities, including the Company’s potential LV-21 project, have been publicly announced. However, much of the announced capacity will not be built. The Company believes that the collapse of Enron, which fueled much of the interest in pure merchant capacity, and the emergence of a tight credit market combined to cause cancellation of a significant amount of the announced capacity. As the country’s economy slowed down so too did the growth rate in electricity consumption. The Company expects that, when the economy begins to grow, the demand for power will also grow and investment in new generating capacity and transmission should occur.

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At both the national and state level, the debate about deregulation of electricity and the creation of competitive markets for wholesale and retail sale of electricity continue. While events in California, including rolling blackouts and extreme market fluctuations in energy prices, the collapse of Enron and significant credit issues facing major utilities have influenced the debate, many states and the federal government continue to consider creating competitive wholesale and retail power markets. System reliability and transmission issues, including wheeling power from one system to another and system constraints (insufficient line capacity to add new electricity), are among the factors being analyzed and the pace at which these problems are solved will affect how quickly competitive power markets may become a reality. The public debate once again includes reference to regulatory concepts like “fair and reasonable rates” not only for transmission of electricity but also generation of electricity

WELLC’s ROVA I and ROVA II generating units are located in Weldon, North Carolina. These facilities are EWGs. EWG status allows the ROVA facilities to operate with certain exemptions from federal and state regulation. Pursuant to the provisions of the National Energy Policy Act of 1992, an EWG can provide power without the requirement that it also sell thermal energy as a Qualifying Facility (“QF”). An EWG can be a QF as defined in the Public Utilities Regulatory Policies Act of 1978 but is not required to maintain QF status. EWGs that are not QFs must have rates approved by the Federal Energy Regulatory Commission (“FERC”). Both ROVA I and ROVA II have rates approved by FERC.

Protection of the Environment

Mining Operations.The Company believes its mining operations are in compliance with applicable federal, state and local environmental laws and regulations, including those relating to surface mining and reclamation, and it is the policy of the Company to operate in compliance with such standards. The Company maintains compliance primarily through the performance of reclamation, maintenance and monitoring activities. Utilization of coal to generate electricity produces certain by-products, the emission of which is subject to Federal regulation. Depending on coal purity and the combustion process, the emission by-products may include nitrogen oxides (NO_x), sulfur dioxide, carbon dioxide and mercury among others. Emission levels vary among generating units. The newer an electric generating unit, the fewer emissions are produced in the combustion process.

Clean Air Act

In 1990, certain amendments to the Clean Air Act (“1990 Amendments”) were enacted. As the first major revisions to the Clean Air Act since 1977, the 1990 Amendments vastly expanded the scope of federal regulations and enforcement in several significant respects. In particular, the 1990 Amendments required that the United States Environmental Protection Agency (“EPA”) consider or issue new regulations related to ozone non-attainment, air toxics and acid rain. Phase I of the acid rain provisions required, among other things, that certain electric utility power plants reduce their sulfur dioxide (SO₂) emissions to effectively less than 2.5 pounds per million Btu by January 1, 1995. Phase II required essentially all utility power plants to reduce emissions to effectively less than 1.2 pounds per million Btu by January 1, 2000. The 1990 Amendments allow utilities the freedom to choose the manner in which they will achieve compliance with the required emission standards. Recently, both the EPA and Congress have become more focused on promulgating some type of air toxics regulation. All coal-fired generating plants could be impacted by such regulations. The Company cannot currently determine the effect of such proposed regulations on its operations.

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Clear Skies and Global Climate Change Initiatives

On February 14, 2002, President Bush announced two major initiatives, the Clear Skies Initiative and a Global Climate Change Initiative. The Clear Skies Initiative proposes cuts in power plant emissions of NO_X,SO₂ and mercury. Under the President’s plan, SO₂ emissions will be reduced 73% from current levels of approximately 11 million tons to a cap of 4.5 million tons in 2010 and 3 million tons in 2018. NO_x emissions will be reduced by 67% from current levels of approximately 5 million tons to a cap of 2.1 million tons in 2008 and 1.7 million tons in 2018. Mercury emissions will be reduced by 69% from current levels of approximately 48 tons to a cap of 26 tons in 2010 and then to 15 tons in 2018. This policy initiative envisions use of an emissions permit limit program modeled after the 1990 Clean Air Act Acid Rain Program and encourages use of new and cleaner pollution control technology. All coal-fired generating plants could be impacted by President Bush’s Clear Skies Initiative or a similar proposal. Sen. Jeffords of Vermont proposed even more stringent regulation of NO_x, SO₂and mercury and regulation of carbon dioxide emissions. Both Sen. Jeffords and President Bush’s proposals will continue to be debated in Congress. The Company cannot currently determine the effect either the Jeffords or Bush proposal could have on its operations.

The Global Climate Change Initiative calls for a cut in greenhouse gas intensity by 18% over the next ten years. Greenhouse gas intensity is the ratio of greenhouse gas emissions to economic output. The Global Climate Change Initiative seeks to lower the United States rate of emissions from an estimated 183 metric tons to 151 metric tons per million dollars of gross domestic product. The Global Climate Change Initiative is comparable to the average progress that nations participating in the Kyoto Protocol are required to achieve. The Company cannot currently determine the effect of the Clear Skies and Global Climate Change Initiatives on its operations.

State Initiatives

State specific environmental legislation may impact Company operations. For example, Texas has passed regulations requiring all fossil fuel fired generating facilities in the state to reduce NO_x emissions to 0.165 pounds per million Btu on an annual average basis beginning in May 2003. This standard may be met by the application of new technology, fuel, characteristics, or emission credits. The Texas NO_x regulations may impact lignite usage at LEGS. See Item 7, Managements Discussion and Analysis, for more information. Other states are evaluating various strategies for improving air quality and reducing emissions. Passage of other state specific environmental laws may further affect the Company’s operations. The Company is monitoring events and issues to evaluate the effects of any new environmental law or regulations.

Mine Reclamation

As of December 31, 2002, the Company has reclamation bonds in place in Montana, North Dakota, Texas, and Virginia to assure that operations comply with all applicable regulations and to assure the completion of final reclamation activities. The amount of the bonds exceeds the estimated cost of final reclamation of $235,271,000. Final reclamation obligations estimated to cost $50 million at the Jewett Mine are the responsibility of its customer, which has issued a corporate guarantee to assure performance of its reclamation obligation. At the Rosebud and Absaloka Mines, certain customers and WRI’s contract miner, WGI, are obligated to either perform or reimburse the Company for certain reclamation activities as they are performed. These reclamation activities are estimated to cost approximately $21,981,000. As of December 31, 2002, WML had $49,484,000 in cash escrowed and invested to use for future reclamation activities at the Rosebud Mine, which activities are estimated to cost approximately $139,000,000 and will be performed through approximately 2025.

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The reclamation obligations associated with the Bullitt refuse area were transferred to the new permitee in November 2002.

Independent Power. The environmental laws and regulations applicable to the projects in which WELLC and WPI may or do participate primarily involve the discharge of emissions into the water and air, but can also include waste disposal, wetlands preservation and noise regulation. These laws and regulations in many cases require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies. Meeting the requirements of each jurisdiction with authority over a project can delay or sometimes prevent the completion of a proposed project, as well as require extensive modifications to existing projects. The partnerships that own the projects in which WELLC has an interest and the partnership through which WPI and MDU are pursuing the LV-21 project have the primary responsibility for obtaining the required permits and complying with the relevant environmental laws.

On December 17, 1999, the EPA issued regulations under Section 126 of the Clean Air Act (the “Section 126 rule”) calling for combined NO_xreductions of 510,000 tons during each annual ozone season (May 1 – September 30) from certain named power stations in the Eastern U.S., including ROVA I and II. The additional NO_xreductions are to begin in 2003. The rule responds to petitions filed by several northeastern states under Clean Air Act Section 126 and seeks to control upwind NO_x emissions which the petitioning states allege prevent them from attaining the one hour ambient air quality standard (.15 ppm) for ozone. The rulemaking approach is an alternative to regional NO_x reductions called for in the EPA NO_x State Implementation Plan (“SIP”) Call which was challenged by industry groups. One of the most significant differences between the NO_x SIP Call and the Section 126 rule is that under the Section 126 rule, the EPA regulates the individual source directly. Each source is assigned an emissions allocation. The baseline for 2003-2007 NO_x emissions allocations is the average of the highest date for any two years in the 1995-1998 period. Allocation budgets will be updated in five-year increments and the EPA will inform sources of their allocations three years in advance. Initial allocations for the ROVA projects beginning in 2003 were published in the December 17, 2000 EPA rule.

On May 15, 2001, the U.S. Court of Appeals for the D.C. Circuit upheld the majority of the EPA’s Section 126 rule but required certain additional justification from the EPA on factors to be used in estimating utilization in 2007. The court’s decision had the effect of suspending the EPA’s effort to impose controls on named sources. The Company expects that after the EPA submits the information that the court has requested, implementation of the Section 126 rule will resume.

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At this time, the independent power projects in which the Company owns an interest are evaluating strategies for complying with the Section 126 rule. In 2000, the ROVA project partnership installed neural networks in the boilers. The neural network increases boiler efficiency and reduces NO_x and carbon monoxide (CO) emissions. While the neural network reduces the level of NO_x and CO emissions from the ROVA I and ROVA II power plants, the ROVA project partnership is evaluating additional compliance strategies, including installation of additional pollution control equipment and emission trading. Replacement or upgrades to ROVA’s continuous emission monitoring (“CEM”) system are also being evaluated.

Dominion Terminal Associates. DTA is responsible for complying with certain state and federal environmental laws and regulations, particularly those affecting air and water quality. DTA has employees on its staff who are responsible for assuring that it is in compliance. In the event that DTA failed to comply, the Company could be responsible for a 20% share of any expense incurred prior to the date the sale of Westmoreland Terminal Company’s partnership interest is completed.

Seasonality

The demand for the power produced by the generating units that are supplied by the Company’s mines and owned by the independent power projects in which the Company holds an interest tend to be higher in the winter and summer months and lower in the spring and fall months. While all of these generating units and WELLC’s two ROVA projects are base loaded, the demand for their power may also be affected by planned and unplanned maintenance outages. A base loaded plant is used first to meet demand because of its location and lower cost of producing electricity.

Foreign and Domestic Operations and Export Sales

The Company’s assets and operations are, and for each of the last three years have been, located entirely within the United States except for the insurance activities of WRM beginning in July 2002. The Company has not made export sales during the last three years.

Available Information

The Company’s Internet address is www.westmoreland.com. The Company will make available free of charge on or through the Company’s Internet website, the Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after the Company electronically files such material with, or furnishes it to, the Securities and Exchange Commission.

ITEM 2 - PROPERTIES

As of December 31, 2002 the Company owned or leased coal properties located in Montana, Texas and North Dakota. The properties contain coal reserves and coal deposits. A “coal reserve” is that part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination. The Company includes in “coal reserves” 161,000,000 tons that are not fully permitted but that otherwise meet the definition of “coal reserves.” A description of the permitting process and the Company’s assessment of that process as applied to these 161,000,000 tons follows the table below. A “coal deposit” is a coal bearing body, which has been appropriately sampled and analyzed in trenches, outcrops, and drilling to support sufficient tonnage and grade to warrant further exploration stage work. This coal does not qualify as a “coal reserve” until, among other things, a final comprehensive evaluation based upon unit cost per ton, recoverability, and other material factors conclude legal and economic feasibility.

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The following table shows the location of the Company’s estimated coal reserves, coal deposits, production in 2002 and other mine information. All of the coal is used in steam boilers to produce electricity.

Summary of Coal Reserves, Deposits, Production
and other Mine Information
as of December 31, 2002

	Absaloka Mine	Rosebud Mine	Jewett Mine	Beulah Mine	Savage Mine
Location	Hardin, MT	Colstrip, MT	Jewett, TX	Beulah, ND	Savage, MT
Coal Reserves: (thousands of tons)
Proven(1)	59,602(2)	273,709(2)	107,321	48,997(2)	15,500(2)
Probable(3)	0	0	0	12,253	4,665
Coal Deposits(4) (thousands of tons)	587,112	234,922	0	0	0
Sulfur Percent(5)	.64	.68	1.00	1.04	.49
2002 Annual Production (thousands of tons)	5,160	10,061	7,105	3,006	337
Year Opened	1974	1924	1985	1963	1958
# of Draglines	1	4	4 plus  bucketwheel	2	1
Delivery	Rail	Truck/Rail/  Conveyer	Conveyer	Conveyer  /Rail	Truck

⁽¹⁾ Proven coal reserves are reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. In addition, all coal reserves are "assigned" coal reserves: coal that has been committed by the Company to operating mining equipment and plant facilities.

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(2)	Includes tons for each mine as described below that are not fully permitted but otherwise meet the definition of "proven" coal reserves.
(3)	Probable reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.
(4)	All coal deposits have been assigned by the Company to operating mining equipment and plant facilities.
(5)	Percent Sulfur applies to the 2002 production tons.

Absaloka Mine

WRI owns the Absaloka Mine, a surface (open-pit) coal mine located in Big Horn County, Montana and has been the only operator on the property. The mine is located in the upper Sarpy Creek drainage, 35 miles south of Hysham and 30 miles east of Hardin via Route 384. The mine is accessed from Route 384 via County Road 42. Mine facilities consisting of a truck dump, primary and secondary crushers, conveyors, coal storage barn, train loadout, rail loop and support facilities including shop, warehouse, boiler house, deep well and water treatment plant were constructed beginning in late 1972 and completed in early 1974. Power is purchased under a long-term contract with the local utility. The primary excavating machine (completed in 1979) is a Bucyrus-Erie 2570W walking dragline with a bucket capacity of 110 cubic yards and is owned by WRI. The present sustainable mine capacity using the dragline is 7.0 million tons per year; production of 5.2 million tons in 2002 was approximately 74 percent of capacity. Mobile equipment, including loaders, haul trucks, scrapers, dozers, graders, water trucks and fuel truck are owned by WRI’s mining contractor and minority owner, WGI. WRI’s total cost for the foregoing mine facilities incurred through 2002 is approximately $77,000,000. The Company anticipates spending an additional $500,000 no later than 2007 to permit an additional mining area within its present mine plan. WRI does not believe additional exploration or development of this area is necessary other than obtaining future mining permits.

The first unit train coal shipment was loaded July 1, 1974. Initially, coal was produced from the Rosebud-McKay and Robinson coal seams; attempts were also made to recover coal from two thin rider seams identified as the Stray-1 and Stray-2. The Stray-1 is in the overburden 10 to 30 feet above the Rosebud (“overburden” consists of barren or non-commercial materials which overlies the coal seam). The Stray-1 is of erratic structure and quality, and for this reason initial efforts to recover a marketable product were unsuccessful, and it has been excavated as overburden. The Stray-2 underlies the Rosebud-McKay by one to six feet. The Stray 2 is relatively high in ash and sulfur, and for several years it was blended with the primary seams. Such blending resulted in erratic quality, and it was abandoned in 1985. The Robinson coal underlies the Rosebud-McKay coal by 60 to 100 feet.

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In 1988, WRI began supplying coal to a new generating unit designed by its customers to burn coal from the Absaloka Mine, but almost immediately severe slagging problems were encountered. The problem was traced to coal from the Robinson seam. The plant owners notified WRI that they would no longer accept Robinson coal, and consequently, mining of the Robinson seam was discontinued in 1990. Hence, the only seam now being mined is the Rosebud-McKay seam, which is actually two seams separated by a thin parting ranging in thickness from a few inches to several feet. The total aggregate coal thickness in the Rosebud-McKay seam averages 32 feet. The coal is subbituminous C grade with an average heating value of 8,700 Btu/lb. and 0.64 percent sulfur as received.

All coal reserves and coal deposits shown in the previous table in the column captioned “Absaloka Mine” are leased by WRI from the Crow Tribe of Indians to exhaustion of the mineable and merchantable coal in the currently leased acreage. The Company believes that all such deposits and reserves are recoverable through existing facilities with current technology and the Company’s existing infrastructure. These reserves and deposits were estimated to be 799,803,000 tons as of January 1, 1980, based principally upon a report by Intrasearch, Inc., an independent firm of consulting geologists, prepared in February 1980. WRI is evaluating the acquisition of the rights to additional reserves or deposits contiguous to its existing leases. Estimated remaining tons are reduced annually by production in the Rosebud-McKay seam and by the amount of coal in the Robinson, Stray-1 and Stray-2 seams bypassed after mining the Rosebud-McKay seam. Through 2002, approximately 122,635,000 tons of coal have been shipped to customers, primarily in the upper Midwest for use as steam coal. Transportation is arranged and charges are paid by WRI’s customers. There have been no significant problems with operation of the coal handling plant. The only significant operating problem has been spoil stability in high overburden areas.

The mining and reclamation permit application process operates under regulations of the Office of Surface Mining (“OSM”) and the State of Montana under its OSM approved program. Among the requirements are detailed pre-mining inventories of environmental resources including soils, vegetation, wildlife, hydrology and archaeology. The application must include detailed plans for mining, reclamation and protection of hydrological resources. The process includes an exhaustive review of the application for compliance with all applicable regulations. After initial review of the application, the regulatory authority issues a letter reviewing deficiencies in the application to which the applicant responds by revising the application where appropriate. This process of identifying and responding to deficiencies is repeated until all matters are cleared. The decision document and environmental assessment are subject to formal public review, including public hearings if requested. The process typically takes two to four years from the time the initial application is filed.

A total of 3,420 acres have been disturbed by mining. Reclamation is complete on 2,576 acres, with the balance involved in active mining operations. The reclamation bond, which is posted by WRI and is an estimate by the Montana Department of Environmental Quality of total cost to reclaim, is $10,614,000. However, except for a small percentage funded by WRI, WGI is contractually responsible for reclaiming the property, whatever the cost. WGI is contractually obligated to fund a reclamation escrow account established in December 2002 or post an approved security to secure their reclamation obligation. After reclamation is complete, WRI is responsible for maintaining and monitoring the reclaimed property until the bond is released. For the property mined through December 31, 2002, WRI’s estimated future cost of maintaining and monitoring such property prior to bond release is approximately $1,500,000 to $2,000,000.

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WRI has chosen not to permit all of the coal reserves in its mine plan because it already has sufficient permitted coal to meet production, given the current rate of mining and demand, through 2008. Of the 59,602,000 tons shown as proven coal reserves in the table above for the Absaloka Mine, 32,351,000 tons are not fully permitted but otherwise meet the definition of “coal reserves”. It is anticipated that an application covering an estimated 32 million tons of unpermitted reserves will be filed in the first half of 2004. Based upon the Company’s current knowledge of the permitting process and the nature of these reserves, the Company believes that there are no matters that would hinder its ability to obtain this mining permit on a timely basis.

Rosebud Mine

WECO was acquired by WML on April 30, 2001. Rosebud Mine coal comes from the Rosebud Seam in the Montana portion of a much larger deposit commonly identified as the Powder River Basin. The Rosebud Mine is a surface (open-pit) coal mine. WECO uses four draglines in a single pass system to uncover one seam of coal. There are three 60 cubic yard capacity draglines purchased in 1975, 1976 and 1980 and one 75 cubic yard dragline purchased in 1983. The draglines use electric power purchased from Montana Power, now Northwestern Energy, under regulated default supply pricing. The machines operate primarily on the highwall side of the pit. Coal is excavated from the seam using 17 to 25 cubic yard electric shovels and diesel powered wheel loaders. Coal is loaded in 120 to 200 ton bottom dump trucks. The trucks haul the coal to one of three crushing facilities where most is loaded directly on conveyors and transported to the four Colstrip units. Both the overburden and coal are drilled and blasted prior to excavation. Other equipment used at the Rosebud Mine includes overburden and coal drills, dozers, water wagons, motor blades, front end loaders, scrapers and numerous support equipment including service trucks, pumps and cranes. The Rosebud Mine has multiple maintenance and support facilities and administration buildings. The mine work force is represented by Local 400 of the IUOE. The Burlington Northern Santa Fe Railroad transports production to those customers served by rail. The Rosebud Mine is equipped with a loop track and tipple facility capable of loading unit trains at the rate of 4,000 tons per hour.

The Rosebud Mine is located at Colstrip, Montana, 130 miles east of Billings. The Northern Pacific Railroad began mining coal for its steam locomotives at Colstrip in 1924. The railroad produced approximately 44 million tons of coal from these reserves before adapting to diesel locomotives in 1958. In 1959, Montana Power purchased the coal leases, mining machinery and Colstrip town site to produce coal for future thermal generating plants, and for sale to others. The total cost of the mine incurred through 2002 is approximately $194,000,000.

WECO was formed as a wholly owned Montana Power subsidiary in 1966 to operate the Rosebud Mine. Initial production was shipped to Montana Power’s Corette Plant at Billings, and to utilities and municipalities in the upper Midwest. Major coal supply contracts were signed with two upper Midwest utilities in the early 1970‘s and in 1980 contracts were finalized for two new 750-MW mine-mouth generating plants at Colstrip. These long-term contracts provided the foundation for a major expansion of the Rosebud Mine. The mine’s production of 11.7 million tons of coal in 1979 steadily grew to 16 million tons in 1988. The Rosebud Mine has consistently ranked among the largest single coal mines in the nation, based on annual production.

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All coal reserves and coal deposits shown in the foregoing table in the column captioned “Rosebud Mine” are in Montana and leased by WECO from the federal government, Great Northern Properties, or the State of Montana. The royalty payable under federal leases adjusts every ten years, and the leases remain in effect as long as minimum commercial quantities of coal are mined. WECO annually mines at least the minimum tonnages required to keep the leases current. Great Northern leases were renewed in 1989 for a term of 30 years, and the royalty payable under these leases adjusts every five years. The state leases remain current as long as commercial quantities are produced or as long as they are under a valid mining permit. These reserves and deposits were estimated to be 560,552,000 tons as of January 1, 1998, based principally upon a reserve study prepared for a Logical Mining Unit Application to the Bureau of Land Management. This reserve study was prepared by the Environmental and Engineering Department of WECO while it was owned by Montana Power. The coal consists exclusively of the Rosebud seam. In 1999, WECO successfully bid on an additional 29,110,000 tons of federal coal and these reserves were added. The Company believes that all held deposits and reserves are recoverable through existing facilities at the Rosebud Mine with current technology and the Company’s existing infrastructure. The coal has an average heating value of 8,500 Btu/lb. and 0.72 percent sulfur as received. Through 2002, approximately 333,078,000 tons of coal have been produced and shipped from the Rosebud Mine to the Colstrip power plants and utility customers in Billings, Montana and the upper Midwest for use as steam coal. Transportation charges are paid by WECO’s customers. There have been no significant problems with operation of the coal handling plant.

A total of 14,328 acres have been disturbed by mining of which reclamation is complete on 6,670 acres, with the balance involved in active mining operations. The reclamation bond, which is posted by WECO and is an estimate of total cost to reclaim, is $135,127,000. After reclamation is complete, WECO is responsible for maintaining and monitoring the reclaimed property until the bond is released. The Company estimates that the total cost to maintain and monitor the reclaimed property until the bond is released will approximate $5,200,000, inclusive of bonding costs.

The permit application process is subject to the regulations of the State of Montana under its OSM approved program. Among the requirements are detailed pre-mining inventories of environmental resources including soils, vegetation, wildlife, hydrology and archaeology. The application must include detailed plans for mining, reclamation and protection of hydrological resources. The process includes an exhaustive review of the application for compliance with all applicable regulations. After initial review of the application, the regulatory authority issues a letter reviewing deficiencies in the application to which the applicant responds by revising the application where appropriate. This process of identifying and responding to deficiencies is repeated until all matters are cleared. The decision document and environmental assessment are subject to formal public review, including public hearings if requested. The process typically takes two to four years from the time the initial application if filed.

WECO has chosen not to permit all of the coal reserves in its mine plan because it already has sufficient coal in its current permitted mine plan given the current rate of mining and demand for its production through 2013. Of the 273,709,000 tons shown as proven coal reserves in the table above for the Rosebud Mine, 78,337,000 tons are not fully permitted but otherwise meet the definition of “coal reserves”. Based upon the Company’s current knowledge of the permitting process and the nature of remaining reserves, the Company believes that there are no matters that would hinder its ability to obtain additional mining permits in the future.

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Jewett Mine

NWR owns and leases coal properties for the Jewett Mine, a surface (open-pit) lignite mine in East Texas, approximately half way between Dallas and Houston west of Interstate Highway 45. The properties are located in Leon, Freestone, and Limestone Counties and are accessed on Farm to Market Road 39. The surface and coal leases for the Jewett Mine are all under private ownership. Most leases are for a term of 25 to 35 years although a few extend to 50 years. The term of the primary leases expire from 2004 to 2025 but are renewable if coal production is being conducted in the required radius area. The Jewett Mine was developed pursuant to an agreement with Reliant calling for production of “the most economic 240,000,000 tons” from the project area to supply the nearby Limestone Electric Generating Station. The coal deposit was evaluated through a series of exploration programs, including physical and chemical analysis, according to predetermined criteria. As of December 31, 2002, a total of 132,679,000 tons have been produced and sold leaving 107,321,000 tons remaining under the agreement. The Company believes that all such reserves are recoverable through existing facilities and with the Company’s existing infrastructure.

Mine facilities consist of a truck dump, crusher, conveyors, coal storage, shop/warehouse complex, administrative support buildings, and water treatment facilities. The contract with TGN requires that all equipment and facilities be maintained such that they continue to be serviceable and support production comparable to the original specifications. Total capital cost to develop the mine was approximately $59,000,000 as of December 31, 2002.

The mine has been in continuous operation by NWR since 1985 and consists of four active areas with as many as four lignite seams within each area. Lignite is a dark brown to black combustible mineral formed over millions of years by the partial decomposition of plant material subject to increased pressure and temperature in an airless environment. Lignite is coal with a lower grade and Btu value. Because of its lower heat value, lignite typically can serve only power generating units that are adjacent to the mine. Overburden removal is accomplished with four draglines, a bucketwheel excavator system and/or a truck and shovel fleet. The primary excavating machines consist of three walking draglines with bucket capacities of 84 cubic yards, one walking dragline with a bucket capacity of 128 cubic yards, and one around-the-pit Bucketwheel Excavator System (“BES”). Additional mobile equipment consists of dozers, scrapers, end dump trucks, bottom dump trucks, front-end loaders, and backhoes. The aforementioned equipment is owned by TGN and is provided to NWR at no cost. NWR is obligated to maintain the equipment. Electrical power for the facilities and major stripping equipment is generated by the Brazos River Authority and transferred to the mine site by Navasota Valley Electric Cooperative.

Overburden removal is scheduled 24 hours per day, 7 days per week. Where overburden thickness total exceeds 180 feet, the BES trucks and loaders are utilized to prebench to a 180-foot level. Draglines then work to expose the lignite seams. Depending on overburden depths and seam geometry, the dragline may take as many as two highwall passes and three spoilside passes to complete a pit. Pit widths vary from 100 to 200 feet with a 140-foot pit being normal. Overburden depths vary from 20 to 240 feet. When the draglines cannot uncover sufficient lignite to meet fuel deliveries, additional prebenching below the aforementioned 180-foot level is required. This reduces the amount of dragline overburden, thus increasing lignite release. The BES system operates in a single mine area to reduce the dragline overburden to a predetermined depth. Once the lignite is exposed it is removed utilizing backhoes, front-end loaders, and 150-ton bottom dump coal haulers. The lignite seams vary in thickness from 1.5 feet to 12 feet. The coal haulers transport the lignite to the coal handling facilities where it is crushed and delivered to the power plant by means of a conveyor belt.

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The first ton of coal from the Jewett Mine was sold in July 1985. The four primary seams are named the #3, #4, #5, and #6 seams. Interburden ranging from one foot to 70 feet in thickness separates them. The total aggregate coal thickness from all four seams is approximately 15 feet. All of the coal mined from the Jewett Mine is shipped approximately one mile, via conveyor, from the crushing facility located at the mine to LEGS. The coal has an average heating value of 6,670 Btu/lb. and 1.00 percent sulfur as received.

Initially, the mine operated with the three Marion 8200 walking draglines. In 1990, due to increased overburden depth, the BES was put into operation. In 1997, due to increased depth of overburden and increased delivery demands by LEGS, a fourth dragline, the Marion 8750, was put into operation. On average, the mine has sold 7.8 million tons of coal per year for 17 years.

Exploration work for the project area was initiated in the late 1970s, and NWR engineers and geologists prepared initial reserve estimates while Montana Power owned NWR. NWR engineers and geologists initially estimated the coal deposits and reserves. To further define the coal reserve, exploration drilling was utilized to delineate that part of the deposit that met an economic depth and strip-ratio. Based on the economic depth and strip-ratio, coring was conducted on 1000-foot centers and then on 500-foot centers to develop the proven reserves. Core samples were taken on 1000-foot centers and were analyzed for physical and chemical parameters. Electronic logs were taken on 500-foot centers. Additional drilling was conducted to further define the limits of the coal seams. As of December 31, 2002, all planned exploration is complete for the life-of-mine coal reserve.

Reclamation activities follow mining. The dragline spoils are regraded to an approximate original contour and are covered with a minimum of four feet of suitable plant growth material. The area is then seeded and mulched.

To date, a total of 12,765 acres have been disturbed by mining of which the mine has regraded 11,715 acres and revegetated 8,356 acres; at any given time there are approximately 600 to 900 acres disturbed in association with the pit, prebench and unregraded spoil. The reclamation bond of $15,000,000, which is posted by NWR and by a self-bond of $50,000,000 from CenterPoint Energy Houston Electric, a subsidiary of CNP, exceeds the total estimated cost to reclaim the mine during and at the end of the life of the mine. Through June 2002, NWR performed the reclamation work and the cost was passed through to the customer. This changed in July 2002 in that NWR will perform the reclamation work on current mining including “final” pits in each area as part of its cost of mining. Final reclamation of the Jewett Mine, at the end of its useful life, is the financial responsibility of TGN and CNP.

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The surface coal mine permitting process is regulated by the Railroad Commission of Texas (“RCT”) under its OSM approved program. Some of the information required for permitting includes detailed premining inventories of environmental resources including soils, vegetation, wildlife, hydrology and archaeology. The application must include detailed plans for mining, reclamation and protection of hydrological resources. The permit preparation process takes in excess of a year. The regulatory review and approval process includes an exhaustive review of the application for compliance with all applicable regulations. After initial review of the application, the regulatory authority issues a letter reviewing deficiencies in the application to which the applicant responds by revising the application where appropriate. This process of identifying and responding to deficiencies is repeated until all matters are cleared. The decision document and environmental assessment are subject to formal public review, including public hearings if requested. The process typically takes eighteen months to two years from the time the initial application is filed with the RCT.

A permit term encompasses five years of mining. Jewett currently holds two mining permits that cover 100% of the proven coal reserves in the table above. Permit 32E is a renewal of the same general permit area that has been in place and actively mined since 1985; it encompasses 21,324 acres. The current term for 32E is July 1998 through July 2003. The permit renewal submittal was provided to the RCT in the first quarter of 2002. The renewal term will be from the date of the RCT approval (but will not affect current operations if delayed past July 2003) through July 2008. Permit 47 is a new permit area encompassing approximately 9,341 acres; it is located contiguous to Permit 32E. The current term for Permit 47 is December 2001 through December 2006.

Prior to any surface mining activity, all surface improvements are removed or relocated from the immediate area. These include buildings, utilities, oil/gas wells and pipelines, county roads, railroads, and public highways. Drainage control facilities such as sedimentation ponds and diversions are constructed during this phase of operations to control runoff from all areas to be disturbed during mining. Clearing and grubbing takes place in advance of overburden removal operations and includes stacking and burning of trees and brush. Dewatering/depressurization wells are installed a minimum of one year in advance of mining activities for the purpose of ground water control. Trucks and loaders selectively handle suitable plant growth material in advance of mining. A minimum of four feet of this suitable plant growth material is transported to the regraded areas of the spoil to reconstruct the surface area for revegetation.

Beulah Mine

DWC operates the Beulah Mine in Beulah, North Dakota. This property was purchased as of April 30, 2001 from Knife River Corporation. The mine and support facilities are located between the two mining areas and service both. Total capital cost to develop the mine was approximately $73,000,000 as of December 31, 2002. Mine facilities consist of a truck dump hopper, primary and secondary crushers, conveyors, train loadout, railroad spur, coal storage bin and coal stockpile. The coal preparation facilities will prepare the coal for transport via conveyor to the Coyote Generating station or for loading onto railroad cars for shipment to the Heskett Generating station. There is no wash plant at this mine site. The support facilities include several maintenance shops, equipment storage buildings, warehouse, employee change houses and mine office and trailers. Power for the mine is purchased from the local electric utility. The two primary excavating machines are a walking dragline with a bucket capacity of 17 cubic yards, which operates in the West Brush Creek area, and a walking dragline with a bucket capacity of 84 cubic yards, which removes overburden at East Beulah. Additional major equipment utilized at the mine include a Caterpillar 5130 track excavator and three end-dump trucks, a coal loading shovel, rubber tired loaders, haul trucks, scrapers, dozers, motor graders, water trucks, and coal drills.

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The Beulah Mine is a surface (open-pit) coal mine located in Mercer and Oliver Counties, North Dakota. The mine is approximately 2 miles south of Beulah. The mine is accessed from North Dakota Highway 49. There are currently two separate mining permits that cover the Beulah Mine. These permits are referred to as the West Brush Creek area and the East Beulah area. Acreage contained within the current permit area for West Brush Creek amounts to approximately 1,030 acres. The Company has private and state surface leases that cover the permit area. The East Beulah current permit area contains approximately 4,289 acres. All surface rights are leased from private owners, with the Company having federal, private and state coal leases which expire from 2009 to 2019. The mine has been open at the current location since 1963 and the coal from this operation supplies the fuel requirements for the adjacent Coyote Generating Station and the Heskett Generating Station in Mandan, North Dakota.

The estimated total owned and leased coal reserves at this site were approximately 61,250,000 tons at December 31, 2002. The Company believes all of these reserves are recoverable through existing facilities with current technology and existing infrastructure. Reserves were estimated to be 73,010,000 tons as of January 1, 1999, based principally upon a report prepared by Weir International Mining Consultants, an independent consulting firm. Presently, the mine produces approximately 3,000,000 tons of coal annually.

Of the lignite beds, the Beulah-Zap Seam is the most consistent in quality, lateral continuity and thickness. The Beulah-Zap seam, ranging in thickness from 10 to 12 feet, is the primary focus of mining in both reserve areas. Several other seams are contained within the stratigraphic package above and below the Beulah-Zap. Among these is the Schoolhouse seam, which lies 45-50 feet above the Beulah-Zap and is also being mined in the East Beulah area. The Schoolhouse seam averages 6 feet in thickness. A lower bench of the Beulah-Zap seam, referred to as the Beulah-Zap lower seam, or BZ-2, is also being mined in the East Beulah mine area. The BZ-2 seam ranges in thickness from 2 to 4 feet. Three individual seams are mined in the East Beulah area and only one in the West Brush Creek area, all with varying in-place quality characteristics. These coals require blending in order to assure consistent product quality. At the present time, nearly all coal blending is conducted in-pit through the scheduling of daily production from different areas and different seams. A quality control engineer is assigned the task of determining the in-place quality parameters and scheduling production accordingly. Estimated overall quality of the coal at the Beulah Mine is an average heating value of 7,000 Btu/lb and 1.00 percent sulfur as received.

Of the 5,319 permitted acres, 4,136 acres have been disturbed by mining. Reclamation has been completed on 2,692 acres, with the balance involved in active mining operations. The reclamation bond, which is posted by the Company and is an estimate of the total cost to reclaim the mine, is $10,696,000. The North Dakota Public Service Commission does not require mining operations to bond for facility removal estimated to be $400,000 or for the post-mining reclamation monitoring period. After all reclamation has been completed, the Company is responsible for maintaining and monitoring the reclaimed property until the bond is released, which is a minimum of 10 years after the final seeding has occurred. The Company estimates the cost of maintaining and monitoring the property prior to bond release will be $1,500,000.

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Of the total reserves shown, approximately 4.0 million tons in the West Brush Creek area and 5.0 million tons at East Beulah are fully permitted at this time. Based on the current estimated production rates of 500,000 and 2,500,000 tons respectively, there are roughly 8 and 2 years, respectively, remaining under the current permitted mine plans. Of the 48,997,000 tons shown as proven coal reserves in the table above for the Beulah Mine, 39,997,000 tons are not fully permitted but otherwise meet the definition of “coal reserves”. The permit application process is subject to the regulations of the OSM and the State of North Dakota under its OSM approved program which is regulated by the North Dakota Public Service Commission. Among the requirements are detailed pre-mining inventories of environmental resources including soils, vegetation, wildlife, hydrology and archaeology. The application must include detailed plans for mining, reclamation and protection of the hydrological resources. The process includes an exhaustive review of the application for compliance with all applicable regulations. After initial review of the application, the regulatory authority issues a letter outlining deficiencies in the application to which the applicant responds by revising the application where appropriate. This process of identifying and responding to deficiencies is repeated until all matters are addressed. The decision document and environmental assessment are subject to formal public review, including public hearing if requested. This process can take anywhere from one up to three years from the time the initial application is filed. Based upon the Company’s current knowledge of the permitting process and the environmental issues which were associated with the permitted reserves, the Company believes that there are no matters that would hinder its ability to obtain any mining permits in the future. The Company is preparing a permit revision for the East Beulah area that will be submitted in the first quarter of 2003 to add approximately 700 acres that will extend the tons permitted to accommodate five years’ production at current rates.

Savage Mine

Savage is the current operator of the Savage Mine in Eastern Montana. This property was also purchased in 2001 from Knife River Corporation. Mine facilities consist of a truck dump, near-pit crushing unit, conveyors, and coal stockpile; support facilities include a shop, warehouse and mine office. Total capital cost to develop the mine was approximately $7,000,000 as of December 31, 2002. There is no wash plant at this mine site. Power for the mine is purchased from the local electric utility. The primary excavating machine is a walking dragline with a bucket capacity of 12 cubic yards. Additional major equipment utilized at the mine include a 992 front-end-loader, haul trucks, scraper, dozers, motor grader, water trucks, drills and other rubber tired loaders. The Pust Seam is the only reserve area. The Pust Seam is classified as a lignite coal with an average heating value of 6,371 Btu/lb and 0.45 percent sulfur as received. It ranges in thickness from 15 to 25 feet, averaging around 20 feet and usually occurs as a single seam; however, a seam parting with a thickness of 1 to 6 feet does occur. Where present, the parting occurs in the lower part of the seam, dividing the lignite into two distinct benches.

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The Savage Mine is a surface (open-pit) coal mine located in Richland County, Montana. The mine is approximately 32 miles north of Glendive and 20 miles south of Sidney. The mine is accessed from Montana Highway 16 via County Road 107. Acreage contained within the current life-of-mine plan amounts to approximately 874 acres. All 874 permitted acres of surface leased fall under private ownership, with the Company having 563 acres of private coal leases and the remaining 311 acres are held under federal coal leases which expire from 2013 to 2017. The mine was opened in 1958 and the coal from this operation supplies the fuel requirements for the Lewis and Clark Generating Station and the Sidney Sugars, Inc. (a subsidiary of American Crystal Sugar Co.) sugar beet processing plant, both located in Sidney.

As of December 31, 2002, Savage’s estimated total coal reserves in owned or leased property were approximately 20,165,000 tons. The Company believes these reserves are recoverable through existing facilities with current technology and existing infrastructure. These reserves were estimated to be 21,486,000 tons as of January 1, 1999, based principally upon a report prepared by Weir International Mining Consultants, an independent consulting firm. Presently, the mine produces approximately 300,000 tons of coal per year.

Of the 874 permitted acres, 502 acres have been disturbed by mining. Reclamation has been completed on 209 acres, with the balance involved in active mining operations. The reclamation bond of $2,946,000 is posted by the Company and exceeds the estimate of the total cost to reclaim the mine. After all reclamation has been completed, the Company is responsible for maintaining and monitoring the reclaimed property until the bond is released, which is a minimum of 10 years after the final seeding has occurred. The cost of maintaining and monitoring the property prior to bond release has been estimated at $265,000 and is included in the reclamation bond estimate.

Of the total reserves shown in the above table in the column captioned “Savage Mine”, approximately 4.7 million tons are fully permitted at this time and 10.8 million tons are not fully permitted but otherwise meet the definition of “coal reserves”. Based on the current estimated production rate of 300,000 tons, there are roughly 15 years remaining under the current permitted mine plan. The permit application process is subject to the regulations of the OSM and the State of Montana under its OSM approved program which is regulated by the Montana Department of Environmental Quality. Among the requirements are detailed pre-mining inventories of environmental resources including soils, vegetation, wildlife, hydrology and archaeology. The application must include detailed plans for mining, reclamation and protection of the hydrological resources. The process includes an exhaustive review of the application for compliance with all applicable regulations. After initial review of the application, the regulatory authority issues a letter outlining deficiencies in the application to which the applicant responds by revising the application where appropriate. This process of identifying and responding to deficiencies is repeated until all matters are addressed. The decision document and environmental assessment are subject to formal public review, including public hearing if requested. This process can take anywhere from one to three years from the time the initial application is filed. Based upon the Company’s current knowledge of the permitting process and the environmental issues which were associated with the permitted reserves, the Company believes that there are no matters that would hinder its ability to obtain any mining permits in the future.

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Refer to Note 3 to Consolidated Financial Statements for a description of WELLC properties.

ITEM 3 - LEGAL PROCEEDINGS

Westmoreland Coal Company

1974 Plan Arbitration

The Company commenced arbitration proceedings with the UMWA 1974 (Retirement) Plan in 1998 regarding the Company’s withdrawal liability. Refer to Item 7 – Management’s Discussion and Analysis-Liquidity Outlook and Note 9 to the Consolidated Financial Statements for further information.

Purchase Price Adjustment

Pursuant to the terms of the Stock Purchase Agreement (the “Stock Purchase Agreement”) between Entech, a subsidiary of Montana Power, and WCC, certain adjustments to the purchase price were to be made as of the date the transaction closed to reflect the net assets of the acquired operations on the closing date and the net revenues that those operations had earned between January 1, 2001 and the closing date. The Stock Purchase Agreement gave the seller 60 days after the transaction closed to provide WCC a certificate setting forth the seller’s calculation of the net assets of the entities that the Company was acquiring and the net revenues of those entities through the closing date. Westmoreland then had 30 days to agree or object to the seller’s certificate. Entech submitted a certificate that would have increased the purchase price by approximately $9 million. The Company submitted its own adjustments which would result in a substantial decrease in the original purchase price and objected to Entech’s certificate. Under the Stock Purchase Agreement, the parties had 15 days from the submission of the Company’s certificate and objection to the seller’s certificate to resolve their differences. If the companies could not reach agreement within that period, the Stock Purchase Agreement requires that their disagreements be submitted to an independent accountant for resolution. The parties have not been able to agree on either the amount of the purchase price adjustment or the methodology to calculate the adjustment, and Entech refused to refer the matter to the independent accountant. Consequently, on November 26, 2001, Westmoreland initiated an action in the Supreme Court of New York seeking specific performance of the purchase price adjustment methodology in the Stock Purchase Agreement. The Supreme Court of New York agreed with Westmoreland and ordered Entech to comply with the purchase price adjustment methodology in the Stock Purchase Agreement. Entech appealed the Court’s decision and sought to enjoin the use of the independent accountant until its appeal was heard. A temporary stay was granted pending a hearing before the full Appellate Division of the Supreme Court of New York. On March 19, 2002, the Appellate Division denied Entech’s request to continue the stay pending completion of Entech’s appeal and dissolved the temporary stay. The Appellate Division sustained the Supreme Court decision on July 5, 2002. Entech appealed both the Supreme Court decision and Appellate Division ruling to the New York Court of Appeals. Argument is set for April 29, 2003. In the interim, attempts to negotiate an acceptable engagement letter allowing the independent accountant to proceed have not been successful, however discussions continue. In addition, Westmoreland has attempted to enforce the lower court rulings through a contempt proceeding; however, the trial court has declined to act pending the results of the appeal. Although there can be no assurance as to the ultimate outcome, the Company denies Entech’s claims, believes its own claims are meritorious, and intends to pursue its rights vigorously.

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Montana Power Shareholders’ Litigation

In mid-November, 2002, Westmoreland Coal Company and Westmoreland Mining LLC were served with a Fourth Amended Complaint in a case styled McGreevey et al. v. Montana Power Company et al. The Fourth Amended Complaint added Westmoreland as a defendant in a shareholder suit against Montana Power Company, various officers of Montana Power Company, the Board of Directors of Montana Power Company, financial advisors and lawyers representing Montana Power and the purchasers of some of the businesses formerly owned by Montana Power and its subsidiary, Entech, Inc. The shareholders filed their first complaint on August 16, 2001 and seek to rescind the sale by Montana Power of its generating assets, oil and gas, transmission businesses and the sale of the coal businesses by Entech or to compel the purchasers to hold these businesses in trust for the shareholders. Plaintiffs, early in the proceeding, before Westmoreland was a party to the litigation sought and were granted certification as a class. Westmoreland has filed an answer, various affirmative defenses and a counterclaim against the plaintiffs. On January 10, 2003, attorneys for one of the defendants filed a petition in the U.S. District Court of Montana removing the case to the federal court. Plaintiffs oppose the removal and prefer to litigate the case in the Montana State Court. The U.S. District Judge has not yet ruled in the removal petition. Although there can be no assurances as to the ultimate outcome, the Company believes its defenses are meritorious and will vigorously defend this litigation.

Westmoreland Energy LLC and Westmoreland Coal Company

Tax Matters

WELLC’s ROVA projects are located in Halifax County, North Carolina and are the County’s largest taxpayer. Halifax County hired Tax Management Associates, Inc. (“TMA”) to review and audit the property tax returns for the past five years. TMA retains a percentage of any additional tax they cause to be paid to the County. In May 2002, the ROVA project was advised that its returns were being scrutinized for potential underpayment due to undervaluation of property subject to tax. When ROVA was being built, the partnership met with the Halifax tax authorities and agreed how the project would be taxed. The County was reminded of the prior discussions and agreement, however, the County declined to stop the process. The project management met with County officials and TMA on September 20, 2002. In late October 2002, the project received notice of an additional assessment of $4.6 million for the years 1994 to 2002. If upheld, the project’s future taxes would increase approximately $800,000 per year. The Company owns a 50% interest in the project. The project partnership will contest the assessment and has filed a protest to the additional assessment and believes the change in assessment methodology and values after the prior agreement is unfounded.

The Montana Department of Revenue has reviewed the Company’s income tax returns for 1998 and 1999 and notified the Company in 2002 that it has disallowed the exclusion of a gain on the 1999 sale of the Rensselaer Project Partnership’s primary asset, the Power Purchase and Supply Agreement with Niagra Mohawk Power Corporation (“NIMO”). In 1997, the New York Public Service Commission in an attempt to substantially reduce the economic burden of existing contracts between NIMO and the various independent power producers approved NIMO’s plan to terminate or restructure its 29 independent power project contracts. The Company’s Rensselaer project was terminated. The Company is objecting to the assessment. If the State’s assessment is upheld, the Company would owe interest of $57,000 to the State of Montana from 1998 and fully use up its Montana net operating loss carryforwards in 2002.

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A similar inquiry on the same issue was made by the State of North Carolina. On February 11, 2003, the North Carolina Department of Revenue notified the Company that it also had disallowed the exclusion of gain on the compelled sale of the Rensselaer Project’s partnership’s Power Purchase and Supply Agreement. The Company could owe a current tax of $3.5 million plus interest of $1.0 million and penalty of $0.9 million to the State of North Carolina if the assessment is upheld. The Company has filed a protest and will commence the appeal process. The Company does not have enough information about the state’s assessment at this time to evaluate its merits and consequently has not recorded any potential impact of that assessment.

Westmoreland Resources, Inc.

MMS Claim

On July 1, 1999, WRI restructured the terms of its coal sales agreement with Xcel Energy. The agreement increased the tonnage of coal that Xcel Energy was required to purchase and that WRI was required to deliver and eliminated an option agreement that Xcel had to purchase additional tonnage. That agreement expired on December 31, 2002. WRI executed new agreements with Xcel at the end of 2002. Under the old agreement, WRI and Xcel had entered into an option agreement whereby WRI had agreed to sell up to an additional 200,000,000 tons of coal to Xcel Energy. As compensation for granting the option, WRI received 1 1/4 cents, payable quarterly (with applicable price adjustments) for each optioned ton. The option was never exercised. In 1999, WRI recorded income of $1,593,000 relative to this option agreement. On May 23, 2001, the Minerals Management Service (“MMS”) of the Department of Interior, responsible for insuring payment of royalties on minerals, including coal produced from Federal or Native American lands, issued a letter demanding payment of an additional $1,900,000 in royalty for the period from 1986 through 1999. MMS asserts that the Xcel option payments were payments for current coal and therefore royalties should have been paid on these amounts. WRI has appealed the MMS determination and believes its defenses are meritorious.

Settlement of Litigation with WGI

During 2001, WRI’s mining contractor and 20% owner, WGI, filed a petition seeking to reorganize its debts pursuant to Chapter 11 of the Bankruptcy Code. Prior to the time the bankruptcy petition was filed, WRI had filed suit against WGI in the U.S. District Court of Montana seeking to recover costs associated with the repair and replacement of components of WRI’s dragline. WGI’s bankruptcy petition stayed that litigation. WRI filed other claims in the bankruptcy court against WGI; these claims alleged, among other things, that WGI overcharged for the cost of mining, failed to provide a competitive cost of mining, and failed to provide adequate assurances that contractually required reclamation would be done. WRI also requested assurances of reimbursement from WGI for a portion of unpaid royalties claimed due by the MMS and for which WGI would be responsible as a result of its equity ownership and pursuant to certain contract obligations. WRI also objected to assumption of the mining contracts by WGI under which WGI provided contract mining and reclamation services to WRI.

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On October 4, 2002, the parties reached an agreement that settled all the pending claims and on December 10, 2002 the bankruptcy court presiding over WGI’s reorganization approved that agreement. The parties agreed to a price per ton for all coal to be mined from the currently permitted mine area which is significantly lower than the price WGI previously charged or than the price WGI had requested for future mining.

WGI will also provide a proposed mining price for all remaining currently leased but unpermitted acreage by December 31, 2003. If the parties do not agree on a price for those tons, there will be a period of negotiation, followed by non-binding mediation and then, if necessary, binding arbitration before a neutral three member panel of coal industry experts. The arbitration panel’s decision on any price dispute will be based on how a prudent contract miner would mine the Absaloka reserves, taking into consideration reasonable costs plus a reasonable profit to economically and efficiently produce and deliver the coal on a stand alone basis (based on current lease holdings) and in the alternative, in conjunction with any additional leased acreage, if available.

Claims for past overcharges were settled with WRI retaining $840,000 of previously withheld amounts and adoption of the new agreed-upon mining price beginning as of October 1, 2002. The total payment withheld by WRI had been approximately $1,120,000, including $560,000 held in an escrow account.

To settle the dispute over the dragline repair and replacement, WGI paid WRI $3.6 million and WRI waived any claim to interest. This settlement is without prejudice to either party’s position regarding the obligation to repair, maintain and replace components of the dragline.

WRI and WGI reserved the question of liability for additional royalties allegedly owed to MMS until the amount of the royalty is finally determined.

Finally, WGI agreed to establish a reclamation escrow account to secure its contractual obligations to perform reclamation. WRI will place 6.5% of each payment for mining services to WGI in the escrow until either the account is fully funded to the amount of the then current estimate of WGI’s reclamation obligation or until WGI posts an irrevocable letter of credit or comparable security acceptable to WRI. WGI’s reclamation obligation will vary over time and may increase or decrease depending on conditions at the Absaloka Mine. It is currently estimated to be $7,884,000. WGI’s failure to comply with certain financial ratios will require WGI to fully fund the reclamation escrow immediately or post an irrevocable letter of credit satisfactory to WRI. The failure to fund the reclamation escrow within 30 days gives WRI the right to withhold all payments to WGI and pay those sums into the reclamation escrow and after six months could result in termination of all mining agreements between WRI and WGI.

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Basin Resources, Inc.

UMWA Benefits

Basin was an operating company, formerly owned by Entech, a subsidiary of Montana Power Company, and had no assets. Basin had operated the Golden Eagle mine near Trinidad, Colorado and ceased operations in 1995. Basin’s workforce had been represented by the UMWA. Basin signed a Basin-specific labor contract with the UMWA in 1993 which expired on January 1, 1998. A group of former employees filed an action in the U.S. District Court for the District of Colorado on April 21, 1998 claiming they were entitled to lifetime health benefits. Basin contended that when the contract expired it was not obligated to continue to provide health benefits. In April 1999, the trial judge granted the former employees’ motion for summary judgment and ordered Basin to reinstate its former health plan and to pay covered medical costs incurred. Basin appealed the District Court’s decision to the Tenth Circuit Court of Appeals. All of the previously described events occurred prior to Westmoreland’s acquisition of the stock of Basin on April 30, 2001. An estimated obligation was accrued by the Company as of December 31, 2001 as part of its purchase price accounting. On September 18, 2002, the Tenth Circuit Court of Appeals reversed the trial court’s award of summary judgment to the former Basin employees and remanded the matter for trial. The case was argued on January 21, and on January 23, 2003 a jury decided that the UMWA work force had bargained for and Basin had agreed to provide lifetime health care benefits.

The Company is evaluating whether to appeal, based on whether the jury’s verdict was contrary to the weight of the evidence. Basin’s evidence was that the Company never agreed during negotiations of the wage agreement to provide lifetime health care benefits. The union negotiator testified during depositions that the Company had only proposed health benefits during the term of the agreement; however, at trial the union negotiator stated that the Company had proposed lifetime benefits on three separate occasions. The union negotiator was impeached with his deposition testimony; however, the jury found for the union. At this time, it is impossible to determine the likelihood of success if the case is appealed.

Landowner Claim

In a second and unrelated proceeding, a landowner alleged in 1994 that subsidence from Basin’s mining operation caused damage to his home. This was the second time this landowner alleged subsidence damage had occurred. Basin paid the landowner $48,000 in 1998 for damages to the residence in satisfaction of the first subsidence complaint. Basin contested the additional subsidence claim and the matter was tried to a Las Animas County Colorado Judge in December 2002. The Judge determined that subsidence had occurred and awarded the land owner damages of $622,000 plus attorney’s fees. The amount of the verdict represented a complete loss in value rather than the cost to repair the home. During the trial, one of the experts identified by Basin testified that the cost to repair the residence was $85,000. This sum included the repair of damages that were allegedly caused in the first subsidence litigation. Basin believes that the damages award is excessive particularly when the plaintiff’s own expert placed the cost of repair below $100,000 and that the award of damages in the first case bars the second litigation. Basin has filed post trial motions and expects to appeal the case to the Colorado Intermediate Court of Appeals.

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Western Energy Company

Montana Department of Revenue/MMS Claim

WECO has received demand letters dated September 23, 2002 and September 24, 2002 from the Montana Department of Revenue (“DOR”), as agent for the MMS, asserting underpayment of certain royalties. DOR contends that royalty payments are due on the fees WECO receives to transport coal from the contract delivery point to the customer. DOR has claimed that approximately $3.2 million is due in respect of this claim. Secondly, DOR has alleged that royalties are also due for certain “take-or-pay” payments WECO received when its customers did not require coal. DOR has alleged that approximately $1.8 million is due in respect of this claim. WECO has appealed the DOR/MMS determinations and WECO believes that MMS is wrongly asserting claims for royalties on transportation and the take-or-pay payments. The appeal process will take several years.

Northwestern Resources Co.

TGN Contract Dispute Issues

Under the terms of the ALSA, lignite prices were set on a cost plus fees basis until June 30, 2002. From July 1, 2002, through August 29, 2015 lignite prices are to be the lesser of (1) a redetermined price set to be competitive with Powder River Basin (“PRB”) coal supplies (subject to an established minimum), or (2) the price that would have otherwise been paid under the pre-July 1, 2002 cost-plus fees provisions of the ALSA. In 1999, when the ALSA was executed, LEGS consisted of two 800MW generating units. Thereafter, TGN decided to increase LEGS’s generating capacity from 800MW per unit to 890MW per unit (only one unit has been increased to 890 MW to date) and to make other modifications, such as construction of a rail unloader that would facilitate use of coal from the PRB. Disputes subsequently arose regarding post-July 2002 tonnages, pricing, the potential impacts of Texas NO_xregulations and TGN’s increase in the generating capacity of LEGS. In light of differences of opinion between the parties regarding various contract provisions, NWR filed an action seeking a declaratory judgment in Freestone County, Texas on December 11, 2001. The action asks the Court to assist in resolving the parties’ differences regarding construction of the ALSA.

In June 2002, the parties agreed to an interim price and confirmed the tonnage commitment for the period of July 1, 2002 through December 31, 2003 while discussions to resolve these disputes continued. As part of the interim agreement, the parties agreed to stay the pending litigation and permit a test burn of up to 750,000 tons of PRB coal to prove the ability of LEGS to burn approximately 7.0 million tons of lignite per year and comply with the new Texas NO_x regulations. One of the terms of the interim agreement was reconfirmation of a set tonnage commitment for the July 1 – December 31, 2002 time period with additional compensation per ton due to NWR for any shortfall in tonnage. LEGS did not take the entire tonnage commitment and NWR believes it is owed additional monies for the shortfall. TGN asserts that NWR was unable to deliver. In addition, the ALSA requires LEGS to give NWR the first right of refusal to supply lignite before LEGS procures PRB or other fuel. On two occasions, in 2002 and early 2003, LEGS procured PRB coal without giving NWR the right to supply lignite. NWR believes it is owed additional monies for the breach of its right of first refusal. TGN asserts no right applies until such fuel is used.

Under the ALSA negotiated in 1999, the parties agreed that NWR would continue to use facilities and in-place infrastructureowned by TGN (then Reliant) at no cost to NWR in order to facilitate the mining of lignite for LEGS. TGN has since requested payment of royalties to TGN for coal mined from minerals owned by TGN. NWR believes that this request is inconsistent with the agreement reached in 1999. When the parties negotiated the June 2002 interim agreement, they did not discuss continued payment of royalties. Discussions on these issues are continuing. Refer to Item 7 – Management’s Discussion and Analysis – Significant Coal Contract Issues for further information.

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There are other pending legal issues at the various Westmoreland subsidiaries which are not material or out of the ordinary course of business.

ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

This item is not applicable.

Executive Officers of the Registrant

The following table shows the executive officers of the Company, their ages as of March 1, 2003, positions held and year of election to their present offices. No family relationships exist among them. All of the officers are elected annually by the Board of Directors and serve at the pleasure of the Board of Directors.

Name	Age	Position	Held Since
(1) Christopher K. Seglem	56	Chairman of the Board,	1996
		President and	1992
		Chief Executive Officer	1993
(2) Robert J. Jaeger	54	Senior Vice President, Finance and Development	1996 2001
(3) W. Michael Lepchitz	49	Vice President, General Counsel	2000
		and Secretary	2001
(4) Thomas G. Durham	54	Vice President, Coal Operations	2000
(5) Todd A. Myers	39	Vice President, Sales and Marketing	2000

(1)

Mr. Seglem was elected President and Chief Operating Officer in June 1992, and a Director of Westmoreland in December 1992. In June 1993, he was elected Chief Executive Officer, at which time he relinquished the position of Chief Operating Officer. In June 1996, he was elected Chairman of the Board. He is a member of the bar of Pennsylvania.

(2)

Mr. Jaeger held various financial positions at Penn Virginia Corporation from 1976 and was Vice President and Chief Financial Officer when he left in March 1995. He joined Westmoreland Energy, Inc. in April 1995 as Vice President-Finance. He was elected Vice President Finance, Treasurer and Controller of Westmoreland in September 1995. He was elected Senior Vice President-Finance, Treasurer and Controller in February 1996 and relinquished the position of Controller in January 1998 and the position of Treasurer in July 2001. He became Senior Vice President, Development in October 2001.

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(3)	Mr. Lepchitz joined Westmoreland in 1991 as Assistant General Counsel. He was named General Counsel of Westmoreland Energy, Inc. (the predecessor of Westmoreland Energy, LLC) in 1995 and became President of Westmoreland Energy in 1997. In June 2000, Mr. Lepchitz was elected Vice President and General Counsel of Westmoreland Coal Company. In May 2001, he became Corporate Secretary of Westmoreland. He is a member of the bar of Virginia.
(4)	Mr. Durham joined Westmoreland as Vice President, Coal Operations in April 2000. For the four years prior to joining Westmoreland, he was a Vice President of NorWest Mine Services, Inc. which provides worldwide consulting services on surface mining and other projects. Mr. Durham has 31 years of surface mine management and operations experience with various mining companies. He became a registered professional engineer in 1976.
(5)	Mr. Myers re-joined Westmoreland in January 2000 as Vice President Sales and Marketing. He originally joined Westmoreland in 1989 as a Market Analyst and was promoted in 1991 to Manager of the Contract Administration Department. He left Westmoreland in 1994. Between 1994 and 2000, he was Senior Consultant and Manager of the Environmental Consulting Group of a nationally recognized energy consulting firm, specializing in coal markets, independent power development, and environmental regulation.

PART II

ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
                 STOCKHOLDER MATTERS

Market Information:

The following table shows the range of sales prices for the Company’s common stock, par value $2.50 per share (the “Common Stock”), and depositary shares, each representing one quarter of a share of the Company’s Series A Convertible Exchangeable Preferred Stock, $1.00 par value per preferred share (the “Depositary Shares”) for the past two years.

The Common Stock and Depositary Shares are listed for trading on the American Stock Exchange (“AMEX”) and the sales prices below were reported by the AMEX.

	Sales Prices
	Common Stock		Depositary Shares
	High	Low	High	Low
2001
First Quarter	$ 16.50	$  8.25	$ 33.00	$ 20.50
Second Quarter	20.85	13.35	38.50	29.00
Third Quarter	17.75	10.80	34.85	28.00
Fourth Quarter	17.05	12.61	34.99	29.00
2002
First Quarter	15.49	10.80	34.00	28.06
Second Quarter	16.44	12.25	36.99	32.50
Third Quarter	13.55	8.30	35.50	28.00
Fourth Quarter	12.85	10.00	34.00	31.00

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Approximate Number of Equity Security Holders of Record:

	Number of Holders of Record
Title of Class	(as of March 1, 2003)
Common Stock ($2.50 par value)	1,539
Depositary Shares, each representing
one-quarter share of a share of Series A
Convertible Exchangeable Preferred
Stock	25

Dividends:

The depositary shares were issued on July 19, 1992. Each depositary share represents one-quarter of a share of the Company’s Series A Convertible Exchangeable Preferred Stock. Dividends at a rate of 8.5% per annum were paid quarterly but were last suspended in the third quarter of 1995 pursuant to the requirements of Delaware law, described below, as a result of net losses, the violation of certain bank covenants, and a subsequent shareholders’ deficit. The Company commenced payment of partial dividends to preferred shareholders on October 1, 2002 as described below. The quarterly dividends which are accumulated but unpaid through and including January 1, 2003 amount to $14,256,000 in the aggregate ($68.93 per preferred share or $17.23 per depositary share). Common stock dividends may not be declared until the preferred stock dividends that are accumulated but unpaid are made current.

There are statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which the Company is incorporated. Under Delaware law, the Company is permitted to pay preferred stock dividends only: (1) out of surplus, surplus being the amount of shareholders’ equity in excess of the par value of the Company’s two classes of stock; or (2) in the event there is no surplus, out of net profits for the fiscal year in which a preferred stock dividend is declared (and/or out of net profits from the preceding fiscal year), but only to the extent that shareholders’ equity exceeds the par value of the preferred stock (which par value was $207,000 at December 31, 2002). The Company had shareholders’ equity at December 31, 2002 of $18,568,000 and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $19,485,000 at December 31, 2002.

The Board of Directors regularly reviews the subjects of current preferred stock dividends and the accumulated unpaid preferred stock dividends, and is committed to meeting its obligations to the preferred shareholders in a manner consistent with the best interests of all shareholders. On August 9, 2002 the Board of Directors declared a dividend of $0.15 per depositary share which was paid on October 1, 2002 to holders of record as of September 17, 2002. On November 8, 2002, the Board of Directors declared a dividend of $0.15 per depositary share which was paid on January 1, 2003 to holders of record as of December 9, 2002. On February 7, 2003, the Board of Directors declared a third dividend of $0.15 per depositary share payable on April 1, 2003 to holders of record as of March 7, 2003.

34

On August 9, 2002 Westmoreland’s Board of Directors authorized the repurchase of up to 10% of the outstanding depositary shares on the open market or in privately negotiated transactions with institutional and accredited investors between then and the end of 2004. The timing and amount of depositary shares repurchased will be determined by the Company’s management based on its evaluation of the Company’s capital resources, the price of the depositary shares offered to the Company and other factors. The program will expire at the end of 2004. Any acquired shares will be converted into shares of Series A Convertible Exchangeable Preferred Stock and retired. The repurchase program will be funded from working capital which may be currently available, or become available to the Company. The repurchase program can provide an outlet for some shareholders who may wish to liquidate a part or all of their holdings but are unable to do so because of “thinness” in the market. During 2002, 7,500 depositary shares were repurchased by the Company at a total cost of $244,000.

Resumption of a dividend payment and the repurchase plan reflect the reestablishment of profitability as a result of the Company’s successful initial implementation of its strategic plan for growth and the Company’s continuing commitment to preferred shareholders.

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ITEM 6 - SELECTED FINANCIAL DATA

Westmoreland Coal Company and Subsidiaries
Five-Year Review

		2002		2001(1)		2000		1999		1998(2)
	(in thousands, expect per share data)
Consolidated Statement of
Operations Information
Revenue – Coal	$	301,235	$	231,048	$	35,137	$	38,539	$	44,010
– Independent power and other		14,506		15,871		32,260		34,492		64,465
Total revenues		315,741		246,919		67,397		73,031		108,475
Cost and expenses		297,415		233,313		60,564		63,456		78,361
Unusual charges		-		-		-		-		2,000
Doubtful accounts recoveries		(516)		(446)		(400)		(174)		(1,028)
Impairment charges		-		-		4,632		-		-
Losses (gains) on the sales of assets		9		440		6		(433)		(475)
Operating income		18,833		13,612		2,595		10,182		29,617
Interest expense		(10,821)		(8,418)		(911)		(1,135)		(190)
Minority interest		(800)		(780)		(518)		(854)		(775)
Interest and other income		4,128		3,229		867		1,826		1,999
Income (loss) before reorganization
items and income taxes		11,340		7,643		2,033		10,019		30,651
Reorganization legal and consulting    fees		-		-		-		-		(9,872)
Reorganization interest income
(expense), net		-		-		-		-		(1,594)
Income tax benefit (expense)		2,368		(1,228)		(428)		82		(3,787)
Income from continuing operations		13,708		6,415		1,605		10,101		15,398
Loss from discontinued operations		(3,583)		(1,188)		(1,297)		(1,464)		(12,070)
Cumulative effect of changes in
accounting principles		-		-		-		-		(9,876)
Net income (loss)		10,125		5,227		308		8,637		(6,548)
Less preferred stock dividend
requirements		1,772		1,776		1,776		2,992		4,888
Net income (loss) applicable to
common shareholders	$	8,353	$	3,451	$	(1,468)	$	5,645	$	(11,436)
Net income (loss) per share applicable
to common shareholders:
Basic	$	1.10	$	0.48	$	(0.21)	$	0.80	$	(1.64)
Diluted	$	1.03	$	0.43	$	(0.21)	$	0.79	$	(1.64)
Weighted average number of common
shares outstanding:
Basic		7,608		7,239		7,070		7,040		6,965
Diluted		8,147		8,000		7,070		7,146		6,965
Balance Sheet Information
Working capital (deficit)	$	(1,626)	$	11,346	$	(1,557)	$	8,886	$	15,054
Net property, plant and equipment		189,532		197,271		34,693		36,558		36,950
Total assets		451,064		466,532		139,096		142,297		215,606
Total debt		100,157		122,910		-		1,563		1,762
Shareholders’ equity		18,568		10,415		3,373		3,057		21,845

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(1)

Effective April 30, 2001, the Company acquired the operating coal business of Montana Power and the coal assets of Knife River Corporation. Refer to Note 2 to the Consolidated Financial Statements for further information.

(2)

On December 23, 1996 Westmoreland Coal Company and four subsidiaries, Westmoreland Resources, Inc., Westmoreland Coal Sales Company, Westmoreland Energy, Inc., and Westmoreland Terminal Company (the "Debtor Corporations"), filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Colorado. The Debtor Corporations were in possession of their respective properties and assets and operated as debtors in possession pursuant to provisions of the Bankruptcy Code. The cases were dismissed on December 23, 1998.

ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
                 AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition
Years Ended December 31, 2002, 2001 and 2000

Forward-Looking Disclaimer

Certain statements in this report which are not historical facts or information are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including, but not limited to, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations. Any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. For example, words such as “may,” “will,” “should,” “estimates,” “predicts,” “potential,” “continue,” “strategy,” “believes,” “anticipates,” “plans,” “expects,” “intends,” and similar expressions are intended to identify forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties and other factors, which may cause the actual results, levels of activity, performance or achievements of the Company, or industry results, to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others, the following: general economic and business conditions; healthcare cost trends; the cost and capacity of the surety bond market; the Company’s ability to manage growth and significantly expanded operations; the ability of the Company to implement its business strategy; the Company’s ability to pay the preferred stock dividends that are accumulated but unpaid; the Company’s ability to retain key senior management; the Company’s access to financing; the Company’s ability to maintain compliance with debt covenant requirements; the Company’s ability to successfully identify new business opportunities; the Company’s ability to achieve anticipated cost savings and profitability targets; the Company’s ability to negotiate profitable coal contracts, price reopeners and extensions; the Company’s ability to maintain satisfactory labor relations; changes in the industry; competition; the Company’s ability to utilize its tax net operating losses; the ability to reinvest excess cash at an acceptable rate of return; weather conditions; the availability of transportation; price of alternative fuels; costs of coal produced by other countries; demand for electricity; the effect of regulatory and legal proceedings; the claims between the Company and Montana Power; and the other factors discussed in Items 1 and 3 above and in this Item 7. As a result of the foregoing and other factors, no assurance can be given as to the future results and achievement of the Company’s goals. The Company disclaims any duty to update these statements, even if subsequent events cause its views to change.

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Critical Accounting Policies

The discussion and analysis of the Company’s financial condition and results of operations are based upon the Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Areas where significant judgments are made include, but are not limited to, the critical accounting policies discussed below. Actual results could differ materially from these estimates. The Company’s senior management has discussed the development, selection and disclosure of the accounting estimates in the critical accounting policies with the audit committee of the Board of Directors.The most significant principles that impact the Company and its subsidiaries relate to post-retirement benefits and pension obligations, reclamation costs and reserve estimates, depletion of mineral rights and development costs included in property, plant and equipment and deferred income taxes. The following discussion highlights those impacts.

The most significant long-term obligations of the Company are post-retirement medical and life insurance benefits and pneumoconiosis (black lung) benefits. The majority of these benefits are provided through self-funded programs. The Company describes these obligations for retired workers as heritage health benefit costs and the estimated amount of future payments for such obligations are determined actuarially and are included in the corporate segment. The estimated cost to provide post-retirement medical and life insurance benefits to employees at active mining operations are included in the coal segment.The discount rate used to calculate the present value of these future benefits was reduced from 7.25% in 2001 to 6.75% in 2002 and will be adjusted annually based upon interest rate fluctuations. The discount rate used can vary from company to company. In addition, the estimated amount of future claims is affected by the assumed health care cost trend rate. During 2001, the Company increased the initial cost trend rate assumption to 10.0% from 5.5% decreasing to an ultimate trend of 5.0% in 2009 and beyond. These factors, among others, greatly affect the annual expense which totaled $26.9 million in 2002 compared to $23.8 million in 2001 and the accrued liability of $117.1 million at December 31, 2002 for post-retirement medical and life insurance costs. The excess of trust assets over the pneumoconiosis benefit obligation increased to $7.7 million as of December 31, 2002 from $7.0 million as of December 31, 2001 as a result of increased bond values due to lower interest rates and despite an increase to the actuarially determined obligation.

The Company’s share of reclamation costs, along with other costs related to mine closure, are accrued and charged against income in the coal business segment on a units-of-production basis over the life of each mine, except at WRI where the Company’s obligation is limited and monitoring costs are being expensed over a 15-year period. Future costs of reclamation are estimated based upon the standards for mine reclamation that have been established by various regulatory agencies that regulate the Company’s mining operations. Estimated costs can change and the liability included in the financial statements of $139 million as of December 31, 2002 must be viewed as an estimate which is subject to revision. The remaining coal reserves used to calculate annual reclamation expense are also engineering estimates and are subject to change.

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In the coal business segment the Company amortizes its mineral acquisition, development costs and some plant and equipment using the units-of-production method based upon estimated recoverable proven and probable reserves. These estimates are reviewed on a regular basis and are adjusted to reflect current mining plans. As a result, changes in estimates of recoverable proven and probable reserves could change amounts recorded in the future for depletion of development costs.

The Company accounts for deferred income taxes using the asset and liability method. One of the largest potential assets of the Company is the Federal net operating loss carryforwards (or NOLs) which were approximately $174 million as of December 31, 2002. The Company’s ability to utilize these NOLs, which are available to the Company to reduce future income taxes until the NOLs expire at various dates through 2019, is dependent upon many factors which determine taxable income. These factors include the timing of tax deductions for certain obligations, such as post-retirement medical benefits and reclamation; percentage depletion of coal production; and any potential limitation on using losses due to a “change of ownership” in the Company. The Company estimates future utilization of the tax losses and its impact on the recognition of deferred tax assets each period. In connection with the 2001 acquisitions, the Company recognized a $55.6 million deferred income tax asset to recognize that portion of the previously unrecognized net operating loss carryforwards that would be utilized through the generation of future taxable income. A valuation allowance of $31,270,000 was concurrently created to cover those NOLs not yet assumed to be utilized. Any increases or decreases to the estimated future utilization of the NOLs will impact the valuation allowance and affect deferred income tax expense. An increase in the estimated utilization of NOLs will decrease deferred income tax expense; a decrease in the estimated utilization of NOLs will increase deferred income tax expense. These changes can materially affect net earnings resulting in an effective book income tax rate different than the 34% Federal statutory rate. For example, the agreement to sell DTA in 2003 is expected to result in a gain and eliminate future operating losses from those operations. Both benefits of the sale significantly increased the expected utilization of NOLs and reduced the valuation allowance which, in turn, increased the tax benefit and net earnings recognized for the year ended December 31, 2002. The valuation allowance was $31,270,000 as of December 31, 2001 and increased overall to $32,574,000 as of December 31, 2002 after the benefit of DTA and changes in other deferred tax assets and liabilities. This allowance includes the loss carryforwards accumulating in North Dakota that are not expected to be utilized. Therefore, the valuation allowance is increased by the amount of North Dakota NOLs resulting in no net impact to deferred tax assets or income tax expense.

39

Contractual Obligations and Commitments

The following table presents contractual obligations (or estimates) and commitments of theCompany as of December 31, 2002, which are discussed elsewhere in this filing.

	Payments Due by Period (in thousands of dollars)
Contractual Obligations and Commitments	Total	2003	2004	2005	2006	After
WML Revolving debt	1,500		1,500
WML Term debt	96,300	7,800	10,300	10,300	11,300	56,600
WCC Revolving debt	500			500
Other debt	1,857	1,053	169	169	169	298
Operating leases	2,637	1,118	899	620
Heritage Health Benefit/ Pension:
Undiscounted obligations:
Workers’ compensation	10,740	2,335	2,200	2,000	1,800	2,405
1974 UMWA pension	8,035(1)	1,473	1,575	1,692	1,818	1,477
Discounted obligations:
Combined Benefit Fund      (Multiemployer)	38,823(2)	4,786	4,686	4,424	4,167	20,760
Post-retirement medical	223,478(3)	12,787	15,948	16,674	17,325	160,744
Qualified pension benefits	41,366(4)	200	250	300	350	40,266
SERP benefits	2,626(5)	76	76	76	76	2,322
Pneumoconiosis	22,784(6)	4,100	3,700	3,400	3,100	8,484
Reclamation costs	233,675(7)	11,381	11,500	11,500	11,500	187,794
Preferred dividends	14,256(8)	1,760(9)	1,760(9)	1,760(9)	1,760(9)	1,760(9) per year

40

(1)	The 1974 UMWA pension obligation is being contested by the Company as discussed below in Liquidity Outlook.
(2)	The present value of the estimated obligation is not accrued as a liability since it is a multiemployer plan. Premium payments are expensed when due.
(3)	Gross benefit obligation is shown in the table. The accrued liability, net of the unrecognized net actuarial loss and the unrecognized net transition obligation, was $116,802,000 as of December 31, 2002.
(4)	Fair value of plan assets at December 31, 2002 was $30,147,000. Future payments will be made from plan assets.
(5)	Gross benefit obligation is shown in the table. The accrued liability, net of the unrecognized net actuarial gain and an unrecognized prior service cost, was $2,020,000 as of December 31, 2002. The plan was unfunded at December 31, 2002.
(6)	Fair value of plan assets at December 31, 2002 totaled $30,449,000. Future payments will be made from plan assets.
(7)	Gross estimated cost of final reclamation is shown in table. The accrued liability of $138,898,000 as of December 31, 2002 will increase as acres are disturbed in mining operations and as mine closures draw nearer. The accrued liability does not reflect contractual obligations of customers and a contract miner to perform reclamation currently estimated at $71,465,000. An escrowed investments totaling $49,484,000 as of December 31, 2002 from contributions by customers for reclamation of WECO’s Rosebud Mine.
(8)	Represents quarterly dividends which are accumulated but unpaid through and including January 1, 2003.
(9)	As provided in the Certificate of Designation establishing the Series A Preferred Stock, the holders of the Series A Preferred Stock are entitled to receive dividends “when, as and if declared by the Board of Directors out of funds of the Corporation legally available therefore.” In general, dividends that are not paid cumulate, as provided in the Certificate of Designation.

Significant Coal Contract Issues

Westmoreland acquired several existing coal supply agreements when it purchased the coal businesses of Montana Power. WECO supplies coal to the four Colstrip Units under two distinct contracts. The contract for Units 1 and 2 called for the price to be reopened on the contract’s thirtieth anniversary, which was July 2001, and gave the parties six months to negotiate a new delivered price for coal. If the parties are unable to agree on a new price, the issue is submitted to binding arbitration. WECO and the owners of Units 1 and 2 have been negotiating since July 2001 in an attempt to reach an agreement for the price of coal through contract expiration in 2009. The deadline provided in the contract for arbitration was extended through June 2002 in connection with the ongoing efforts to agree on a new price. After more than a year had passed, WECO sent the Units 1 and 2 owners an arbitration demand on September 3, 2002. Proceedings are anticipated to take place during the summer of 2003. While WECO believes it is due a price increase, as with any arbitration, the outcome is uncertain.

On August 2, 1999, NWR, as part of a settlement of then pending litigation, entered into an Amended Lignite Supply Agreement with Reliant (now CNP), for its Limestone Electric Generating Station. CNP has notified NWR that it has assigned the ALSA to TGN, a subsidiary. The ALSA provided for a transition from the cost plus fees pricing mechanism of the original lignite supply agreement to a market-based pricing mechanism under the ALSA effective July 1, 2002. The market-based pricing mechanism is an annual determination of the equivalent cost of purchasing, delivering, and consuming Powder River Basin (“PRB”) coal from Wyoming at LEGS, subject to a minimum and a maximum price set forth under the ALSA. The ALSA provides that the price be redetermined annually and that annual volumes be committed eighteen months prior to the start of each calendar year’s shipments. If TGN proposes to purchase PRB coal above the amount committed to, NWR has the right of first refusal to meet the equivalent PRB price and supply lignite instead. In no event may TGN procure PRB coal for LEGS, either in addition to or in place of the committed volumes, unless NWR declines to match the equivalent price of PRB coal and deliver lignite.

41

In accordance with the ALSA, the parties agreed in June 2000 to lignite volumes for the period July 2002 through December 2003. The ALSA also called for the PRB equivalent price for 2002 (July through December) and the 2004 annual commitment volume to have been determined by the end of June 2002. However, TGN asserted that certain cost effects associated with the uprating of at least one of its two LEGS generating units and with its strategy to comply with new Texas nitrogen oxide (“NO_x”) emission regulations (which take effect May 1, 2003) should be included in the calculation of the PRB equivalent price. When the parties were unable to agree on the pricing mechanism, NWR filed for a declaratory judgment in Limestone County, Texas, against TGN (then Reliant) in December 2001. NWR claimed that the uprating and NO_x compliance costs should not be included in or otherwise affect the calculation of the PRB equivalent price. NWR also claimed that it is necessary to resolve NWR and TGN’s competing claims before the PRB equivalent price could be calculated.

Subsequently, NWR and TGN (then Reliant) agreed to stay this litigation and resolved these issues for 2002 and 2003 by entering into an interim agreement on June 18, 2002 that (1) set firm pricing and volumes from July 1, 2002 through December 31, 2003; (2) provided TGN flexibility to test blends of SPRB coal for NO_x compliance in 2002; (3) obligated TGN to make best efforts to achieve a lignite-to-SPRB blend that achieves NO_x compliance using a minimum of 7 million tons per year of lignite; (4) obligated TGN to share its test results and allowed NWR to observe the tests; (5) postponed the commitment of lignite volumes for 2004 until early in 2003; (6) stayed all related litigation until February 28, 2003 (the parties have since extended this date to March 31, 2003); and (7) required the parties to make good faith efforts to select a standing arbitrator as required under the ALSA. Refer to Item 3 – Legal Proceedings for further information.

In the course of testing blends of PRB coal for NO_x compliance during the second half of 2002, TGN failed to take delivery of the full lignite volumes agreed upon in the June 18, 2002 letter agreement. NWR has subsequently informed TGN that it expects to be compensated as provided under the June 18, 2002 interim agreement for shortfall volumes. TGN claims NWR was unable to deliver these amounts. In addition, TGN has procured certain amounts of PRB coal above the agreed upon volume of 750,000 tons without first offering a right of first refusal to NWR. NWR has informed TGN that it would be entitled to damages for this breach. NWR has asserted that it is not in breach until it uses any such coal. Finally, TGN believes and has requested that NWR should pay royalties on lignite produced since July 1, 2002 from NWR mineral leases with TGN. NWR disputes its obligation to pay these royalties.

42

NWR and TGN have been meeting in an attempt to settle all of the issues above and to agree upon prices and volumes for 2004 and 2005 or longer. As with any dispute, the outcome is uncertain; however, the Company believes that the ultimate resolution of this dispute will not have a material adverse effect on its financial condition or results of operations.

In addition to the contract issues discussed above, the Company is involved with various other legal proceedings, described in Item 3 – Legal Proceedings, which may affect the Company’s liquidity.

Other Risks

Westmoreland’s businesses use large equipment, including mining and power generation equipment and conveyor systems used for the transportation of coal. While every effort is made to maintain this equipment, there is always a risk that unexpected equipment breakdowns can interrupt either the production of coal or generation of electricity. For example, in the fall of 2002 the dragline at the Beulah Mine was damaged and was out of operation for six weeks while being repaired at a cost of approximately $900,000 not covered by insurance.

Unexpected equipment failure at electric generating units, called forced outages, if significant, may adversely impact Westmoreland. These forced outages could cause fluctuations in delivery of coal or in distributions from Westmoreland’s independent power plants. For example, the Colstrip Unit 3 was shut down several times in 2002 for unexpected repairs which significantly reduced coal sales from the Rosebud Mine.

Westmoreland’s business is subject to some seasonality. Weather has the potential to impact Westmoreland’s business. The Company supplies coal to electric generation units and if winter is unseasonably warm or summer is unseasonably cool, the customer’s need for coal may be less than expected. The mild winter of 2001/2002 decreased the demand for electrical generation and lowered the Company’s coal sales during early 2002.

WGI is contractually obligated to perform mining and reclamation at the Absaloka Mine. WGI emerged from bankruptcy in 2002 and reached agreement with WRI regarding several claims as discussed elsewhere in this report. If WGI is unable to perform its mining contract or complete its reclamation obligation, WRI would be prepared to operate the mine and supply coal to its customers, and would have a claim against WGI.

Changes in various mining, coal-fired generating plant and other environmental regulations have the potential to impact the Company. These include President Bush’s Clean Skies Initiative and Global Climate Initiative, the Kyoto Protocols, and the Texas NO_xregulations.

The Company is dependent on a limited number of contracts and customers. The Company derives substantially all of its revenues from a relatively small number of coal supply contracts and from two independent power projects.

The Company may have difficulty managing existing and future growth. The Company rapidly and significantly expanded its operations during 2001, and will pursue further opportunities to expand and diversify its revenue base. These expansions may place a significant strain on the Company’s management, operations, and financial resources and may require additions to the Company’s current personnel, systems, procedures, and controls.

43

The loss of key senior management personnel could negatively affect the Company’s business. The Company depends on the continued services and performance of senior management and other key personnel, particularly Christopher K. Seglem, Chairman of the Board, President and Chief Executive Officer. The Company does not have “key person” life insurance policies. The unexpected loss of any of the Company’s executive officers or other key employees could harm its business.

Liquidity and Capital Resources

Cash provided by operating activities was $29,987,000 in 2002, $28,435,000 in 2001 and $2,160,000 in 2000. Cash from operations in 2002 compared to 2001 benefited from an additional four months of operations from the acquisitions completed in the second quarter of 2001 which contributed $46,839,000 and $34,799,000 to operating cash flow during the years ended December 31, 2002 and 2001, respectively. Cash provided by operating activities in 2001 also included $8,949,000 from the Company’s three Virginia independent power projects which were sold on March 23, 2001. Other components of cash flow from operating activities, such as impairment charges, deferred income tax benefit, depreciation, depletion and amortization are discussed in the results of operations. The net change in assets and liabilities was $12,559,000 in 2002 compared to $9,338,000 in 2001. The most significant components are accounts receivable and accounts payable. Accounts receivable and accounts payable can vary widely at the end of any reporting period. The Company has a few large customers and therefore the timing of receipt of accounts receivables can have a significant effect on cash from operations. Likewise, the Company has large payments of accounts payable due to a few vendors or suppliers. The actual timing of these payments can have a significant impact on cash from operations from period to period. Accounts receivable contributed cash of $15,273,000 in 2002 due to better collection of outstanding amounts owed by customers. The large increase in accounts payable in 2001 is due to normal activity at the acquired mines and contributed $13,049,000 to cash flow. Also, cash from operations benefited in 2002 by approximately $1.1 million from a favorable judgment in the Ft. Drum dispute with the U.S. Army. Cash flows in 2000 were positively impacted by the settlement of the ROVA forced outage litigation. Working capital was a deficit of $1,626,000 at December 31, 2002 compared to a positive $11,346,000 as of December 31, 2001 primarily due to the timing of collection of accounts receivable and increased reclamation activities expected during 2003.

Cash used in investing activities was $1,224,000 in 2002, $151,325,000 in 2001 and $4,434,000 in 2000. In 2002, additions to property and equipment using cash totaled $7,323,000 and proceeds of $476,000 from sales of used equipment provided cash. Also, during 2002, WML deposited $4,283,000 into required restricted cash accounts for debt service and security deposits and earned interest income of approximately $10,000. The $6,000,000 refund of collateral under the UMWA Master Agreement which was received during the second quarter of 2002 provided cash and reduced restricted cash. The primary use of cash in 2001 was $162,700,000 paid for acquisitions and payments of $8,340,000 into restricted cash accounts for debt service. Cash used in investing activities also included the recoupment of collateral required for long-term security deposits and bond obligations of $9,368,000 in 2001 associated with a change in bonding agents. In addition to the acquisitions, additions to the Company’s property, plant and equipment totaled $5,433,000 in 2001 and consisted principally of mine development costs at WECO. Cash provided by investing activities in 2001 included $15,954,000 in proceeds from the sale of the Company’s interests in the three Virginia independent power projects. Cash used in investing activities in 2000 included funding of collateral for security deposits of $4,321,000 and fixed asset additions of $647,000 (including $621,000 at WRI) offset by a partial reimbursement from WRI’s mine operator of $530,000.

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Cash used in financing activities was $24,151,000 for 2002. Cash used in financing activities in 2002 represented repayment of WML’s long-term bank debt of $12,700,000, the net repayment of revolving debt of $9,000,000, repayment of $1,053,000 of other term debt, repurchases of preferred shares totaling $244,000, and dividends paid to WRI’s minority shareholder of $1,240,000. Cash in the amount of $334,000 was provided by the exercise of stock options in 2002. As of December 31, 2002, the Company’s revolving line of credit has $0.5 million outstanding of the $10 million total available under the facility. Cash provided by financing activities for 2001 totaled $113,930,000. Cash provided in 2001 represented proceeds from the issuance of long-term and revolving debt, net of $5,396,000 debt issuance costs, and cash of $1,479,000 from the exercise of stock options less $12,053,000 for repayment of long-term debt and $1,100,000 of dividends paid to WRI’s minority shareholder. Cash used in financing activities in 2000 totaled $3,655,000 and was primarily for repayment of WRI’s long-term debt as well as the payments of dividends to minority shareholders of WRI.

Consolidated cash and cash equivalents at December 31, 2002 totaled $9,845,000 (including $5,113,000 at WML and $4,679,000 at WRI). At December 31, 2001, cash and cash equivalents totaled $5,233,000 (including $624,000 at WML and $3,449,000 at WRI.) The cash at WML is available to the Company through quarterly distributions as described below in the Liquidity Outlook section. The cash at WRI, an 80%-owned subsidiary, is available to the Company through dividends. In addition, the Company had restricted cash and bond collateral, which were not classified as cash or cash equivalents, of $17,287,000 at December 31, 2002 and $18,423,000 at December 31, 2001. The restricted cash at December 31, 2002 included $12,883,000 in the WML debt service reserve accounts described above. The Company’s workers’ compensation and post-retirement medical cost obligation bonds were collateralized by interest-bearing cash deposits of $5,540,000, which amount was classified as a non-current asset. In addition, the Company has reclamation deposits of $49,484,000, which were funded by certain customers to be used for payment of reclamation activities at the Rosebud Mine. The Company also has $5,000,000 in interest-bearing debt reserve accounts for certain of the Company’s independent power projects. This cash is restricted as to its use and is classified as part of the investment in independent power projects. The restricted cash at December 31, 2001 included $8,371,000 in the WML debt service accounts and $6,000,000 deposited to collateralize the Company’s obligations required by the Master Agreement dated as of January 4, 1999 (the “Master Agreement”) among WCC, WRI, WELLC, Westmoreland Terminal Company, and Westmoreland Coal Sales Company, the UMWA 1992 Benefit Plan and its Trustees, the UMWA Combined Benefit Fund and its Trustees, the UMWA 1974 Pension Trust and its Trustees, the UMWA, and the Official Committee of Equity Security Holders, which facilitated the dismissal of WCC’s bankruptcy case. In 2001, the Company’s workers’ compensation bond was collateralized by interest-bearing cash deposits of $4,052,000. In addition, the Company’s reclamation deposits totaled $47,924,000. The Company also had $4,600,000 in interest-bearing debt reserve accounts for certain of the Company’s independent power projects.

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Liquidity Outlook

The major factors impacting the Company’s liquidity outlook are its significant heritage health benefit costs, its acquisition debt repayment obligations, and its ongoing business requirements. The Company’s principal sources of cash flow are dividends from WRI, distributions from independent power projects and distributions from WML subject to its debt agreement provisions. The demand for electricity will affect coal demand and pricing and therefore will impact the Company’s production and cash flow.

A detailed discussion of health benefit and retirement obligations is provided below. The Company’s heritage health benefit costs consist primarily of payments for post-retirement medical and workers’ compensation benefits. The Company also is obligated for employee pension and pneumoconiosis benefits. The pension plans have a deficit in funding as of the end of 2002 and the pneumoconiosis obligation has a funding surplus at present. It is important to note that retiree health benefit costs are affected by nationwide increases in medical service and prescription drug costs. As a result of the acquisitions completed in 2001, the Company assumed additional obligations, as of April 30, 2001, for post-retirement medical and life insurance benefits of approximately $12,745,000, which will negatively impact the estimated annual expenditures for benefits. Due to the impact of increasing healthcare cost trends on the actuarial valuations of future obligations the Company’s total estimated liability has increased and the heritage health benefit expense for 2003 may continue to increase. The estimated liability for post-retirement medical costs increased approximately $5.7 million between December 31, 2001 and December 31, 2002 due to an increase in the actuarially determined expense recognized. Actuarial valuations of the Company’s future obligations indicate that the Company’s retiree health benefit costs will continue to increase in the near term and then decline to zero over the next approximately thirty-five years as the number of eligible beneficiaries declines. The Company incurred cash costs of $20,500,000 for heritage health benefit costs in 2002 and expects to incur $21,000,000 for these costs in 2003. The Company incurred cash costs of approximately $2,750,000 for workers’ compensation benefits in 2002, The Company expects to incur cash costs of less than $2,500,000 for workers’ compensation benefits in 2003 and expects that amount to steadily decline to zero over the next approximately eighteen years. There were no workers’ compensation obligations assumed in conjunction with the 2001 acquisitions as all the acquired operations are fully insured for any potential obligation.

One element of heritage health benefit costs is UMWA pensions under the 1974 (Retirement) Plan. Since this plan is a multiemployer plan under ERISA, a contributing company is liable for its share of unfunded vested liabilities upon termination or withdrawal from the Plan. The Company believes the Plan was fully funded in 1998 when the Company terminated its last UMWA employees who were participants in the 1974 Retirement Plan and withdrew from the Plan. However, the Plan claims that the Company withdrew on a date earlier than the date on which the Company terminated its last UMWA employee and that when the Company withdrew the Plan was not fully funded. The Plan has asserted a claim of $13,800,000, which the Company is vigorously contesting through arbitration as provided under ERISA. The Company recognized the $13,800,000 asserted liability in 1998. The arbitration proceeding began June 4, 2001 and evidence regarding determination of the appropriate withdrawal date has been submitted. The Company is awaiting the Arbitrator’s decision on the withdrawal date issue. Determination of the amount of withdrawal liability, if any, was deferred until the withdrawal date was determined. If necessary, a second arbitration proceeding to determine the amount of withdrawal liability will be held. In accordance with the Multiemployer Pension Plan Amendments Act of 1980, the Company has made monthly principal and interest payments to the Plan while it pursues its rights and will continue to make such monthly payments until arbitration is completed. Included in the payments made in 2002 is interest of approximately $696,000 and principal of $1,374,000. At the conclusion of arbitration the Company may be entitled to a refund or it could be required to pay any remaining obligation in installments through 2008.

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Under the Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”), the Company is required to provide postretirement medical benefits for UMWA miners by making premium payments into three benefit plans: (i) the UMWA Combined Benefit Fund (the “Combined Fund”), a multiemployer plan which benefits miners who retired before January 1, 1976 or who retired thereafter but whose last employer did not provide benefits pursuant to an operator-specific Individual Employer Plan (“IEP”), (ii) an IEP for miners who retired after January 1, 1976, and (iii) the 1992 UMWA Benefit Plan, a multiemployer plan which benefits (A) miners who were eligible to retire on February 1, 1993, who did retire on or before September 30, 1994 and whose former employers are no longer in business, (B) miners receiving benefits under an IEP whose former employer goes out of business and ceases to maintain the IEP, and (C) new spouses or new dependents of retirees in the Combined Fund who would be eligible for coverage thereunder but for the fact that the Combined Fund was closed to new beneficiaries as of July 20, 1992. The premiums paid by the Company cover its own retirees and its allocated portion of the pool of retired miners whose previous employers have gone out of business.

The Coal Act also authorized the Trustees of the 1992 UMWA Benefit Plan to implement security provisions for the payment of future benefits. The Trustees set the level of security for each company at an amount equal to three years’ benefits. The bond amount and the amount to be secured are reviewed and adjusted on an annual basis. The Company secured its obligation in 2001 by posting a bond for $21 million. The bond was collateralized by U.S. Government-backed securities in the amount of $7,968,000 at March 31, 2001 which amount the Company withdrew during the second quarter of 2001 in connection with a change of bonding agents. The Company’s previous bonding agent required collateral equal to approximately 40% of the bonded amount. The Company’s bond amount increased to approximately $25 million in early 2002 but was then reduced to approximately $22 million during the second quarter of 2002 by the Trustees of the 1992 UMWA Plan. The Company’s bonding agent required cash collateral of $300,000 to support the increased bond amount, which amount was deposited in June 2002. The amount of the bond collateral is periodically reviewed by the bonding agent and may be increased back to prior levels of approximately 40% of the bonded amount. The Company has been notified that additional collateral of $800,000 may be required in early 2003.

The Combined Fund faces an ongoing solvency crisis because benefit expenses continue to exceed premiums from contributing companies. The Combined Fund sought additional funding relief from Congress in 2000. Under the sponsorship of Senators Byrd and Rockefeller of West Virginia, the House and Senate approved, as a part of the Interior and Related Agencies Appropriations Bill, a transfer of accumulated interest in the Abandoned Mine Land Reclamation Fund (“AML”) to the Combined Fund. In its report, the conference committee noted that this was a short-term solution and urged that the Congressional committees with jurisdiction over the matter work with the concerned parties to insure the long-term solvency of the Combined Fund. The conference committee went on to admonish the parties not to ask for additional funding from AML in the future. This funding was in addition to the annual transfer from the AML Funds and does not prevent the Combined Fund from continuing to operate at a deficit.

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In September 2002, Congressmen Rahall of West Virginia introduced a bill (“HR 3813”) to further modify the allocation of interest that accrues to the AML and permit additional use of the accrued interest by the Combined Fund. HR 3813 would remove the $70 million cap on annual transfers of interest balances from the AML to the Combined Fund and remove the requirement that transferred funds must be used to provide benefits for the unassigned beneficiaries. HR 3813 allows interest transfers to be made to offset the amount of any deficits to the Combined Fund or to prevent reductions in health care coverage. The Congressional Budget Office (“CBO”) estimates that the Combined Fund will record a deficit of net assets in 2002 and each year thereafter. It is estimated that the Combined Fund will run a deficit of more than $450 million over the 2003-2012 period. Without some relief like HR 3813, the Combined Fund estimates that it will have to reduce benefits starting in 2004 and will need to cut $421 million in benefits over the 2004-2012 period with the current $70 million cap. HR 3813 passed the House but not the Senate before adjournment in 2002 and is expected to be reintroduced in the 107th Session of Congress.

In connection with its dismissal from Chapter 11 in 1998, the Company agreed to secure its obligations under the Master Agreement for a period of six years by providing a Contingent Promissory Note (“Note”). The original principal amount of the Note was $12 million. The Company collateralized its obligations under the Note in part by posting $6 million for the first three years in an escrow account. The Note is payable only in the event the Company does not meet its Coal Act obligations, fails to meet certain ongoing financial tests specified in the Note, or failed to maintain a required balance of $6 million in an escrow account through 2001. The Company met all of these requirements through 2001 and, accordingly, in January 2002, the principal amount of the Note was reduced to $6 million and the $6 million collateral was returned to the Company on May 1, 2002. The remaining Note amount of $6 million is secured by the ROVA cash flows to the Company which must be maintained at a minimum of $8 million per year.

A Medicare prescription drug benefit that covers Medicare-eligible beneficiaries covered by the Coal Act could reduce one of the Company’s largest costs. Of the over $20 million per year the Company paid for retirees’ health care costs in 2002, more than 50% is for prescription drugs. Provision of such a benefit continues to be debated on the national level, and although both Republicans and Democrats proposed new bills in 2002, none of the bills passed both houses of Congress. It is expected that both parties will introduce legislation intended to address prescription drugs in the 107th Congress. There is no assurance at this time what, if any, new proposal will be enacted into law or what effect that it may have on the Company’s obligation.

The Company expects that there will be continued upward pressure on corporate insurance and surety bonding rates as a result of insurers’ world-wide loss experiences over the past several years, the terrorist attacks in September 2001 and ongoing threats around the world. Property and casualty premiums are increasing by extraordinary amounts and some companies face limitations on the amount of coverage and bonding capacity available to them. Westmoreland was able to maintain all required insurance coverage and capacity as of July 1, 2002 but at higher premiums. At the beginning of the third quarter, the Company formed an offshore-based captive insurance company to help mitigate the effect of escalating premiums. The captive insurance company elected to be a U.S. tax paying entity.

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The Company’s acquisitions in 2001 greatly increased revenues and operating cash flow, and have returned the Company to profitability, but the cash used and financing arranged to make those acquisitions could also create short-term liquidity issues which must be managed. The Company used $39 million of available cash in the second quarter of 2001 to complete the acquisitions, knowing that short-term liquidity would be temporarily reduced by doing so. The terms of the acquisition financing facility also restricted distributions to the Company from WML, particularly through March 2002, while the required debt service reserve account was being initially funded. Distributions available from WML increased in the second quarter of 2002 when a one-time reduction in the debt service reserve account of approximately $2 million was realized after the $20 million Term A Notes were fully repaid at June 28, 2002. However, the debt financing requires that 25% of excess cash flow, as defined, be used to fund the balloon payment due in 2008. Therefore, only 75% of WML’s excess cash flow is available to the Company until the debt is paid off.

The final purchase price for the acquisition of Montana Power’s coal business is subject to adjustment. As discussed in Item 3 Legal Proceedings of this Annual Report on Form 10-K, the Company and Montana Power were not able to agree on either the amount of the purchase price adjustment or the methodology to calculate the adjustment within the time frame provided for under the Purchase Agreement. The Company initiated an action in the Supreme Court of New York on November 26, 2001, seeking specific performance of the purchase price methodology provided for under the Purchase Agreement. Any change in the purchase price will cause a change to the preliminary purchase price allocation. If the purchase price is reduced, the Company and WML may be required to use the proceeds received from Entech and Montana Power to pay down the indebtedness described in Note 5 to the Consolidated Financial Statements. In the unlikely event an additional purchase price payment is required it would likely be funded by the use of WML’s revolving credit facility. Touch America, Montana Power’s successor, has publicly reported that it only has sufficient cash to maintain operations until mid-second quarter 2003. Although there can be no assurance as to the ultimate outcome of this dispute, the Company believes its claims are meritorious and intends to pursue its rights vigorously.

The Company’s ongoing and future business needs may also affect liquidity. The Company does not anticipate that its coal and power production will diminish materially as a result of the continued economic downturn because the independent power projects in which the Company owns interests and the power plants that purchase coal mined by the Company produce relatively low-cost, baseload power. In addition, most of the Company’s production is sold under long-term contracts, which help insulate the Company from unfavorable reductions in tons sold. However, contract price reopeners, contract expirations or terminations, and market competition could affect future price and production levels. The Company’s largest customers include companies which have subsidiaries who have suffered downgraded credit ratings which may later affect the customers as the entire energy industry is impacted by tighter liquidity. The Company invoices its customers for coal sales either semi-monthly or monthly and limits its credit exposure by closely monitoring its accounts receivable.

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In previous years, WRI expended approximately $4.1 million to repair the dragline at WRI. All of these expenditures substantially increased the productive life of the dragline and therefore were capitalized. The Company believed that, under the terms of WRI’s agreements with WGI, WGI was responsible for all of these expenditures. WRI expended these amounts to assure continued, uninterrupted production at WRI, and demanded reimbursement from WGI for the full cost of the repair. WGI initially reimbursed WRI for only approximately $530,000 of these costs. On March 7, 2000, WRI commenced litigation against WGI in the United States District Court for the District of Montana seeking, among other things, payment by WGI of approximately $3.6 million of dragline repair costs paid by WRI, plus accrued interest. The Company did not immediately record any amounts that may have been recoverable from WGI in its Consolidated Financial Statements. WGI faced a severe near-term liquidity problem and in May 2001 WGI sought protection in the bankruptcy court in Reno, Nevada. WRI filed claims against WGI to recover the cost of repairing the dragline, for overcharges on mining costs, potential royalty underpayment as alleged by the MMS and seeking adequate assurances that WGI would perform its contractual obligations regarding reclamation. In addition, WRI objected to the assumption of existing contract mining agreements between WRI and WGI. As described in Note 14 to the Consolidated Financial Statements and Item 3, Legal Proceedings, WRI reached an agreement in the fourth quarter of 2002 that settled all of the pending litigation and was approved by the bankruptcy court. In addition to a reduced mining price at WRI and the provision of security by WGI for performance of its reclamation obligations, the agreement provided that WGI pay $3.6 million of dragline repair costs and settle claims for amounts withheld by WRI for past unpaid mining costs. These funds were received and the dragline reimbursement decreased its carrying value and will decrease future depletion expense.

The Company has certain contract contingencies, which may impact future sales, prices received and cost of operations. These include, but are not limited to:

• NWR’s dispute with TGN, the owner/operator of the Limestone Station, concerning Rights of First Refusal damages for PRB coal purchased, royalties for coal on leases owned by TGN and payment for purchasing shortfalls during the last six months of 2002; and,

• A price reopener triggered in July 2001 under WECO’s Coal Supply Agreement with the owners of Colstrip Units 1 and 2 which the Company believes will ultimately result in an increase in the overall value of the Coal Supply Agreement to the Company.

In addition, there are other issues regarding royalty payments, state income tax audits, property taxes and reclamation obligations and related bonding requirements, which may affect the Company, but their impact is not known at this time.

Westmoreland Terminal Company’s interest in DTA was being utilized at less than capacity and had been incurring operating losses of approximately $2.0 million per year due to the continued softness of the export market for U.S. coal and a lack of throughput for the Company’s space at the terminal. An impairment of the Company’s investment in DTA was recognized during third quarter 2002 as the result of the price associated with another partner’s sale of its interest in DTA and as discussed in Results of Operations below. On January 29, 2003, the Company entered into a letter of intent with a subsidiary of Dominion Resources, Inc. to sell its 20% partnership interest in DTA and its industrial revenue bonds for total consideration of $10.5 million. A Purchase and Sale Agreement was executed on March 14, 2003. Under the terms of the Purchase and Sale Agreement, Westmoreland Terminal Company will guarantee throughput through the terminal for a period of three years. To secure the throughput commitment, the purchaser will deposit $6.0 million of the sale proceeds as collateral for a stand-by letter of credit for the purchaser. Westmoreland Terminal Company made certain representations about the status of its partnership interest, the industrial revenue bonds being purchased and the general condition of DTA and agreed to indemnify the purchaser for any loss incurred as a result of a breach of these representations. The liability for a breach of the representations and warranties is capped at $4.5 million. The representations and warranties will expire at various times over the next several years. Westmoreland has guaranteed Westmoreland Terminal Company’s obligations under the Purchase and Sale Agreement for a period of five years in an amount that will decline to $2.5 million after 2 1/2 years. As a result, the Company will recognize a pretax gain of approximately $4.5 million when the transaction closes. Closing is expected to take place promptly after receipt of all bank and partnership consents or following expiration of DTA partnership rights of first refusal. At closing, the purchaser will assume all of Westmoreland Terminal Company’s DTA partnership obligations. The Company will no longer incur DTA-related operating losses, which were $2,050,000, $1,922,000 and $1,800,000 in 2002, 2001 and 2000, respectively. Due to the sale of the Company’s investment, the financial results relating to DTA have been presented as Discontinued Operations in the accompanying Consolidated Statements of Operations.

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The Company has a 4.49% Class B Limited Partnership interest in the Ft. Lupton power project. No distributions have been received from that project since 1999 and distributions are not expected to resume until 2005 due to spikes in natural gas prices which reduced earnings and caused non-compliance with debt ratios. Until debt ratios are brought back into compliance, no distributions from this project are allowed.

The Company is mindful of the need to manage costs with respect to the timing of receipts, and variations in distributions or expected performance. For instance, scheduled coal customer plant outages during 2003, primarily during the second quarter, and scheduled outages at the ROVA power projects during the first and third quarters are expected to reduce revenues and profits during those periods. Also, the Jewett Mine’s recent transition to market-based pricing is expected to provide lower profits during the 18 months ending December 31, 2003 than compared to the cost-plus mechanism previously in place. Therefore, the Company continues to take steps to conserve cash wherever possible. In January 2003, the Company amended its revolving line of credit for general corporate purposes, increasing it from $7 million to $10 million, of which $0.5 million was outstanding as of December 31, 2002.

The Company also aims to increase its sources of profitability and cash flow. Given possible future demand for new power generating capacity, stronger energy pricing, the need for stabilizing fuel and electricity costs, and pressure to reduce harmful emissions into the environment, the Company believes that its strategic plan positions it well for potential further growth, profitability, and improved liquidity.

The Company’s ongoing and future business needs may also affect its liquidity. The Company’s growth plan is focused on acquiring profitable businesses and developing projects in the energy sector which complement the Company’s existing core operations and where America’s dual goals of low cost power and a clean environment can be effectively addressed. The Company has sought to do this in niche markets that minimize exposure to competition, maximize stability of long-term cash flows and provide opportunities for synergistic operation of existing assets and new opportunities. The Company regularly seeks opportunities to make additional strategic acquisitions, to expand existing businesses and to enter related businesses. The Company considers potential acquisition opportunities as they are identified, but cannot be assured that it will be able to consummate any such acquisition. The Company anticipates that it would finance acquisitions by using its existing capital resources, by borrowing under existing bank credit facilities, by issuing equity securities or by incurring additional indebtedness. The Company may not have sufficient available capital resources or access to additional capital to execute potential acquisitions, and the Company may not find suitable acquisition candidates at acceptable prices. There is no assurance that the Company’s current or future acquisition efforts will be successful or that any such acquisition will be completed on terms that are favorable to the Company. Acquisitions involve risks, including difficulties in integrating acquired operations, diversions of management resources, debt incurred in financing such acquisitions and unanticipated problems and liabilities. Any of these risks could have a material adverse effect upon the Company’s business, financial condition and results of operations.

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A key to the Company’s strategy is the availability of approximately $174 million in NOLs at the end of 2002. The availability of these NOLs can shield the Company’s future taxable income from payment of regular Federal income tax and thereby increase the return the Company receives from profitable investments (as compared to the return a tax-paying entity would receive that cannot shield its income from federal income taxation).

The availability of the Company’s NOLs is governed by Section 382 of the Internal Revenue Code of 1986 (“Code”). The Code limits the utilization of a corporation’s NOLs if an “ownership change” within the meaning of the Code (an “Ownership Change”) occurs with respect to that corporation. In general, an Ownership Change occurs if, among other things, “5-Percent shareholders” within the meaning of the Code (“5-Percent Shareholders”) increase their percentage ownership of the corporation’s stock by more than 50 percentage points over any three-year period. A 5-Percent Shareholder is any person who owns 5 percent or more of the value of the corporation’s stock, and the value of the corporation’s stock is the sum of the market values of all of the corporation’s outstanding shares. The Company continues to monitor the ongoing status of ownership changes by 5-Percent Shareholders and cautions its current shareholders and potential investors that the creation of new 5-Percent Shareholders or trading by existing 5-Percent Shareholders could negatively impact the calculation of the Ownership Change. The Company believes that, based on public information currently on file, there has not been an Ownership Change, and that the percentage of change is approximately 11% as of December 31, 2002. If the percentage of change begins to again approach the 50% limitation, then the Company may ask existing and potential shareholders for their assistance in minimizing the change. If the change exceeds the 50% limitation, the Company may be unable to use a portion of its NOLs.

Sources of potential additional future liquidity may also include resolution of the NWR dispute with TGN and WECO’s price re-opener with the owners of Colstrip Units 1 and 2 discussed above, the sale of non-strategic assets, reimbursement of amounts paid to the 1974 UMWA Pension Plan and increased cash flow from existing operations.

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A possible short-term impact on the Company’s liquidity is its obligation in mid-2003 to pay the vested benefit of the long-term incentive performance units granted in 2000 under the Company’s 2000 Performance Unit Plan. That plan tied the amount of the incentive to the absolute increase in stock value over three years. The obligation fluctuates with changes in the market value of the Company’s common stock but is estimated to be $3.8 million as of December 31, 2002. A portion of the 2003 payment may be voluntarily deferred by the recipients to future years using the Company’s newly adopted Deferred Compensation Plan. In the course of considering adoption of the Deferred Compensation Plan, the Company was informed by all participating members of the 2000 Performance Unit Plan that they would defer a significant portion of the 2003 pay-out for periods of no less than three years. Also, at the discretion of the Board of Directors, some or all of the obligation can be paid by issuing Company stock, to the extent approved by shareholders. Additional long-term incentive obligations may be payable in future years but the potential expense is more limited since the value of the awards is linked to the relative appreciation in stock value and is capped.

The Company has three separate defined benefit pension plans for full-time employees after combining three of five prior plans effective for the 2002 plan year. The future funding of these plans could have a long-term impact on liquidity determined primarily by investment returns on the plans’ assets. During 2002, one of the plans required an additional contribution of $78,000 with increasing contributions expected to be required in future years unless investment returns materially improve above assumed rates of return. After three of the plans were combined, additional contributions are expected to be postponed until 2005 and the total payments reduced. However, based upon current actuarial assumptions and projections, the required minimum annual cash contributions will grow from approximately $1.2 million in 2005 to $5.1 million in 2008 unless investment returns improve or funding requirements change.

In conclusion, there are many factors which can both positively or negatively affect the Company’s liquidity and cash flow. Management believes that cash flows from operations, along with available borrowings, should be sufficient to pay the Company’s heritage health benefit costs, meet repayment requirements of the debt facilities, meet pension plan funding requirements, pay long-term performance plan obligations and fund ongoing business activities as long as currently anticipated surplus cash distributions from WML are received. At the same time, the Company continues to explore contingent sources of additional liquidity on an ongoing basis and to evaluate opportunities to expand and/or restructure its debt obligations and improve its capital structure.

Preferred Dividends and Stock Repurchase Plan

The depositary shares were issued on July 19, 1992. Each depositary share represents one-quarter of a share of the Company’s Series A Convertible Exchangeable Preferred Stock. Dividends at a rate of 8.5% per annum were previously paid quarterly but were last suspended in the third quarter of 1995 pursuant to the requirements of Delaware law, described below, as a result of recognition of net losses, the violation of certain bank covenants, and a subsequent shareholders’ deficit. The Company commenced payment of dividends to preferred shareholders on October 1, 2002 as described below. The quarterly dividends which are accumulated but unpaid through and including January 1, 2003 amount to $14,256,000 in the aggregate ($68.93 per preferred share or $17.23 per depositary share). Common stock dividends may not be declared until the preferred stock dividends that are accumulated but unpaid are made current.

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There are statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which the Company is incorporated. Under Delaware law, the Company is permitted to pay preferred stock dividends only: (1) out of surplus, surplus being the amount of shareholders’ equity in excess of the par value of the Company’s two classes of stock; or (2) in the event there is no surplus, out of net profits for the fiscal year in which a preferred stock dividend is declared (and/or out of net profits from the preceding fiscal year), but only to the extent that shareholders’ equity exceeds the par value of the preferred stock (which par value was $207,000 at December 31, 2002). The Company had shareholders’ equity at December 31, 2002 of $18,568,000 and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $19,485,000 at December 31, 2002.

The Board of Directors regularly reviews the subjects of current preferred stock dividends and the accumulated unpaid preferred stock dividends, and is committed to meeting its obligations to the preferred shareholders in a manner consistent with the best interests of all shareholders. On August 9, 2002 the Board of Directors declared a dividend of $0.15 per depositary share which was paid on October 1, 2002 to holders of record as of September 17, 2002. On November 8, 2002, the Board of Directors declared a dividend of $0.15 per depositary share which was paid on January 1, 2003 to holders of record as of December 9, 2002. On February 7, 2003, the Board of Directors declared a third dividend of $0.15 per depositary share payable on April 1, 2003 to holders of record as of March 7, 2003.

On August 9, 2002 Westmoreland’s Board of Directors authorized the repurchase of up to 10% of the outstanding depositary shares on the open market or in privately negotiated transactions with institutional and accredited investors between then and the end of 2004. The timing and amount of depositary shares repurchased will be determined by the Company’s management based on its evaluation of the Company’s capital resources, the price of the depositary shares offered to the Company and other factors. The program will expire at the end of 2004. Any acquired shares will be converted into shares of Series A Convertible Exchangeable Preferred Stock and retired. The repurchase program will be funded from working capital which may be currently available, or become available to the Company. During 2002, 7,500 depositary shares were repurchased by the Company at a total cost of $244,000.

Resumption of a dividend payment and the repurchase plan reflect the reestablishment of profitability as a result of the Company’s successful initial implementation of its strategic plan for growth and the Company’s continuing commitment to preferred shareholders.

Results of Operations
2002 Compared to 2001

Coal Operations.The increase in revenues is primarily the result of the Company experiencing a full year of contributions in 2002 from the acquisitions completed in April 2001. Of the 26.1 million equivalent tons sold during 2002, all except a few insignificant industrial orders were sold under long-term contracts, to owners of power plants located adjacent to or nearby the mines, other than at WRI. Beginning in the third quarter of 2002, revenues at the Jewett Mine were lower, as expected, as a result of the new market-based price effective July 1, 2002 which was less than the previous cost-plus fees. Equivalent tons sold include petroleum coke sales which are expected to continue through April 2003. There was a reduction in tons sold at the Rosebud Mine due to several unplanned outages at a customer’s plant as well as reduced power plant demands at LEGS which is supplied by the Jewett Mine as discussed below. Cost as a percentage of revenues decreased to 75% in 2002 compared to 77% in 2001 with a full year of operations at the acquired mines which have better margins than the Absaloka Mine.

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During the unplanned outages at the Colstrip Station in 2002, mining operations at the Rosebud Mine were carefully managed to minimize costs. Some of the tons not sold due to the outages were made up during the year. The Jewett Mine suffered reduced demand due to mild weather during the first six months of the year and the economic slowdown which reduced tons sold. In addition, tons sold from Jewett were reduced during the third quarter of 2002 due to a test burn of SPRB coal at the Limestone Station.

The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods:

		Year Ended
		2002		2001	Change
Revenues – thousands	$	301,235	$	231,048	30%
Volumes – millions of equivalent coal tons		26.062		20.503	27%
Cost of sales – thousands	$	226,707	$	177,304	28%

Depreciation, depletion and amortization increased to $11,539,000 in 2002 compared to $9,165,000 in 2001 due to capital expenditures and a full year of coal production from acquired operations.

Independent Power. Equity in earnings from the independent power operations was $14,506,000 in 2002 compared to $15,871,000 in 2001. The Virginia projects contributed $1,285,000 in 2001 equity earnings prior to their sale in March 2001. During 2002 and 2001, the ROVA projects produced 1,639,000 and 1,668,000 megawatt hours, respectively, and achieved average capacity factors of 89% and 90%, respectively. The decrease in 2002 was attributable to a small increase in the number of forced outage days for repairs.

Terminal Operations.Losses at Westmoreland Terminal Company, a wholly-owned subsidiary of the Company, continued in 2002 due to low throughput volume at Dominion Terminal Associates as a result of continued weakness in the export market and partnership cost-sharing obligations. WTC’s share of losses from DTA was $2,050,000 in 2002 compared to $1,922,000 in 2001. WTC owns a 20% interest in DTA. WTC is dependent upon its customers’ coal export business to maintain an acceptable level of throughput. The coal export business has experienced a significant decline due to a decline in worldwide demand for American metallurgical and steam coal and intense competitive pressure from coal suppliers in other nations. The Company does not believe that those competitive pressures will abate in the near term. WTC’s remaining investment of $3,712,000 in DTA was expensed as a non-cash impairment charge during the third quarter of 2002 as a result of continuing losses and an agreement by one of the terminal’s other owners which disposed of its interest in DTA. It should be noted that recognition of the impairment charge did not reduce the Company’s obligation for continued cash operating expenses or the ongoing recognition of such losses. As previously discussed, in March 2003 the Company agreed to sell its interest in DTA and will recognize a pretax gain of approximately $4.5 million when the transaction closes. Closing is expected to take place promptly after receipt of all bank and partnership consents or following expiration of DTA partnership rights of first refusal. The Company’s consolidated financial statements for 2002 and earlier years have been reclassified to reflect DTA as discontinued operations.

55

Costs and Expenses.Selling and administrative expenses were $32,248,000 for 2002 compared to $23,071,000 in 2001. The amounts for 2002 and 2001 include $18,440,000 and $11,559,000, respectively, incurred by the four mines acquired in 2001. Partially offsetting the 2002 increase was lower non-cash compensation expense for long-term employee performance incentives, with an expense of $1,046,000 in 2002 compared to an expense of $3,215,000 during 2001. Of the $1,046,000 expense in 2002, $136,000 was for performance units granted in 2000, $478,000 was for performance units granted in 2001 and $432,000 was for performance units granted in 2002. The long-term incentive plan program is designed to link management interests with those of shareholders by tieing long-term incentive compensation directly to appreciation in the value of the Company’s common stock. Performance units were granted in 2000 and 2001 because the Company did not have an adequate number of qualified stock options available for award and lesser amounts were granted in 2002 as more qualified stock options were available as a result of shareholder approval of additional shares for options in May, 2002. The expense for performance units (performance units, unlike stock options, are expensed) fluctuates with changes in the market value of the Company’s common stock. Vesting occurs over three years, but none of the performance units granted in 2000 will be paid until 2003, none of the performance units granted in 2001 will be paid until 2004 and none of the performance units granted in 2002 will be paid until 2005, and all can be paid at the discretion of the Board of Directors in Company stock, to the extent the required shares have been approved by shareholders. The amount payable for the performance units granted in 2000 are linked to the absolute change in value of the Company’s stock. The amount payable for the performance units granted in 2001 and 2002 are linked to the relative appreciation in the Company’s stock (compared to a peer group of other companies) and is capped to limit the potential amount of variable expense. The overall increase in selling and administrative expenses in 2002 is also due to higher legal costs related primarily to WRI’s dispute with WGI and an adverse judgment, with associated legal costs totaling $1.4 million in the Basin landowner case as described in Item 3 Legal Proceedings, to annual salary increases, and to the addition of employees associated with the Company’s growth. Medical claims under the Company’s self-insured plan for active employees were also higher in 2002. Fiscal 2001 benefited from a reduction of approximately $500,000 in the estimated liability for reclamation at the Bullitt Refuse Area while 2002 had a $300,000 additional benefit when the refuse area permit and associated liability were transferred to another operator.

56

Heritage health benefit costs were $26,921,000 in 2002 compared to $23,773,000 in 2001, reflecting increased costs for the post-retirement medical plans as actuarially determined, despite a decrease in payments made to the Combined Fund.

During 2002, the Company recognized a $1.1 million gain in connection with an administrative decision compensating the owners of the Ft. Drum independent power project for the U.S. Army’s unilateral decision to reduce the price it paid under its contract with the project.

Interest expense was $10,821,000 and $8,418,000 for 2002 and 2001, respectively. The increase was mainly due to the acquisition financing obtained during the second quarter of 2001, despite repayment of $23.7 million term debt of the acquisition financing during 2002. Interest income decreased in 2002 due to lower rates despite the larger amounts the Company holds in interest-bearing deposit accounts.

As a result of the acquisitions, the Company recognized a $55,600,000 deferred income tax asset in April 2001 which assumes that a portion of previously unrecognized net operating loss carryforwards will be utilized because of the projected generation of future taxable income. The deferred asset increased to $65,084,000 as of December 31, 2002 from $57,061,000 at December 31, 2001 because of temporary differences (such as accruals for pension and reclamation expense, which are not deductible for tax purposes until paid) arising during the intervening period and due to a reduction of the deferred income tax valuation allowance discussed above. Deferred tax assets are comprised of both a current and long-term portion. When taxable income is generated, the deferred tax asset relating to the Company’s net operating loss carryforwards is reduced and a deferred tax expense (non-cash) is recognized although no regular Federal income taxes are paid. Income tax benefit for 2002 represents a current income tax obligation for State income taxes, and the utilization of a portion of the Company’s net operating loss carryforwards, net of the impact of changes in deferred tax assets and liabilities. The agreement to sell DTA in 2003 increased the expected utilization of federal NOLs both due to the gain on sale and a reduction in future losses. This contributed to a reduction in the valuation allowance related to Federal NOLs and increased the tax benefit and net earnings. A tax loss in North Dakota that increased state NOLs and deferred tax assets was offset for the same amount by an increase in the valuation allowance since those losses are not expected to be utilized. The Federal Alternative Minimum Tax regulations were changed to allow 100% utilization of net operating loss carryforwards in 2001 and 2002 thereby eliminating all of the Company’s current Federal income tax expense.

Other Comprehensive Income. The other comprehensive loss of $88,000 (net of income taxes of $59,000) recognized during 2002 represents the change in the unrealized loss on an interest rate swap agreement on the ROVA debt caused by changes in market interest rates during the period. This compares to other comprehensive loss of $1,703,000 (net of income taxes of $1,135,000) for 2001. If market interest rates continue to decrease prior to repayment of the debt, additional comprehensive losses will be recognized. Conversely, increases in market interest rates would reverse previously recorded losses.

57

Results of Operations
2001 Compared to 2000

Coal Operations. The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods:

		Year Ended
		2001 (a)		2000	Change
Revenues – thousands	$	231,048	$	35,137	558%
Volumes – millions of equivalent coal tons		20.503		4.910	318%
Cost of sales – thousands	$	177,304	$	30,250	486%

(a) Includes only eight months of operations from acquisitions discussed in Note 2 to the Consolidated Financial Statements.

The dramatic increase of mining coal revenues to $231,048,000 in 2001 from $35,137,000 in 2000 is the result of adding eight months revenues from the acquisitions as well as approximately 1.0 million more tons from the Company’s existing mine. Of the 20.5 million equivalent tons sold during 2001, over 99% was sold under long-term contracts, to owners of power plants located adjacent to the mines, except at WRI. Equivalent tons sold include petroleum coke sales. The mines acquired in 2001 average a higher price per ton and better margins than the Absaloka Mine, which continued its operations. As a result, costs as a percentage of revenues decreased to 77% in 2001 compared to 86% in 2000.

Depreciation, depletion and amortization increased to $9,165,000 in 2001 compared to $1,972,000 in 2000 as a result of the acquisitions and the large increase in capital assets.

Independent Power. Equity in earnings from the independent power projects was $15,871,000 in 2001 compared to $32,260,000 in 2000. The decrease in 2001 reflects the loss of earnings associated with the sale of the Virginia projects in March 2001, and an increased realization of $8 million in December 2000 as a result of settlement of past underpayments at ROVA. The decrease in 2001 was partially offset by improved results from ROVA in 2001 due in part to the restructured power purchase agreement which also came out of the litigation settlement. During 2001 and 2000, the ROVA projects produced 1,668,000 and 1,648,000 megawatt hours, respectively, and achieved average capacity factors of 90% and 89%, respectively.

Terminal Operations.The Company’s share of losses from DTA was $1,922,000 in 2001 compared to $1,800,000 in 2000. DTA is dependent upon its customers’ coal export business to maintain an acceptable level of throughput. The continued loss was due to a continued weakness in the export market. The coal export business has experienced a significant decline due to intense competitive pressure from coal suppliers in other nations. The Company does not believe that those competitive pressures will abate in the near term.

58

Costs and Expenses.Selling and administrative expenses were $23,071,000 for 2001 compared to $6,839,000 for 2000. The increase includes $11,499,000 incurred during eight months by the Company’s four mines acquired in 2001. The increase is also due to $2,668,000 of non-cash compensation expense in 2001 for the management long-term performance units granted in 2000 compared to $824,000 expense in fiscal year 2000 and due to $507,000 non-cash expense for the performance units granted in 2001, which are tied to performance of the Company’s stock, the price of which increased dramatically during 2001. Other increases in 2001 are due to annual salary increases, bonuses and the addition of employees and related relocation expenses associated with the Company’s growth. Fiscal 2001 benefited from a reduction of approximately $500,000 in the estimated liability for reclamation at the Bullitt Refuse Area.

During 2001, the Company recorded a $123,000 loss on the sale of WELLC’s remaining interest in the Ft. Drum independent power project and a $317,000 loss related to the sale of WELLC’s interests in the three Virginia independent power projects. The recognition of the Virginia loss, as well as an impairment charge recognized in the fourth quarter of 2000, was necessary because the service lives originally adopted for depreciation purposes for these projects were greater than the cash flow streams provided under the existing term of the power supply agreements for the facilities. The proceeds from the sale of the Virginia projects totaling $24,903,000, including $8,949,000 from operating earnings distributed by the projects at the time of the sale, were used to fund a portion of the acquisitions completed during the second quarter of 2001.

Heritage health benefit costs increased to $23,773,000 in 2001 compared to $21,503,000 in 2000 primarily as a result of increased costs for postretirement medical plans and payments to the Combined Benefit Fund. In addition, a lower pneumoconiosis benefit was recognized in 2001 than in 2000.

Interest expense was $8,418,000 and $911,000 for 2001 and 2000, respectively. The increase was mainly due to the acquisition financing. Interest income increased during 2001 despite declining rates due to the larger deposit accounts acquired in the acquisitions.

As a result of the acquisitions, the Company recognized a $55.6 million deferred income tax asset which assumes that at least a portion of previously unrecognized net operating loss carryforwards will be utilized because of the projected generation of future taxable income. The asset increased to $57,061,000 as of December 31, 2001 and is comprised of both a current and long-term portion. When taxable income is generated, the deferred tax asset relating to the Company’s net operating loss carryforwards is reduced and a deferred tax expense (non-cash) is recognized although no regular Federal income taxes are paid. Income tax expense for 2001 represents a current income tax obligation for State income taxes, the utilization of a portion of the Company’s net operating loss carryforwards and the impact of changes in deferred tax assets and liabilities. The Federal Alternative Minimum Tax regulations were recently changed to allow 100% utilization of net operating loss carryforwards in 2001 and 2002 thereby eliminating the Company’s current Federal income tax expense. In 2001, an income tax benefit to the Company of $989,000 resulting from stock option exercises was added to other paid-in capital. The income tax benefit of $437,000 in 2000 was primarily the result of percentage depletion.

59

Other Comprehensive Loss.The other comprehensive loss of $1,703,000 (net of income taxes of $1,135,000) recognized in 2001 represents the unrealized loss on an interest rate swap agreement on the ROVA debt caused by decreases in market interest rates during the period. If market interest rates continue to decrease prior to repayment of the debt, additional comprehensive losses will be recognized. Conversely, increases in market interest rates would result in comprehensive gains.

NEW ACCOUNTING PRONOUNCEMENTS

In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143,Accounting for Asset Retirement Obligations.SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The pronouncement is effective for fiscal years beginning after June 15, 2002. In conjunction with the implementation of SFAS No. 143, the Company expects to record a cumulative effect of a change in accounting principles, net of taxes, ranging from an immaterial gain to a charge against income of approximately $0.5 million upon adoption of SFAS No. 143. In addition, the Company expects to record an asset retirement obligation of approximately $115 to $120 million. Future changes to implementation guidance, if any, could result in changes to these estimated impacts.

In August 2001, the FASB issued SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 supersedes SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. SFAS No. 144 establishes a single accounting model for long-lived assets to be disposed of by sale and requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The Company adopted SFAS No. 144 on January 1, 2002.

In April 2002, the FASB issued SFAS No. 145,Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections. Prior to the adoption of the provisions of SFAS No. 145, generally accepted accounting principles (“GAAP”) required gains or losses on the early extinguishment of debt be classified in a company’s periodic consolidated statements of operations as extraordinary gains or losses, net of associated income taxes, after the determination of income or loss from continuing operations. SFAS No. 145 changes GAAP to require, except in the case of events or transactions of a highly unusual and infrequent nature, gains or losses from the early extinguishment of debt to be classified as components of a company’s income or loss from continuing operations. The Company will adopt the provisions of SFAS No. 145 on January 1, 2003. The adoption of the provisions of SFAS No. 145 is not expected to affect the Company’s financial position or results of operations.

In June 2002, the FASB issued SFAS No. 146,Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value only when the liability is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of SFAS No. 146 is not expected to have an effect on the Company’s financial position or results of operations.

60

In November, 2002 the FASB issued Financial Interpretation No. 45,Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34 (FIN 45). FIN 45 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of FIN 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002.

In December, 2002 the FASB issued SFAS No. 148,Accounting for Stock-based Compensation-Transition and Disclosure. SFAS No. 148 amends FASB Statement No. 123,Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair-value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS No. 148 have no material impact on the Company, as we do not plan to adopt the fair-value method of accounting for stock options at the current time. We have included the required disclosures in the Summary of Significant Accounting Policies and in Note 12 to the Consolidated Financial Statements.

ITEM 7A – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risk, including the effects of changes in commodity prices as discussed below.

Commodity Price Risk

The Company, through its subsidiaries WRI and WML, produces and sells coal to third parties from coal mining operations in Montana, Texas and North Dakota and through its subsidiary, WELLC, produces and sells electricity and steam to third parties from its independent power projects located in North Carolina and Colorado. Nearly all of the Company’s coal production and all of its electricity and steam production are sold through long-term contracts with customers. These long-term contracts serve to minimize the Company’s exposure to changes in commodity prices although some of the Company’s contracts are adjusted periodically based upon market prices. The Company has not entered into derivative contracts to manage its exposure to changes in commodity prices, and was not a party to any such contracts at December 31, 2002.

61

Interest Rate Risk

The Company and its subsidiaries are subject to interest rate risk on its debt obligations. Long-term debt obligations have both fixed and variable interest rates, and the Company’s revolving line of credit has a variable rate of interest indexed to either the prime rate or LIBOR. Interest rates on these instruments approximate current market rates as of December 31, 2002. Based on the balances outstanding as of December 31, 2002, a one percent change in the prime interest rate or LIBOR would increase interest expense by $20,000 on an annual basis. The Company’s heritage health benefit costs are also impacted by interest rate changes because its pension, pneumoconiosis and post-retirement medical benefit obligations are recorded on a discounted basis.

ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements	Page
Consolidated Balance Sheets	64
Consolidated Statements of Operations	66
Consolidated Statements of Shareholders' Equity and Comprehensive Income	67
Consolidated Statements of Cash Flows	68
Summary of Significant Accounting Policies	70
Notes to Consolidated Financial Statements	76

63

Westmoreland Coal Company and Subsidiaries
Consolidated Balance Sheets

December 31,		2002		2001
		(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	9,845	$	5,233
Receivables:
Trade		20,962		34,381
Other		1,221		3,075
		22,183		37,456
Inventories		14,018		13,748
Restricted cash		8,497		14,371
Deferred income taxes		15,831		15,859
Other current assets		6,765		5,941
Total current assets		77,139		92,608
Property, plant and equipment:
Land and mineral rights		53,314		53,564
Plant and equipment		197,759		194,529
		251,073		248,093
Less accumulated depreciation and depletion		61,541		50,822
Net property, plant and equipment		189,532		197,271
Deferred income taxes		49,253		41,202
Investment in independent power projects		33,407		28,707
Investment in Dominion Terminal Associates-held for sale		-		3,975
Prepaid pension cost		-		4,783
Excess of trust assets over pneumoconiosis benefit
obligation		7,665		6,985
Restricted cash and bond collateral		8,790		4,052
Advance coal royalties		4,639		6,570
Deferred overburden removal costs		10,348		9,517
Reclamation deposits		49,484		47,924
Reclamation receivables		8,370		10,360
Other assets		12,437		12,578
Total Assets	$	451,064	$	466,532

See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.

(Continued)

64

Westmoreland Coal Company and Subsidiaries
Consolidated Balance Sheets (Continued)

December 31,		2002		2001
		(in thousands)
Liabilities and Shareholders' Equity
Current liabilities:
Current installments of long-term debt	$	8,852	$	13,753
Accounts payable and accrued expenses:
Trade		27,070		24,168
Income taxes		594		57
Production taxes		14,273		17,544
Workers’ compensation		2,335		2,900
Postretirement medical costs		12,787		13,966
1974 UMWA Pension Plan obligations		1,473		1,374
Reclamation costs		11,381		7,500
Total current liabilities		78,765		81,262
Long-term debt, less current installments		91,305		109,157
Accrual for workers’ compensation, less current portion		8,405		10,141
Accrual for postretirement medical costs, less current
portion		104,336		97,127
Accrual for pension and SERP costs		4,341		1,752
1974 UMWA Pension Plan obligations, less current
portion		6,562		8,035
Accrual for reclamation costs, less current portion		127,517		132,148
Other liabilities		6,732		11,522
Minority interest		4,533		4,973
Commitments and contingent liabilities
Shareholders' equity
Preferred stock of $1.00 par value
Authorized 5,000,000 shares;
Issued and outstanding 206,833 shares at          December 31, 2002 and 208,708 shares          at December 31, 2001		207		209
Common stock of $2.50 par value
Authorized 20,000,000 shares;
Issued and outstanding 7,711,379 shares at
December 31, 2002 and 7,515,221 shares          at December 31, 2001		19,278		18,787
Other paid-in capital		70,908		69,723
Accumulated other comprehensive loss		(5,101)		(1,703)
Accumulated deficit		(66,724)		(76,601)
Total shareholders' equity		18,568		10,415
Total Liabilities and Shareholders' Equity	$	451,064	$	466,532

See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.

65

Westmoreland Coal Company and Subsidiaries
Consolidated Statements of Operations

Years Ended December 31,		2002		2001		2000
		(in thousands except per share data)
Revenues:
Coal	$	301,235	$	231,048	$	35,137
Independent power projects - equity in earnings		14,506		15,871		32,260
		315,741		246,919		67,397
Cost and expenses:
Cost of sales – coal		226,707		177,304		30,250
Depreciation, depletion and amortization		11,539		9,165		1,972
Selling and administrative		32,248		23,071		6,839
Heritage health benefit costs		26,921		23,773		21,503
Doubtful accounts recoveries		(516)		(446)		(400)
Impairment charges		-		-		4,632
Loss on sales of assets		9		440		6
		296,908		233,307		64,802
Operating income from continuing operations		18,833		13,612		2,595
Other income (expense):
Interest expense		(10,821)		(8,418)		(911)
Interest income		2,117		2,657		1,866
Minority interest		(800)		(780)		(518)
Other income (expense)		2,011		572		(999)
		(7,493)		(5,969)		(562)
Income from continuing operations before   income taxes		11,340		7,643		2,033
Income tax benefit (expense) from   continuing operations		2,368		(1,228)		(428)
Net income from continuing operations		13,708		6,415		1,605
Discontinued operations:
Loss from operations of      discontinued terminal segment (including      impairment charge in 2002 of $3,712)		(5,971)		(1,980)		(2,162)
Income tax benefit		2,388		792		865
Loss from discontinued operations		(3,583)		(1,188)		(1,297)
Net income		10,125		5,227		308
Less preferred stock dividend requirements		1,772		1,776		1,776
Net income (loss) applicable to common
shareholders	$	8,353	$	3,451	$	(1,468)
Net income (loss) per share applicable to
common shareholders:
Basic	$	1.10	$	0.48	$	(0.21)
Diluted	$	1.03	$	0.43	$	(0.21)
Weighted average number of common
shares outstanding - basic		7,608		7,239		7,070
Weighted average number of common
shares outstanding – diluted		8,147		8,000		7,070

See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.

66

Westmoreland Coal Company and Subsidiaries
Consolidated Statements of Shareholders’ Equity
and Comprehensive Income
Years Ended December 31, 2000, 2001, and 2002

		Class A Convertible Exchangeable Preferred Stock		Common Stock		Other Paid-In Capital		Accumulated Other Comprehensive Loss		Accumulated Deficit		Total Shareholders’ Equity
		(in thousands)
Balance at December 31, 1999
(208,708 preferred shares and 7,067,663 common shares outstanding)	$	209	$	17,669	$	67,315	$	-	$	(82,136)	$	3,057
Common stock options
exercised (2,000 shares)		-		5		3		-		-		8
Net income		-		-		-		-		308		308
Balance at December 31, 2000
(208,708 preferred shares and 7,069,663 common shares outstanding)		209		17,674		67,318		-		(81,828)		3,373
Common stock issued as
compensation (74,108       shares)		-		185		865		-		-		1,050
Common stock options
exercised (371,450 shares)		-		928		551		-		-		1,479
Tax benefit of stock option       exercises		-		-		989		-		-		989
Net income		-		-		-		-		5,227		5,227
Net unrealized change in      interest rate swap agreement,      net of tax benefit of $1,135		-		-		-		(1,703)		-		(1,703)
Comprehensive income												3,524
Balance at December 31, 2001
(208,708 preferred shares and 7,515,221 common shares outstanding)		209		18,787		69,723		(1,703)		(76,601)		10,415
Common stock issued as
compensation (118,258      shares)		-		296		1,128		-		-		1,424
Common stock options
exercised (77,900 shares)		-		195		139		-		-		334
Repurchase and retirement of
preferred shares       (1,875 shares)		(2)		-		(242)		-		-		(244)
Dividends declared		-		-		-		-		(248)		(248)
Tax benefit of stock option
exercises		-		-		160		-		-		160
Net income		-		-		-		-		10,125		10,125
Minimum pension liability, net
of tax benefit of $2,207		-		-		-		(3,310)		-		(3,310)
Net unrealized change in
interest rate swap agreement,
net of tax benefit of $59		-		-		-		(88)		-		(88)
Comprehensive income												6,727
Balance at December 31, 2002
(206,833 preferred shares and 7,711,379 common shares outstanding)	$	207	$	19,278	$	70,908	$	(5,101)	$	(66,724)	$	18,568

See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.

67

Westmoreland Coal Company and Subsidiaries
Consolidated Statements of Cash Flows

Years Ended December 31,		2002		2001		2000
		(in thousands)
Cash flows from operating activities:
Net income	$	10,125	$	5,227	$	308
Adjustments to reconcile net income to net cash
provided by operating activities:
Equity in earnings of independent power projects		(14,506)		(15,871)		(32,260)
Cash distributions from independent power projects		9,718		18,426		23,434
Share of losses of DTA		2,050		1,922		1,800
Cash generated by DTA		92		257		168
Cash contributions to DTA		(1,879)		(1,827)		(1,623)
Deferred income tax benefit		(5,656)		(472)		-
Depreciation, depletion and amortization		11,539		9,165		1,972
Stock compensation expense		1,424		1,050		-
Impairment charges		3,712		-		4,632
Losses on sales of assets		9		440		6
Distributions from pneumoconiosis trust		-		-		6,397
Minority interest		800		780		518
Other		-		-		(154)
Changes in assets and liabilities:
Receivables, net		15,273		(5,429)		(893)
Inventories		(270)		(456)		-
Excess of trust assets over pneumoconiosis
benefit obligation		(680)		(178)		(1,552)
Accounts payable and accrued expenses		(369)		13,049		(2,100)
Income taxes payable		537		57		315
Accrual for workers’ compensation		(2,301)		(2,295)		(2,936)
Accrual for postretirement medical costs		6,030		4,728		4,695
1974 UMWA Pension Plan		(1,374)		(1,279)		(1,191)
Other assets and liabilities		(4,287)		1,141		624
Net cash provided by operating activities		29,987		28,435		2,160
Cash flows from investing activities:
Additions to property, plant and equipment		(7,323)		(5,433)		(647)
Cash paid for acquisitions		-		(162,700)		-
Reimbursement from mine operator		3,600		-		530
Change in restricted cash and bond collateral		1,136		794		(4,321)
Change in other long-term assets		887		-		-
Net proceeds from sales of investments and assets		476		16,014		4
Net cash used in investing activities		(1,224)		(151,325)		(4,434)

(Continued)

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Westmoreland Coal Company and Subsidiaries
Consolidated Statements of Cash Flows (Continued)

Years Ended December 31,		2002		2001		2000
		(in thousands)
Cash flows from financing activities:
Proceeds from long-term debt, net of debt issuance      costs		-		114,604		-
Repayment of long-term debt		(13,753)		(12,053)		(1,563)
Net borrowings (repayments) of revolving lines of      credit, net		(9,000)		11,000		-
Repurchase of preferred shares		(244)		-		-
Dividends paid to minority shareholders of subsidiary		(1,240)		(1,100)		(2,100)
Exercise of stock options		334		1,479		8
Dividends on preferred shares		(248)		-		-
Net cash provided by (used in) financing activities		(24,151)		113,930		(3,655)
Net increase (decrease) in cash and cash equivalents		4,612		(8,960)		(5,929)
Cash and cash equivalents, beginning of year		5,233		14,193		20,122
Cash and cash equivalents, end of year	$	9,845	$	5,233	$	14,193
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest	$	10,176	$	8,340	$	1,000
Income taxes		886		1,209		2

See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.

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Westmoreland Coal Company and Subsidiaries
Summary of Significant Accounting Policies

Consolidation Policy

The consolidated financial statements of Westmoreland Coal Company (the “Company”) include the accounts of the Company and its majority-owned subsidiaries, after elimination of intercompany balances and transactions. The Company uses the equity method of accounting for companies where its ownership is between 20% and 50% and for partnerships and joint ventures in which less than a controlling interest is held.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.

Cash Equivalents

The Company considers all highly liquid debt instruments purchased with original maturities of three months or less to be cash equivalents. All such instruments are carried at cost, which approximates market. Cash equivalents consist of Eurodollar time deposits, money market funds and bank repurchase agreements.

Inventories

Inventories, which include materials and supplies as well as raw coal, are stated at the lower of cost or market. Cost is determined using the average cost method.

Property, Plant and Equipment

Property, plant and equipment are carried at cost and include expenditures for new facilities and those expenditures that substantially increase the productive lives of existing plant and equipment. Maintenance and repair costs are expensed as incurred. Mineral rights and development costs are depleted based upon estimated recoverable proven and probable reserves. Plant and equipment are depreciated on a units-of-production or straight-line basis over the assets’ estimated useful lives, ranging from 3 to 40 years. The Company assesses the carrying value of its property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing estimated undiscounted cash flows expected to be generated from such assets with their net book value. If net book value exceeds estimated cash flows, the asset is written down to fair value. When an asset is retired or sold, its cost and related accumulated depreciation and depletion are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss. Fully depreciated plant and equipment still in use are not eliminated from the accounts.

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Advanced Coal Royalties

Royalty payments made to lessors under terms of mineral lease agreements that are recoupable against future production are deferred. They are charged to expense as the leased coal reserves are mined.

Deferred Overburden Removal Costs

The cost of removing overburden in advance of coal extraction, net of amounts reimbursed by customers, is deferred and charged to expense when the coal is produced.

Workers’ Compensation and Pneumoconiosis Benefit Obligations

The Company is self-insured for workers’ compensation claims incurred prior to 1996 and federal and state pneumoconiosis benefits for current and former employees. Workers’ compensation claims incurred after January 1, 1996 are covered by a third party insurance provider.

The liability for workers’ compensation claims is an actuarially determined estimate of the ultimate losses incurred on such claims based on the Company’s experience, and includes a provision for incurred but not reported losses. Adjustments to the probable ultimate liability are made continually based on subsequent developments and experience and are included in operations as incurred.

Reclamation Deposits and Receivables

Certain of the Company’s customers have either agreed to reimburse the Company for reclamation expenditures as they are incurred or have pre-funded a portion of the expected reclamation costs. These funds will serve as a source for use for final reclamation activities. The total reclamation deposit of $49,484,000 at December 31, 2002 consists of $17,661,000 of cash and cash equivalents and $31,823,000 of Federal agency bonds. The Company has the intent and ability to hold these securities to maturity, and, therefore, accounts for them as held-to-maturity securities. Held-to-maturity securities are recorded at amortized cost, adjusted for the amortization or accretion of premiums or discounts calculated on the effective interest method. Interest income is recognized when earned. In addition, the Company has recognized $8,370,000 as a long-term receivable, which amount will be collected as certain reclamation activities are performed at the Rosebud and Jewett Mines.

The amortized cost, gross unrealized holding losses and fair value of held-to-maturity securities at December 31, 2002 are as follows (in thousands):

Amortized cost	$	31,823
Gross unrealized holding gains		222
Gross unrealized holding losses		(24)
Fair Value	$	32,021

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Maturities of held-to-maturity securities are as follows at December 31, 2002 (in thousands):

		Amortized Cost		Fair Value
Due in five years or less	$	28,086	$	28,269
Due after five years to ten years		3,737		3,752
	$	31,823	$	32,021

Post Retirement Benefits Other than Pensions

The Company accounts for health care and life insurance benefits provided to certain retired employees and their dependents by accruing the cost of such benefits over the service lives of employees. The Company is amortizing its transition obligation, for past service costs relating to these benefits, over twenty years. For UMWA represented union employees who retired prior to 1976, the Company provides similar medical and life insurance benefits by making payments to a multiemployer union trust fund. The Company expenses such payments when they become due.

Coal Revenues

The Company recognizes coal sales revenue at the time title passes to the customer in accordance with the terms of the underlying sales agreements.

Reclamation

Minimum standards for mine reclamation have been established by various regulatory agencies and dictate the reclamation requirements at the Company’s operations. Certain reclamation is performed and expensed on an ongoing basis as mining operations are performed. The remaining reclamation costs, along with other costs related to mine closure, are accrued and charged against income on a units-of-production basis over the life of the mine. Costs of future expenditures for reclamation and mine closure are not discounted to their present value.

WRI’s share of reclamation costs is fixed and is being recognized evenly over a 15-year period. Total expected reclamation costs at idled sites were fully accrued at the time of idling. Estimates at idle sites are periodically reviewed and adjustments are made in accruals to provide for changes in expected future costs.

Income Taxes

The Company accounts for deferred income taxes using the asset and liability method. Deferred tax liabilities and assets are recognized for the expected future tax consequences of events that have been reflected in the Company’s financial statements based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities, as well as operating loss and tax credit carryforwards, using enacted tax rates in effect in the years in which the differences are expected to reverse.

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Comprehensive Income

The Company is party to an interest rate swap agreement on the long-term debt at the Roanoke Valley I independent power project through a subsidiary which is accounted for under the equity method of accounting. In accordance with generally accepted accounting principles, the Company has reflected the difference between its 50% share of the fair value of this interest rate swap agreement and its carrying value as a separate component of shareholders’ equity. The swap agreement exchanged variable interest rates on debt for a fixed rate. Because market interest rates have declined below those provided for in the swap agreement, the fair value of the swap agreement has decreased. The change in current interest rates, net of income tax impacts, is a component of the Company’s total comprehensive income. If interest rates remain at their current levels, the Company will recognize its share of the loss in future periods as a reduction in equity in earnings of independent power projects.

During 2002, the Company recognized an additional minimum pension liability as a result of the accumulated pension benefit obligation exceeding the fair value of pension plan assets at December 31, 2002. This additional minimum liability, net of income tax effects, is shown as a separate component of shareholders’ equity.

Incentive Stock Options

The Company applies the intrinsic-value-based method of accounting prescribed by Accounting Principles Board (“APB”) Opinion No. 25,Accounting for Stock Issued to Employees, and related interpretations, to account for its fixed-plan stock options. Under this method, compensation expense is recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123,Accounting for Stock-Based Compensation, established accounting and disclosure requirements using a fair-value-based method of accounting for stock-based employee compensation plans. As allowed under SFAS No. 123, the Company has elected to continue to apply the intrinsic-value-based method of accounting described above, and has adopted only the disclosure requirements of SFAS No. 123. The following table illustrates the effect on net income (loss) and net income (loss) per share as if the compensation cost for the Company’s fixed-plan stock options had been determined based on the fair value at the grant dates consistent with SFAS No. 123:

		2002		2001		2000
	(in thousands, except per share data)
Net income (loss) applicable to   common shareholders:
As reported	$	8,353	$	3,451	$	(1,468)
Pro forma	$	6,698	$	1,986	$	(2,140)
Income (loss) per share   applicable to common   shareholders:
As reported, basic	$	1.10	$	.48	$	(.21)
Pro forma, basic	$	.88	$	.26	$	(.30)
As reported, diluted	$	1.03	$	.43	$	(.21)
Pro forma, diluted	$	.82	$	.25	$	(.30)

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The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for options granted in 2002, 2001 and 2000. The weighted average fair value of options granted in 2002, 2001 and 2000 was $13.92, $17.58 and $3.26, respectively.

Options Granted	Dividend Yield	Volatility	Risk-Free Rate	Expected Life
2002	None	229%	4.93 - 5.16%	10 years
2001	None	272%	4.89 - 5.39%	10 years
2000	None	257-304%	5.80 - 6.13%	8-10 years

Earnings Per Share

Basic earnings (loss) per share is computed by dividing net income (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share are determined on the same basis except that the weighted average shares outstanding are increased to include additional shares for the assumed exercise of stock options, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options were exercised and that the proceeds from such exercises were used to acquire shares of common stock at the average market price during the reporting period.

The following table provides a reconciliation of the number of shares used to calculate basic and diluted earnings per share (EPS):

	2002	2001	2000
Weighted average number of common shares outstanding:	(in thousands of shares)
Basic	7,608	7,239	7,070
Effect of dilutive instruments	539	761	-
Diluted	8,147	8,000	7,070
Number of shares not included in dilutive EPS that would have been antidilutive because the exercise or conversion price was greater than the average market price of the common shares.	309	113	N/A

NEW ACCOUNTING PRONOUNCEMENTS

        In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143,Accounting for Asset Retirement Obligations. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The pronouncement is effective for fiscal years beginning after June 15, 2002. In conjunction with the implementation of SFAS No. 143, the Company expects to record a cumulative effect of a change in accounting principles, net of taxes, ranging from an immaterial gain to a charge against income of approximately $0.5 million upon adoption of SFAS No. 143. In addition, the Company expects to record an asset retirement obligation of approximately $115 to $120 million. Future changes to implementation guidance, if any, could result in changes to these estimated impacts.

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In August 2001, the FASB issued SFAS No. 144,Accounting for the Impairment or Disposal of Long-LivedAssets. SFAS No. 144 supersedes SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. SFAS No. 144 establishes a single accounting model for long-lived assets to be disposed of by sale and requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The Company adopted SFAS No. 144 on January 1, 2002.

In April 2002, the FASB issued SFAS No. 145,Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections. Prior to the adoption of the provisions of SFAS No. 145, generally accepted accounting principles (“GAAP”) required gains or losses on the early extinguishment of debt be classified in a company’s periodic consolidated statements of operations as extraordinary gains or losses, net of associated income taxes, after the determination of income or loss from continuing operations. SFAS No. 145 changes GAAP to require, except in the case of events or transactions of a highly unusual and infrequent nature, gains or losses from the early extinguishment of debt to be classified as components of a company’s income or loss from continuing operations. The Company will adopt the provisions of SFAS No. 145 on January 1, 2003. The adoption of the provisions of SFAS No. 145 is not expected to affect the Company’s financial position or results of operations.

In June 2002, the FASB issued SFAS No. 146,Accounting for Costs Associated with Exit or DisposalActivities. SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value only when the liability is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of SFAS No. 146 is not expected to have an effect on the Company’s financial position or results of operations.

In November, 2002 the FASB issued Financial Interpretation No. 45,Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34 (FIN 45). FIN 45 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of FIN 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002.

In December, 2002 the FASB issued SFAS No. 148,Accounting for Stock-based Compensation-Transition and Disclosure. SFAS 148 amends FASB Statement No. 123,Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair-value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 have no material impact on the Company, as we do not plan to adopt the fair-value method of accounting for stock options at the current time. We have included the required disclosures in the Summary of Significant Accounting Policies and in Note 12 to the Consolidated Financial Statements.

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Reclassifications

Certain prior year amounts have been reclassified to conform to the current year presentation.

Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements

December 31, 2002, 2001 and 2000

1. NATURE OF OPERATIONS

The Company’s current principal activities, all conducted within the United States, are: (i) the production and sale of coal from Montana, North Dakota and Texas; and (ii) the development, ownership and management of interests in cogeneration and other non-regulated independent power plants. Prior to 2003, the Company was also engaged in the leasing of capacity at Dominion Terminal Associates (“DTA”), a coal storage and vessel loading facility. As discussed in Note 4, the Company agreed to sell its investment in DTA in March 2003 and its activities have been classified as discontinued operations in the Consolidated Statements of Operations.

2. ACQUISITIONS AND DISPOSITIONS

On April 30, 2001 and May 11, 2001, respectively, the Company, through its separate wholly owned, separate subsidiary Westmoreland Mining LLC (“WML”), completed the acquisitions of the coal business of The Montana Power Company (“Montana Power”) for approximately $136 million, and the coal operations of Knife River Corporation (“Knife River,” a subsidiary of MDU Resources Group, Inc.) for approximately $27 million. The acquisitions were effective April 30, 2001. WML is a special purpose Delaware limited liability company formed on December 4, 2000 for the purpose of facilitating the financing of these acquisitions and, through its subsidiaries, operating the Rosebud, Jewett, Beulah and Savage mines. The results of operations relating to the acquisitions have been included in the Company’s consolidated financial statements beginning on May 1, 2001.

In the Montana Power transaction, WML acquired the stock of Western Energy Company (“WECO”), which owns and operates the Rosebud Mine located in the northern Powder River Basin near the town of Colstrip, Montana, and Northwestern Resources Co. (“NWR”), which owns and operates the Jewett Mine in Central Texas. In addition, the Company acquired the stock of three entities that were not engaged in active operations: Basin Resources, Inc.; Horizon Coal Services, Inc. (“Horizon”); and North Central Energy Company. In connection with this acquisition, all of the membership interests in Western Syncoal LLC were transferred to the Company’s subsidiary, Westmoreland Power, Inc. (“WPI”). Western Syncoal LLC was previously a wholly owned subsidiary of Western Energy Company. In January 2003 Western Syncoal was sold to another company. At the closing of this transaction, the Company made a payment of $71,500 to the purchaser.

The final purchase price for the acquisition of Montana Power’s coal business is subject to adjustment pursuant to the terms of the Stock Purchase Agreement dated as of September 15, 2000 (the “Purchase Agreement”) between the Company and Entech, Inc. (“Entech”), the subsidiary through which Montana Power owned and conducted its coal business. See further discussion of the status of the purchase price adjustment in Note 14.

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In the Knife River transaction, WML’s subsidiary, Dakota Westmoreland Corporation, acquired all of the assets associated with the Beulah Mine in Beulah, North Dakota, and WML’s subsidiary, Westmoreland Savage Corp., acquired all of the assets associated with the Savage Mine in Savage, Montana. In connection with this transaction, WPI acquired certain rights related to the former Gascoyne mine site in North Dakota. In December 2001, the Company and Knife River agreed to final purchase price adjustments and in January 2002, the Company received approximately $600,000 from Knife River.

The acquisitions were funded with $39 million in cash contributed to WML by the Company and borrowings of $125 million ($120 million term debt and $5 million revolving line of credit) by WML as described in Note 5.

The acquisitions were recorded under the purchase method of accounting and, therefore, the purchase prices have been allocated to the assets acquired and liabilities assumed based on estimated fair values at the date of acquisition. These purchase price allocations are subject to further adjustment based on the final purchase price closing adjustments discussed above. The estimated fair values of the assets acquired, the liabilities assumed and the deferred income tax asset recognized to reflect the value of a portion of the net operating loss carryforwards the Company expected to utilize as a result of future taxable income generated by the acquisitions are summarized below (in thousands):

Working capital	$	21,122
Property, plant and equipment		166,387
Deferred income tax asset		55,600
Reclamation deposits		46,827
Other assets		31,063
Long-term debt		(3,963)
Reclamation obligations		(135,844)
Other liabilities		(18,492)
Net assets acquired	$	162,700

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The following unaudited consolidated pro forma financial information is presented for the year ended December 31, 2001 in order to provide a basis for comparative evaluation of the consolidated companies’ performance as if the acquisitions had occurred at the beginning of the periods presented. This unaudited pro forma information includes permitted adjustments to give effect to depreciation of property, plant and equipment, interest expense on acquisition-related financing, and certain other adjustments, together with related income tax effects. The unaudited pro forma information is not meant to be nor should it be relied upon as necessarily indicative of the results of operations that actually would have occurred had the acquisitions occurred at the beginning of the periods presented or of future results of the combined operations.

		Year Ended December 31, 2001
		(in thousands except per share data)
Revenues	$	335,830
Net income applicable to common shareholders	$	9,963
Net income per share applicable to common shareholders:
Basic	$	1.38
Diluted	$	1.25

Dispositions

On March 23, 2001, the Company sold its 30% interests in three Virginia independent power projects (Altavista, Hopewell and Southampton) for aggregate net proceeds of approximately $24,903,000, including $8,949,000 of operating earnings distributed from the projects at the time of the sale. A net loss of $317,000 was recorded by the Company in conjunction with this sale. The recognition of the loss, as well as an impairment charge recognized in the fourth quarter of 2000, was necessary because the service lives originally adopted for depreciation purposes for these projects were greater than the cash flow streams provided under the power supply agreements for the facilities. During the second quarter of 2001, the Company sold its 1.25% interest in the Ft. Drum independent power project for proceeds of approximately $60,000, resulting in a loss of $123,000. The proceeds from the sales were used to fund a portion of the purchase prices of the acquisitions completed during the second quarter.

3. WESTMORELAND ENERGY, LLC

Westmoreland Energy, LLC (“WELLC”), formerly Westmoreland Energy, Inc., a wholly owned subsidiary of the Company, holds general and limited partner interests in partnerships which were formed to develop and own cogeneration and other non-regulated independent power plants. Equity interests in these partnerships range from 4.49 percent to 50 percent. As of December 31, 2002 WELLC held interests in three operating projects as listed and described in the Project Summary below. As discussed in Note 2, the Company sold its interests in four independent power projects during 2001. The lenders to the remaining projects have recourse only against these projects and the income and revenues therefrom. The debt agreements contain various restrictive covenants including restrictions on making cash distributions to the partners, with which the partnerships are in compliance. The type of restrictions on making cash distributions to the partners vary from one project lender to another.

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Project	Ft. Lupton	Roanoke Valley I	Roanoke Valley II
Location:	Ft. Lupton, Colorado	Weldon, North Carolina	Weldon, North Carolina
Gross Megawatt Capacity:	290 MW	180 MW	50 MW
WELLC Equity Ownership:	4.49%	50.0%	50.0%
Electricity Purchaser:	Public Service of Colorado	Dominion Virginia Power	Dominion Virginia Power
Steam Host:	Rocky Mtn. Produce, Ltd	Patch Rubber Company	Patch Rubber Company
Fuel Type:	Natural Gas	Coal	Coal
Fuel Supplier:	Thermo Fuels, Inc.	TECO Coal/ CONSOL	TECO Coal/ CONSOL
Commercial Operation Date:	1994	1994	1995

The following is a summary of aggregated financial information for all investments owned by WELLC which are accounted for under the equity method:

Balance Sheets
December 31,		2002		2001
		(in thousands)
Assets
Current assets	$	40,282	$	40,458
Property, plant and equipment, net		255,364		264,484
Other assets		25,171		23,832
Total assets	$	320,817	$	328,774
Liabilities and equity
Current liabilities	$	29,500	$	28,213
Long-term debt and other liabilities		231,922		250,075
Equity		59,395		50,486
Total liabilities and equity	$	320,817	$	328,774
WELLC’s share of equity	$	33,407	$	28,707

Income Statements
For years ended December 31,		2002		2001		2000
		(in thousands)
Revenues	$	110,075	$	124,946	$	215,454
Operating income		46,731		72,209		94,059
Net income		28,935		33,003		69,874
WELLC’s share of earnings	$	14,506	$	15,871	$	32,260

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WELLC performs asset management services for the partnerships and has recognized related revenues of $258,000, $267,000 and $294,000 for the years ended December 31, 2002, 2001 and 2000, respectively. Management fees, net of related costs, are recorded as other income when the service is performed.

ROVA I Project - WELLC owns a 50% partnership interest in Westmoreland-LG&E Partners (the “ROVA Partnership”). The ROVA Partnership’s principal customer, Dominion Virginia Power, contracted to purchase the electricity generated by ROVA I, one of two units included in the ROVA Partnership, under a long-term contract (the “Power Purchase and Operating Agreement” or “PPOA”). From May 1994 through October 2000, that customer disputed the ROVA Partnership’s interpretation of provisions of the contract dealing with the payment of the capacity purchase price when the facility experiences a “forced outage” day. A forced outage day is a day when ROVA I is not able to generate a specified level of electrical output. The ROVA Partnership believed that the customer was required to pay the ROVA Partnership the full capacity purchase price unless forced outage days exceed a contractually stated allowed annual number. The customer asserted that it was not required to do so.

During that period, Dominion Virginia Power withheld payments during periods of forced outages. In October 2000, the ROVA partnership and Dominion Virginia Power resolved the issues regarding capacity payments during forced outages resulting in a payment to the ROVA partnership for amounts previously withheld plus accrued interest. WELLC’s share was $14,900,000. In addition to settlement of the litigation, the ROVA Partnership and Virginia Power negotiated an amendment to the PPOA which clarified the provisions of the contract governing capacity payments and provides incentives for the Partnership to keep the ROVA unit available and on-line.

Virginia Projects - On March 23, 2001, the Company sold its 30% interests in three Virginia independent power projects. WELLC’s share of earnings from these projects contributed approximately $1,286,000 and $5,287,000 in 2001 and 2000, respectively. Refer to Note 2 – Acquisitions and Dispositions for additional information.

4. INVESTMENT IN DOMINION TERMINAL ASSOCIATES (DTA)

At December 31, 2002, the Company had a 20% interest in Dominion Terminal Associates (“DTA”), a partnership formed for the construction and operation of a coal-storage and vessel-loading facility in Newport News, Virginia. DTA’s annual throughput capacity is approximately 18 million tons, and its ground storage capacity is approximately 1.4 million tons. Each partner is responsible for its share of throughput and expenses at the terminal. The Company actively marketed its 20% share of the terminal’s facilities. Accordingly, the Company’s share of losses from DTA represents the revenue received from WTC’s customers, net of the Company’s share of the expenses incurred attributable to the terminal’s coal-storage and vessel loading operations. The Company leased the terminal’s ground storage space and vessel-loading facilities to certain unaffiliated parties who are engaged in the export business and provided related support services.

The Company recognized an impairment of the full remaining book value of $3,712,000 of its investment in DTA during the third quarter of 2002. The impairment was a result of the terminal’s continuing operating losses and an agreement by one of the terminal’s other owners which disposed of its interest in DTA at a price materially less than the Company’s book value for its interest. The impairment is a non-cash charge, but the Company continued to share in cash operating expenses for the terminal until such time that alternative arrangements for the terminal’s ongoing operation could be determined, or until such time that the Company divested its investment.

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On January 29, 2003, the Company entered into a letter of intent with a subsidiary of Dominion Resources, Inc. to sell its 20% partnership interest in DTA and its industrial revenue bonds for total consideration of $10.5 million. A Purchase and Sale Agreement was executed on March 14, 2003. Under the terms of the Purchase and Sale Agreement, Westmoreland Terminal Company will guarantee throughput through the terminal for a period of three years. To secure the throughput commitment, the purchaser will deposit $6.0 million of the sale proceeds as collateral for a stand-by letter of credit for the purchaser. Westmoreland Terminal Company made certain representations about the status of its partnership interest, the industrial revenue bonds being purchased and the general condition of DTA and agreed to indemnify the purchaser for any loss incurred as a result of a breach of these representations. The liability for a breach of the representations and warranties is capped at $4.5 million. The representations and warranties will expire at various times over the next several years. Westmoreland has guaranteed Westmoreland Terminal Company’s obligations under the Purchase and Sale Agreement for a period of five years in an amount that will decline to $2.5 million after 2 1/2 years. As a result, the Company will recognize a pretax gain of approximately $4.5 million when the transaction closes. Closing is expected to take place promptly after receipt of all bank and partnership consents or following expiration of DTA partnership rights of first refusal. At closing, the purchaser will assume all of Westmoreland Terminal Company’s DTA partnership obligations. The Company will no longer incur DTA-related operating losses, which were $2,050,000, $1,922,000 and $1,800,000 in 2002, 2001 and 2000, respectively. Due to the sale of the Company’s investment, the financial results relating to DTA have been presented as Discontinued Operations. The basic and diluted loss per share from these discontinued operations was $.47, $.16 and $.18 for 2002, 2001 and 2000, respectively, prior to any impact of preferred dividend requirements.

5. LINES OF CREDIT AND LONG-TERM DEBT

The amounts outstanding at December 31, 2002 and 2001 under the Company’s lines of credit and long-term debt consist of the following:

		2002		2001
	(in thousands)
WML revolving line of credit	$	1,500	$	8,000
WML term debt		96,300		109,000
Corporate revolving line of credit		500		3,000
Other term debt		1,857		2,910
		100,157		122,910
Less current portion		(8.852)		(13,753)
	$	91,305	$	109,157

WML has a $20 million revolving credit facility (the “Facility”) with PNC Bank, National Association, as Agent, which expires on April 27, 2004. The interest rate is either PNC Bank’s Base Rate plus 1.60% or Euro-Rate plus 3.10% (4.52% at December 31, 2002), at WML’s option. In addition, a commitment fee of ½ of 1% of the average unused portion of the available credit is payable quarterly. The amount available under the Facility is based upon, and any outstanding amounts are secured by, eligible accounts receivable. At December 31, 2002, WML had additional borrowing capacity of approximately $15,000,000 under the Facility.

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WML borrowed $120 million from a group of institutions using PNC Capital Markets, Inc. as lead arranger to fund the acquisitions described in Note 2. The borrowings consisted of $20 million in variable-rate Series A Notes and $100 million in fixed-rate Series B Notes. The Series A Notes were repaid in full on June 30, 2002. The Series B Notes bear interest at a rate of 9.39% and require quarterly principal and interest payments from September 2002 to December 2008, when the remaining outstanding balance is due. The Series B Notes are secured by assets of WML.

Both the revolving line of credit and the term notes contain various covenants which limit WML or its subsidiaries’ ability to merge or consolidate with another entity, dispose of assets, pay dividends, or change the nature of business operations. WML is also required to maintain certain financial ratios as defined in the agreements. Further, pursuant to these agreements any purchase price adjustment from the Montana Power transaction which is paid to WML must be used to repay any amounts outstanding under the Facility and in certain circumstances fund a debt service reserve account. As of December 31, 2002, WML was in compliance with such covenants.

Under the terms of the Series A Notes and Series B Notes, WML is required to maintain a debt service reserve account equal to the principal and interest payments and certain fees scheduled to become due within the next six months. In addition, 25% of any “Surplus Cash Flow” (as such term is defined in the agreement for the $120 million term loan) is applied to the prepayment of WML’s indebtedness and 75% of any Surplus Cash Flow is available to WML. WML may distribute such Surplus Cash Flow to the Company so long as no Event of Default or Potential Event of Default under the term loan agreement exists or is likely to result from the distribution. The quarterly distribution is in addition to the $500,000 management fee that WML pays the Company each quarter. At December 31, 2002, WML had funded a balance of $8,497,000 in the debt service reserve account, which could be used for principal and interest payments, and $4,386,000 in the long-term prepayment account. Those funds have been classified as restricted cash in the consolidated balance sheet.

WML also assumed outstanding notes payable of the acquired entities totaling $3,963,000 at the acquisition date related to the purchase of real property and mineral rights. These notes generally require annual payments through 2009 and bear interest at approximately 6%. The total amount outstanding under these notes as of December 31, 2002 was $1,857,000.

On December 14, 2001, the Company executed an agreement with First Interstate Bank for a two-year $7 million revolving line of credit. Interest is payable monthly at the Bank’s prime rate plus 1% (5.25% at December 31, 2002). The Company is required to maintain certain financial ratios. The credit is collateralized by the Company’s stock in WRI, 100% of the common stock of Horizon, and the dragline located at WRI’s Absaloka Mine in Big Horn County, Montana. On December 14, 2002, the expiration date of this credit facility was extended to December 14, 2004. On January 24, 2003, the capacity of the facility was increased to $10 million and the expiration date further extended to January 24, 2005.

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The maturities of all long-term debt and the revolving credit facilities outstanding at December 31, 2002 are (in thousands):

2003	$	8,852
2004		11,969
2005		10,969
2006		11,470
2007		12,099
Thereafter		44,798
	$	100,157

6. WORKERS’ COMPENSATION BENEFITS

The Company was self-insured for workers’ compensation benefits prior to and through December 31, 1995. Beginning in 1996, the Company purchased third party insurance for new workers’ compensation claims. Based on updated actuarial and claims data, $449,000, $642,000 and $67,000 were charged to operations in 2002, 2001 and 2000, respectively. The cash payments for workers’ compensation benefits were $2,751,000, $2,938,000 and $3,003,000 in 2002, 2001 and 2000, respectively.

The Company was required to obtain surety bonds in connection with its self-insured workers’ compensation plan. The Company’s surety bond underwriters required collateral for such bonding. As of December 31, 2002 and 2001, $4,014,000 and $3,962,000, respectively, was held in the collateral accounts.

7. PNEUMOCONIOSIS (BLACK LUNG) BENEFITS

The Company is self-insured for federal and state pneumoconiosis benefits for current and former employees and has established an independent trust to pay these benefits.

The following table sets forth the funded status of the Company’s obligation:

December 31,		2002		2001
		(in thousands)
Actuarial present value of benefit obligation:
Expected claims from terminated employees	$	2,330	$	4,716
Claimants		20,454		18,271
Total present value of benefit obligation		22,784		22,987
Plan assets at fair value, primarily government-backed
securities		30,449		29,972
Excess of trust assets over pneumoconiosis benefit
obligation	$	7,665	$	6,985

The discount rates used in determining the accumulated pneumoconiosis benefit as of December 31, 2002 and 2001 were 6.75% and 7.25%, respectively.

In February 2000, the Company received $6,397,000 of the surplus from the trust and used the funds to pay postretirement medical expenses.

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8. POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS

Single-Employer Plans

The Company and its subsidiaries provide certain health care and life insurance benefits for retired employees and their dependents either voluntarily or as a result of the Coal Act. Substantially all of the Company’s current employees may also become eligible for these benefits if certain age and service requirements are met at the time of termination or retirement as specified in the plan agreement. The majority of these benefits are provided through self-insured programs. The Company adopted Statement of Financial Accounting Standards No. 106 –Employers’ Accounting for Postretirement Benefits Other thanPensions (SFAS 106) effective January 1, 1993 and elected to amortize its unrecognized, unfunded accumulated postretirement benefit obligation over a 20-year period.

The following table sets forth the actuarial present value of postretirement medical and life insurance benefit obligations and amounts recognized in the Company’s financial statements:

December 31,		2002		2001
		(in thousands)
Assumptions:
Discount rate		6.75%		7.25%
Change in benefit obligation:
Net benefit obligation at beginning of year	$	205,564	$	160,441
Service cost		400		227
Interest cost		14,989		12,327
Plan participant contributions		67		62
Actuarial loss		18,882		32,459
Benefit obligation assumed in acquisitions		-		13,038
Gross benefits paid		(16,424)		(12,990)
Net benefit obligation at end of year		223,478		205,564
Change in plan assets:
Employer contributions		16,357		12,928
Plan participant contributions		67		62
Gross benefits paid		(16,424)		(12,990)
Fair value of plan assets at end of year		-		-
Funded status at end of year		(223,478)		(205,564)
Unrecognized net actuarial loss		65,353		49,369
Unrecognized net transition obligation		41,002		45,102
Net amount recognized at end of year (recorded   as accrued benefit cost in the accompanying   balance sheet)	$	(117,123)	$	(111,093)

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The components of net periodic postretirement benefit cost are as follows:

Year ended December 31,		2002		2001		2000
		(in thousands)
Assumptions:
Discount rate		7.25%		7.50%		7.50%
Components of net periodic benefit cost:
Service cost	$	400	$	227	$	51
Interest cost		14,989		12,327		11,698
Amortization of:
Transition obligation		4,100		4,100		4,100
Actuarial loss		2,899		861		501
Total net periodic benefit cost	$	22,388	$	17,515	$	16,350

Of the total net periodic benefit cost of $22,388,000 in 2002 and $17,515,000 in 2001, $21,125,000 and $16,722,000, respectively, relates to the Company’s former eastern mining operations and is included in heritage health benefit costs. The remainder of $1,263,000 and $793,000, respectively, relates to current operations and is included in selling and administrative costs.

Sensitivity of retiree   welfare results (in thousands):
Effect of a one percentage point increase in   assumed health care cost trend
- - on total service and interest cost components	$	994
- - on postretirement benefit obligation	$	21,447
Effect of a one percentage point decrease in
assumed ultimate health care cost trend
- - on total service and interest cost components	$	(807)
- - on postretirement benefit obligation	$	(18,786)

Postretirement benefits include medical benefits for retirees and their spouses (and Medicare Part B reimbursement for certain retirees) and retiree life insurance.

The health care cost trend assumed on covered charges was 9.25%, 10.0% and 5.5% for 2002, 2001 and 2000, respectively, decreasing to an ultimate trend of 5.0% in 2009 and beyond. This increase in the health care cost trend assumption is reflected as an unrecognized actuarial loss in the tables above and will be recognized as expense over the remaining service lives of the covered employees.

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Multiemployer Plan

The Company makes payments to the Combined Benefit Fund (“CBF”), which is a multiemployer health plan neither controlled nor administered by the Company. The CBF is designed to pay benefits to UMWA workers (and dependents) who retired prior to 1976. Prior to February 1993, the amount paid by the Company was based on hours worked or tons processed (depending on the source of the coal) in accordance with the national contract with the UMWA. Beginning February 1993 the Company was required by the Coal Act to make monthly premium payments into the CBF. These payments were based on the number of beneficiaries assigned to the Company, the Company’s UMWA employees who retired prior to 1976 and the Company’s pro-rata assigned share of UMWA retirees whose companies are no longer in business. The net present value of the Company’s future cash payments is estimated to be approximately $38,823,000 at December 31, 2002. The Company expenses payments to the CBF when they are due. Payments are generally made on the due date. Payments in 2002, 2001 and 2000 were $5,205,000, $5,659,000 and $5,349,000, respectively.

9. RETIREMENT PLANS

Defined Benefit Pension Plans

The Company provides defined benefit pension plans for its full-time employees. Benefits are generally based on years of service and the employee’s average annual compensation for the highest five continuous years of employment as specified in the plan agreement. The Company’s funding policy is to contribute annually the minimum amount prescribed, as specified by applicable regulations. Prior service costs and actuarial gains and losses are amortized over plan participants’ expected future period of service using the straight-line method.

Supplemental Executive Retirement Plan

Effective January 1, 1992, the Company adopted the Westmoreland Coal Company Supplemental Executive Retirement Plan (“SERP”). The SERP is an unfunded non-qualified deferred compensation plan which provides benefits to certain employees that are not eligible under the Company’s defined benefit pension plan beyond the maximum limits imposed by the Employee Retirement Income Security Act (“ERISA”) and the Internal Revenue Code.

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The following table provides a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the periods ended December 31, 2002 and 2001 and the amounts recognized in the Company’s financial statements for both the defined benefit pension and SERP Plans:

		Qualified Pension Benefits				SERP Benefits
December 31,		2002		2001		2002		2001
		(in thousands)
Assumptions:
Discount rate		6.75%		7.25%		6.75%		7.25%
Expected return on plan assets		9.00%		9.00%		9.00%		9.00%
Rate of compensation increase		4.50%		4.50%		5.00%		5.00%
Change in benefit obligation:
Net benefit obligation at beginning of year	$	33,544	$	1,422	$	1,503	$	1,337
Service cost		1,943		1,238		76		52
Interest cost		2,556		1,551		170		105
Actuarial loss		3,513		1,686		953		85
Benefit obligations assumed in acquisitions		-		27,876		-		-
Gross benefits paid		(190)		(229)		(76)		(76)
Net benefit obligation at end of year		41,366		33,544		2,626		1,503
Change in plan assets:
Fair value of plan assets at beginning of year		33,593		5,892		-		-
Actual return on plan assets		(3,334)		(1,265)		-		-
Employer contributions		78		-		76		76
Transfer of assets from plans assumed in   acquisitions		-		29,195		-		-
Gross benefits paid		(190)		(229)		(76)		(76)
Fair value of plan assets at end of year		30,147		33,593		-		-
Funded status at end of year		(11,219)		49		(2,626)		(1,503)
Unrecognized net actuarial (gain) loss		14,271		4,655		532		(478)
Unrecognized prior service cost		154		96		74		229
Unrecognized net transition asset		(10)		(17)		-		-
Net amount recognized at end of year		3,196		4,783		(2,020)		(1,752)
Amounts recognized in the accompanying balance sheet consist of:
Prepaid benefit cost		3,196		4,783		-		-
Minimum pension liability		(5,517)		-		-		-
Accrued benefit cost		-		-		(2,020)		(1,752)
Net amount recognized at end of year	$	(2,321)	$	4,783	$	(2,020)	$	(1,752)

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The components of net periodic pension cost (benefit) are as follows:

		Qualified Pension Benefits						SERP Benefits
Year ended December 31,		2002		2001		2000		2002		2001		2000
		(in thousands)
Assumptions:
Discount rate		7.25%		7.50%		7.50%		7.25%		7.50%		7.50%
Expected return on plan assets		9.00%		9.00%		9.00%		N/A		N/A		N/A
Rate of compensation increase		4.50%		4.50%		5.00%		5.00%		5.00%		5.00%
Components of net periodic benefit cost
Service cost	$	1,943	$	1,238	$	141	$	76	$	52	$	54
Interest cost		2,556		1,551		98		170		105		93
Expected return on assets		(2,975)		(2,275)		(492)		-		-		-
Amortization of:
Transition asset		(6)		(6)		(6)		-		-		-
Prior service cost		50		42		42		76		116		116
Actuarial (gain) loss		97		-		(4)		22		(40)		(86)
Total net periodic pension cost (benefit)	$	1,665	$	550	$	(221)	$	344	$	233	$	177

1974 UMWA Pension Plan

The Company was required under the 1993 Wage Agreement to pay amounts based on hours worked or tons processed (depending on the source of the coal) in the form of contributions to the 1974 UMWA Pension Plan with respect to UMWA represented employees. The 1974 UMWA Pension Plan is neither controlled nor administered by the Company.

Under the Multiemployer Pension Plan Act (“MPPA”), a company contributing to a multiemployer plan is liable for its share of unfunded vested liabilities upon withdrawal from the plan. In connection with the cessation of eastern mining operations, its only operations at that time which utilized UMWA employees, the Company recorded an estimate of the liability the Company would incur upon withdrawal from the 1974 UMWA Pension plan. The actuarial estimate of this obligation was estimated by the 1974 UMWA Pension Plan at $13,800,000 in 1996. The 1974 UMWA Pension Plan has not provided the Company with an updated actuarial estimate of the withdrawal liability calculated as of June 30, 1998, the date of the asset valuation the Company believes should be used to determine the actual withdrawal liability, in accordance with the provisions of MPPA. The Company believes the liability at June 30, 1998 would be substantially less than $13,800,000 and is contesting the withdrawal liability through arbitration. In accordance with MPAA, the Company must amortize this withdrawal liability, with interest, during the arbitration process by making payments of approximately $172,500 per month. These payments have been made and will be recoverable to the extent the final assessed amount is less than the amounts paid. Should the Company be unsuccessful in the arbitration proceedings, it will be obligated to continue to make payments through March 2008. Of the $13,800,000 recorded in 1996, $8,035,000 remains outstanding as of December 31, 2002.

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10. INCOME TAXES (BENEFIT)

Income tax expense (benefit) attributable to income (loss) before income taxes consists of:

		2002		2001		2000
		(in thousands)
Current:
Federal	$	-	$	-	$	(599)
State		900		908		162
		900		908		(437)
Deferred:
Federal		(5,605)		(120)		-
State		(51)		(352)		-
		(5,656)		(472)		-
Income tax expense (benefit)	$	(4,756)	$	436	$	(437)

Income tax expense (benefit) attributable to income (loss) before income taxes differed from the amounts computed by applying the statutory Federal income tax rate of 34% to pretax income (loss) from continuing operations as a result of the following:

		2002		2001		2000
		(in thousands)
Computed tax expense (benefit) at statutory rate	$	1,825	$	1,925	$	(44)
Increase (decrease) in tax expense resulting from:
Tax depletion in excess of book		(3,399)		(2,412)		(563)
Minority interest adjustment		272		265		176
State income taxes, net of increase in      valuation allowance of $5,453		720		842		106
Change in valuation allowance
relating to Federal income taxes		(4,149)		-		11
Other, net		(25)		(184)		(123)
Income tax expense (benefit)	$	(4,756)	$	436	$	(437)

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The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2002 and 2001 are presented below:

		2002		2001
Deferred tax assets:		(in thousands)
Federal net operating loss carryforwards	$	58,874	$	61,633
State net operating loss carryforwards		6,035		1,220
Alternative minimum tax credit carryforwards		2,608		2,608
Accruals for the following:
Workers' compensation		4,296		5,216
Postretirement benefit and pension obligations		43,336		37,724
Reclamation costs		7,532		3,360
1974 UMWA pension plan obligation		3,214		3,764
Other accruals		4,722		2,877
Total gross deferred assets		130,617		118,402
Less valuation allowance		(32,574)		(31,270)
Net deferred tax assets		98,043		87,132
Deferred tax liabilities:
Investment in independent power projects	$	(14,964)	$	(13,769)
Plant and equipment, differences due to depreciation and   amortization		(14,929)		(13,508)
Excess of trust assets over pneumoconiosis benefit obligation		(3,066)		(2,794)
Total gross deferred tax liabilities		(32,959)		(30,071)
Net deferred tax asset	$	65,084	$	57,061

The net deferred tax asset is presented on the consolidated balance sheets at December 31, as follows:

		2002		2001
	(in thousands)
Deferred income tax assets – current	$	15,831	$	15,859
Deferred income tax assets – long-term		49,253		41,202
	$	65,084	$	57,061

An income tax benefit of $160,000 and $989,000 related to the exercise of stock options during 2002 and 2001, respectively, was added to other paid-in capital.

Based on estimated taxable income generated during 2002, the Company expects to have used approximately $6,841,000 of its Federal net operating loss carryforwards. As of December 31, 2002, a minimum of $174,000,000 of future taxable income will be necessary to enable the Company to fully utilize the net operating loss carryforwards and realize gross deferred tax assets of $130,617,000. As of December 31, 2002, the Company has available Federal net operating loss carryforwards to reduce future taxable income which expire as follows:

Expiration Date		Regular Tax
(in thousands)
2010	$	48,212
2011		36,479
2012		449
2018		532
after 2018		88,493
Total	$	174,165

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The Company has alternative minimum tax credit carryforwards of $2,608,000 which are available indefinitely to offset future Federal taxes payable. For Alternative Minimum Tax purposes, the Company has net operating loss carryforwards of approximately $53,750,000 as of December 31, 2002. The Federal Alternative Minimum Tax regulations were recently changed to allow 100% utilization of net operating loss carryforwards in 2001 and 2002. As of December 31, 2002, the Company also has available an estimated $12,592,000 in net operating loss carryforwards in Colorado to reduce future taxable income.

11. CAPITAL STOCK

Preferred stock dividends at a rate of 8.5% per annum were paid quarterly from the third quarter of 1992 through the first quarter of 1994. The declaration and payment of preferred stock dividends was suspended in the second quarter of 1994 in connection with extension agreements with the Company’s principal lenders. Upon the expiration of these extension agreements, the Company paid a quarterly dividend on April 1, 1995 and July 1, 1995. Pursuant to the requirements of Delaware law, described below, the preferred stock dividend was suspended in the third quarter of 1995 as a result of recognition of losses and the subsequent shareholders’ deficit. Dividends of $0.60 per preferred share, or $0.15 per depositary share were then paid on October 1, 2002 and January 1, 2003. The quarterly dividends which are accumulated but unpaid through and including January 1, 2003 amount to $14,256,000 in the aggregate ($68.93 per preferred share or $17.23 per depositary share). Common stock dividends may not be declared until the preferred stock dividends that are accumulated but unpaid are made current.

During 2002, the Company purchased 7,500 depositary shares, or 1,875 preferred shares, for $244,000. This reduced the number of preferred shares outstanding to 206,833 and the ongoing quarterly preferred dividend requirement to $440,000. The depositary shares purchased were converted into shares of Series A Preferred Stock and retired.

There are statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which the Company is incorporated. Under Delaware law, the Company is permitted to pay preferred stock dividends only: (1) out of surplus, surplus being the amount of shareholders’ equity in excess of the par value of the Company’s two classes of stock; or (2) in the event there is no surplus, out of net profits for the fiscal year in which a preferred stock dividend is declared (and/or out of net profits from the preceding fiscal year), but only to the extent that shareholders’ equity exceeds the par value of the preferred stock (which par value was $208,708 at December 31, 2001). The Company had shareholders’ equity at December 31, 2002 of $18,568,000 and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $19,485,000 at December 31, 2002.

Shareholder Rights Plan

On February 7, 2003, the Company adopted an amended and restated shareholder rights plan.  Each right entitles the holder to buy one one-hundredth of a share of Series B Junior Participating Preferred Stock, par value $1.00 per share, of the Company at a price of $50.00 per one one-hundredth of a Preferred Share in certain circumstances.  In general, the rights are exercisable only if a person or group acquires 20% or more of the Company’s Common Stock or Voting Stock (an “Acquiring Person”) or announces a tender or exchange offer the consummation of which would result in ownership by a person or group of 20% or more of the Company’s Common Stock or Voting Stock (the date on which the rights become exercisable, the “Distribution Date”).  In general, the rights are not exercisable until the Distribution Date and are not exercisable by an Acquiring Person.  The rights will expire on February 7, 2013, subject to earlier redemption or exchange by the Company as described in the plan.   A copy of the amended and restated rights plan has been filed with the Securities and Exchange Commission as an exhibit to a Current Report on Form 8-K dated February 7, 2003. This summary of the rights plan does not purport to be complete and is qualified in its entirety by reference to the plan.

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12. INCENTIVE STOCK OPTION AND STOCK APPRECIATION RIGHTS PLANS

As of December 31, 2002, the Company had options outstanding from four shareholder-approved Incentive Stock Option (“ISOs”) Plans for employees and three Incentive Stock Option Plans for directors.

The 1985 employee Plan provides for the granting of ISOs and stock appreciation rights and the 1995, 2000 and 2002 employee Plans provide for the granting of ISOs and restricted stock. The 1985, 1995, 2000 and 2002 Plans also provide for the grant of non-qualified options, if so designated, and contain the terms specified for non-qualified options. Restricted stock is an award payable in shares of common stock subject to forfeiture under certain conditions. ISOs granted under the 1985, 1995, 2000 and 2002 Plans generally vest over two years and expire ten years from the date of grant and may not have an option price that is less than the fair market value of the stock on the date of grant. The maximum number of shares of the Company’s common stock that could be issued or granted under the 1985, 1995, 2000 and 2002 Plans is 400,000, 350,000, 350,000 and 450,000, respectively.

The 1985 Plan expired on January 7, 1995. Therefore, no further grants may now be made from this plan. As of December 31, 2002, the 1995, 2000 and 2002 Plans have 0, 24,200 and 346,400, respectively, shares available for future issue or grant.

The 1991 Non-Qualified Stock Option Plan for Non-Employee Directors provided for the granting on September 1 of each year of options to purchase 1,500 shares of the Company’s common stock. The maximum number of shares of the Company’s common stock that may be issued pursuant to options granted under the plan was 200,000 shares. This plan expired in 2001 with 141,500 shares unissued. Options granted pursuant to this plan expire ten years after the date of grant and vest after the completion of one year of board service following the date of grant. Grants under this plan were suspended in 1996 and resumed upon the Company’s dismissal from bankruptcy.

In 1996, the shareholders approved the 1996 Directors’ Stock Incentive Plan. The plan provides for the grant of non-qualified stock options to directors on an annual basis beginning on the date of the 1996 Annual Meeting with options for 20,000 shares to be granted to each director on that date or after a director is first elected or appointed, and options for 10,000 shares to be granted to each director after each annual meeting thereafter. The maximum number of shares of the Company’s common stock that may be issued or granted under the plan is 350,000 (none are available as of December 31, 2002) and the options expire no later than ten years after the date of grant. Options granted pursuant to this plan vest 25% per year over a four-year period. Options granted during a director’s period of active service continue to vest pursuant to this schedule if a director leaves the board due to reaching retirement age. In the event of a change of control of the Company, any option that was not previously exercisable and vested will become fully exercisable and vested.

In 2000, the Board of Directors adopted the 2000 Nonemployee Directors’ Stock Incentive Plan, and as permitted by applicable American Stock Exchange rules, did not seek shareholder approval of this plan. Like the 1996 Directors’ Plan, options for 20,000 shares are granted to each director when first elected or appointed, and options for 10,000 shares are granted after each annual meeting thereafter. The maximum number of shares that may be issued under the plan and the vesting, expiration and acceleration upon change-of-control provisions are the same as the 1996 Directors’ Plan. As of December 31, 2002, there are 80,000 shares available under this plan for future issue or grant.

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Information for 2002, 2001 and 2000 with respect to both the employee and director Plans is as follows:

	Issue Price Range	Stock Option Shares	Weighted Average Exercise Price
Outstanding at December 31, 1999	$  2.63-20.00	774,000	$  4.76
Granted in 2000	2.81-7.94	477,800	3.43
Exercised in 2000	2.63	(2,000)	2.63
Expired or forfeited in 2000	14.28	(75,000)	14.28
Outstanding at December 31, 2000	2.63-20.00	1,174,800	3.64
Granted in 2001	12.04-8.19	135,500	17.58
Exercised in 2001	2.81-8.75	(371,450)	3.99
Expired or forfeited in 2001	2.63-20.00	(56,500)	5.53
Outstanding at December 31, 2001	2.63-18.19	882,350	5.51
Granted in 2002	12.86-15.31	183,600	13.93
Exercised in 2002	2.63-12.38	(77,900)	4.28
Outstanding at December 31, 2002	$  2.63-18.19	988,050	$  7.17

Information about stock options outstanding as of December 31, 2002 is as follows:

Range of Exercise Price	Number Outstanding	Weighted- Average Remaining Contractual Life (Years)	Weighted- Average Exercise Price	Number Exercisable	Weighted- Average Exercise Price
$2.63-5.00	628,950	5.9	$2.94	576,450	$2.93
5.01-10.00	40,000	7.9	7.41	20,000	7.41
10.01-15.00	114,835	9.4	12.79	5,617	12.21
15.01-18.19	204,265	8.8	16.98	42,127	18.07
$2.63-18.19	988,050	7.0	$7.17	644,194	$4.14

13. BUSINESS SEGMENT INFORMATION

The Company’s operations have been classified into two segments: coal and independent power operations. The coal segment includes the production and sale of coal from Eastern Montana, North Dakota and Texas. The independent power operations include the ownership of interests in cogeneration and other non-regulated independent power plants. The “Corporate” classification noted in the tables represents all costs not otherwise classified, including corporate office charges, heritage health benefit costs, business development expenses and all residual costs of the idled Virginia Division. Summarized financial information by segment for 2002, 2001 and 2000 is as follows:

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Year ended December 31, 2002

		Coal		Independent Power		Corporate		Total
		(in thousands)
Revenues:
Coal revenue	$	301,235	$	-	$	-	$	301,235
Equity in earnings		-		14,506		-		14,506
		301,235		14,506		-		315,741
Costs and expenses:
Cost of sales - coal		226,707		-		-		226,707
Depreciation, depletion, and   amortization		11,430		13		96		11,539
Selling and administrative		23,058		939		8,251		32,248
Heritage health benefit costs		-		-		26,921		26,921
Doubtful account recoveries		(516)		-		-		(516)
Loss on sales of assets		9		-		-		9
Operating income (loss)   from continuing operations	$	40,547	$	13,554	$	(35,268)	$	18,833
Capital expenditures	$	7,196	$	45	$	82	$	7,323
Property, plant and equipment (net)	$	188,154	$	69	$	1,309	$	189,532

Year ended December 31, 2001

		Coal		Independent Power		Corporate		Total
		(in thousands)
Revenues:
Coal revenue	$	231,048	$	-	$	-	$	231,048
Equity in earnings		-		15,871		-		15,871
		231,048		15,871		-		246,919
Costs and expenses:
Cost of sales - coal		177,304		-		-		177,304
Depreciation, depletion, and   amortization		9,124		11		30		9,165
Selling and administrative		13,184		376		9,511		23,071
Heritage health benefit costs		-		-		23,773		23,773
Doubtful account recoveries		(428)		-		(18)		(446)
Loss on sales of assets		-		440		-		440
Operating income (loss)   from continuing operations	$	31,864	$	15,044	$	(33,296)	$	13,612
Capital expenditures	$	5,388	$	4	$	41	$	5,433
Property, plant and equipment (net)	$	195,968	$	45	$	1,258	$	197,271

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Year ended December 31, 2000

		Coal		Independent Power		Corporate		Total
		(in thousands)
Revenues:
Coal revenue	$	35,137	$	-	$	-	$	35,137
Equity in earnings		-		32,260		-		32,260
		35,137		32,260		-		67,397
Costs and expenses:
Cost of sales - coal		30,250		-		-		30,250
Depreciation, depletion, and
amortization		1,847		29		96		1,972
Selling and administrative		900		456		5,483		6,839
Heritage health benefit costs		-		-		21,503		21,503
Doubtful account recoveries		-		-		(400)		(400)
Impairment charges		-		4,632		-		4,632
Loss (gain) on sales of assets		-		(2)		8		6
Operating income (loss)   from continuing operations	$	2,140	$	27,145	$	(26,690)	$	2,595
Capital expenditures	$	621	$	10	$	16	$	647
Property, plant and equipment (net)	$	34,587	$	60	$	46	$	34,693

The Company derives its coal revenues from a few key customers. The customers from which more than 10% of total revenue has been derived and the percentage of total revenue is summarized as follows:

	2002	2001	2000
	(in thousands)
Customer A	$ 119,658	$ 92,626	$          -
Customer B	64,007	46,104	-
Percentage of total revenue	58%	56%	0%

14. COMMITMENTS AND CONTINGENCIES

Protection of the Environment

As of December 31, 2002 the Company has reclamation bonds in place in Montana, North Dakota, Texas, and Virginia, to assure that all currently permitted operations comply with all applicable Federal and State regulations and to assure the completion of final reclamation activities. The amount of the Company’s bonds exceeds the amount of its estimated final reclamation obligations. The Company estimates that the cost of final reclamation for its mines will total approximately $235,271,000 and that the Company will be responsible for paying approximately $185,547,000 of this amount.

As of December 31, 2002, $138,898,000 of the Company’s obligation has been accrued and WML had $49,484,000 of cash reserved and invested to use for future reclamation activities at the Rosebud Mine.

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At NWR and WECO, both subsidiaries of WML, certain customers, and at Westmoreland Resources, Inc. (“WRI”), the contract miner, are contractually obligated to either perform or reimburse the Company for reclamation activities as they are performed at the respective operations. Final reclamation obligations at NWR’s Jewett Mine, estimated at approximately $30,000,000, are contractually the responsibility of its customer which also has a corporate guarantee posted with the Texas Railroad Commission to assure performance of final reclamation.

At WECO’s Rosebud Mine, one of the customers is responsible for an additional estimated final reclamation cost of $12,300,000. By contract with its mining contractor and 20% owner, Washington Group International, Inc. (“WGI”), WRI’s maximum liability for reclamation costs associated with final mine closure of the Absaloka Mine is limited to approximately $1,700,000, which amount is being prefunded through annual installment payments to WGI of $113,000 through 2005. Remaining liability for backfilling, regrading and seeding at WRI’s Absaloka Mine is the responsibility of WGI. Pursuant to the terms of the settlement agreement described below, WGI has established a reclamation escrow account into which 6.5% of every contract mining payment made by WRI to WGI is deposited. This reclamation escrow account serves a security for WGI’s satisfactory performance of its contractually required reclamation activities.

Upon WGI’s completion of its reclamation responsibilities, WRI will be responsible for site maintenance and monitoring until final bond release. WRI has posted a surety bond with the State of Montana to ensure that final reclamation activities are performed. Certain provisions of a settlement with WGI of various issues, described below, provides WRI additional security that the mining contractor will meet these obligations.

The Company believes its mining operations are in compliance with applicable federal, state and local environmental laws and regulations, including those relating to surface mining and reclamation, and it is the policy of the Company to operate in compliance with such standards. The Company maintains compliance primarily through the performance of contemporaneous reclamation, and maintenance and monitoring activities.

WGI Settlement

During 2001, WRI’s mining contractor and 20% owner, WGI, filed a petition seeking to reorganize its debts pursuant to Chapter 11 of the Bankruptcy Code. Prior to the time the bankruptcy petition was filed, WRI had filed suit against WGI in the U.S. District Court of Montana seeking to recover costs associated with the repair and replacement of components of WRI’s dragline. WGI’s bankruptcy petition stayed that litigation. WRI filed other claims in the bankruptcy court against WGI; these claims alleged, among other things, that WGI overcharged for the cost of mining, failed to provide a competitive cost of mining, and failed to provide adequate assurances that contractually required reclamation would be done. WRI also requested assurances of reimbursement from WGI for a portion of unpaid royalties claimed due by the MMS and for which WGI would be responsible as a result of its equity ownership and pursuant to certain contract obligations. WRI also objected to assumption of the mining contracts by WGI under which WGI provided contract mining and reclamation services to WRI.

On October 4, 2002, the parties reached an agreement that settled all the pending claims and on December 10, 2002 the bankruptcy court presiding over WGI’s reorganization approved that agreement. The parties agreed to a price per ton for all coal to be mined from the currently permitted mine area which is significantly lower than the price WGI previously charged or than the price WGI had requested for future mining.

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WGI will also provide a proposed mining price for all remaining currently leased but unpermitted acreage by December 31, 2003. If the parties do not agree on a price for those tons, there will be a period of negotiation, followed by non-binding mediation and then, if necessary, binding arbitration before a neutral three member panel of coal industry experts. The arbitration panel’s decision on any price dispute will be based on how a prudent contract miner would mine the Absaloka reserves, taking into consideration reasonable costs to economically and efficiently produce and deliver the coal on a stand alone basis (based on current lease holdings) and in the alternative, in conjunction with any additional leased acreage, if available, plus a reasonable profit.

Claims for past overcharges were settled with WRI retaining $840,000 of previously withheld amounts and adoption of the new agreed-upon mining price beginning as of October 1, 2002. The total payment withheld by WRI had been approximately $1,120,000, including $560,000 held in an escrow account.

To settle the dispute over the dragline repair and replacement, WGI paid WRI $3.6 million and WRI waived any claim to interest. This settlement is without prejudice to either party’s position regarding the obligation to repair, maintain and replace components of the dragline.

WRI and WGI reserved the question of liability for additional royalties allegedly owed to MMS until the amount of the royalty is finally determined.

Finally, WGI agreed to establish a reclamation escrow account to secure its contractual obligations to perform reclamation. WRI will place 6.5% of each payment for mining services to WGI in the escrow until either the account is fully funded to the amount of the then current estimate of WGI’s reclamation obligation or until WGI posts an irrevocable letter of credit or comparable security acceptable to WRI. WGI’s reclamation obligation will vary over time and may increase or decrease depending on conditions at the Absaloka Mine. It is currently estimated to be $7,884,000. WGI’s failure to comply with certain financial ratios will require WGI to fully fund the reclamation escrow immediately or post an irrevocable letter of credit satisfactory to WRI. The failure to fund the reclamation escrow within 30 days gives WRI the right to withhold all payments to WGI and pay those sums into the reclamation escrow and after six months could result in termination of all mining agreements between WRI and WGI.

Contract Contingencies

On August 2, 1999, NWR, as part of a settlement of then pending litigation, entered into an Amended Lignite Supply Agreement with Reliant (now CNP), for its Limestone Electric Generating Station. CNP has notified NWR that it has assigned the ALSA to TGN, a subsidiary. The ALSA provided for a transition from the cost plus pricing mechanism of the original lignite supply agreement to a market-based pricing mechanism under the ALSA effective July 1, 2002. The market-based pricing mechanism is an annual determination of the equivalent cost of purchasing, delivering, and consuming Powder River Basin (“PRB”) coal from Wyoming at LEGS, subject to a minimum and a maximum price set forth under the ALSA. The ALSA provides that the price be redetermined annually and that annual volumes be committed eighteen months prior to the start of each calendar year’s shipments. If TGN proposes to purchase PRB coal above the amount committed to, NWR has the right of first refusal to meet the equivalent PRB price and supply lignite instead. In no event may TGN procure PRB coal for LEGS, either in addition to or in place of the committed volumes, unless NWR declines to match the equivalent price of PRB coal and deliver lignite.

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In accordance with the ALSA, the parties agreed in June 2000 to lignite volumes for the period July 2002 through December 2003. The ALSA also called for the PRB equivalent price for 2002 (July through December) and the 2004 annual commitment volume to have been determined by the end of June 2002. However, TGN asserted that certain cost effects associated with the uprating of at least one of its two LEGS generating units and with its strategy to comply with new Texas nitrogen oxide (“NO_x”) emission regulations (which take effect May 1, 2003) should be included in the calculation of the PRB equivalent price. When the parties were unable to agree on the pricing mechanism, NWR filed for a declaratory judgment in Limestone County, Texas, against TGN (then Reliant) in December 2001. NWR claimed that the uprating and NO_x compliance costs should not be included in or otherwise affect the calculation of the PRB equivalent price. NWR also claimed that it is necessary to resolve NWR and TGN’s competing claims before the PRB equivalent price could be calculated.

Subsequently, NWR and TGN (then Reliant) agreed to stay this litigation and resolved these issues for 2002 and 2003 by entering into an interim agreement on June 18, 2002 that (1) set firm pricing and volumes from July 1, 2002 through December 31, 2003; (2) provided TGN flexibility to test blends of PRB coal for NO_Xcompliance in 2002; (3) obligated TGN to make best efforts to achieve a lignite-to-PRB blend that achieves NOX compliance using a minimum of 7 million tons per year of lignite; (4) obligated TGN to share its test results and allowed NWR to observe the tests; (5) postponed the commitment of lignite volumes for 2004 until early in 2003; (6) stayed all related litigation until February 28, 2003 (the parties have since extended this date to March 31, 2003); and (7) required the parties to make good faith efforts to select a standing arbitrator as required under the ALSA.

In the course of testing blends of PRB coal for NO_x compliance during the second half of 2002, TGN failed to take delivery of the full lignite volumes agreed upon in the June 18, 2002 letter agreement. NWR has subsequently informed TGN that it expects to be compensated as provided under the June 18, 2002 interim agreement for shortfall volumes. TGN claims NWR was unable to deliver these amounts. In addition, TGN has procured certain amounts of PRB coal above the agreed upon volume of 750,000 tons without first offering a right of first refusal to NWR. NWR has informed TGN that it would be entitled to damages for this breach. NWR has asserted that it is not in breach until it uses any such coal. Finally, TGN believes and has requested that NWR should pay royalties on lignite produced since July 1, 2002 from NWR mineral leases with TGN. NWR disputes its obligation to pay these royalties.

NWR and TGN have been meeting in an attempt to settle all of the issues above and to agree upon prices and volumes for 2004 and 2005 or longer. As with any dispute, the outcome is uncertain; however, the Company believes that the ultimate resolution of this dispute will not have a material adverse effect on its financial condition or results of operations.

WECO’s Coal Supply Agreement with the Colstrip Units 1 and 2 owners (the “1 and 2 Owners”) contains a provision which called for the price to be reopened on the contract’s thirtieth anniversary, which was July 2001, and gave the parties six months to negotiate a new delivered price for coal. If the parties are unable to agree on a new price, the issue is submitted to binding arbitration. WECO and the owners of Units 1 and 2 have been negotiating since July 2001 in an attempt to reach an agreement for the price of coal through contract expiration in 2009. The deadline provided in the contract for arbitration was extended through June 2002 in connection with the ongoing efforts to agree on a new price. After more than a year had passed, WECO sent the 1 and 2 Owners an arbitration demand on September 3, 2002. Proceedings are anticipated to take place during the summer of 2003. While WECO believes it is due a price increase, as with any arbitration, the outcome is uncertain.

98

UMWA Master Agreement

The Company is subject to certain financial ratio tests under the terms of an agreement with the UMWA Health and Retirement Funds (the “Master Agreement”), which facilitated the Company’s discharge from Chapter 11 Bankruptcy in 1998. The Company’s obligations under the Master Agreement are secured by a Contingent Promissory Note (the “Note”) in an initial principal amount of $12 million; the principal amount of the Note decreased to $6 million in 2002. The Note is payable only in the event the Company does not meet its Coal Act obligations, fails to meet certain ongoing financial ratio tests specified in the Note or fails to comply with certain covenants set forth in a security agreement. The Company was required to collateralize its obligations under the Note for the first three years in part by posting $6 million cash in an escrow account. The $6 million collateral was returned to the Company on May 1, 2002. The cash flows of the ROVA project, or at the Company’s discretion a letter of credit or surety bond, secure the Company’s performance through 2004. The Note also gives the Company certain rights to cure a default that would otherwise ripen into an “Event of Default.” On no more than one occasion through the remaining term of the Note, the Company may cure a default that arises from the Company’s failure to satisfy the financial ratios in a quarter by complying with the financial ratios in the immediately following quarter. The Note terminates on January 1, 2005. The Company is in compliance as of December 31, 2002 and believes it will comply with the financial ratios in the Note through its expiration.

Purchase Price Adjustment

As discussed in Note 2, the final purchase price for the acquisition of Montana Power’s coal business is subject to adjustment pursuant to the terms of the Purchase Agreement between the Company and Entech. Pursuant to the terms of the Stock Purchase Agreement (the “Stock Purchase Agreement”) between Entech, a subsidiary of Montana Power, and WCC, certain adjustments to the purchase price were to be made as of the date the transaction closed to reflect the net assets of the acquired operations on the closing date and the net revenues that those operations had earned between January 1, 2001 and the closing date. The Stock Purchase Agreement gave the seller 60 days after the transaction closed to provide WCC a certificate setting forth the seller’s calculation of the net assets of the entities that the Company was acquiring and the net revenues of those entities through the closing date. Westmoreland then had 30 days to agree or object to the seller’s certificate. Entech submitted a certificate that would have increased the purchase price by approximately $9 million. The Company submitted its own adjustments which would result in a substantial decrease in the original purchase price and objected to Entech’s certificate. Under the Stock Purchase Agreement, the parties had 15 days from the submission of the Company’s certificate and objection to the seller’s certificate to resolve their differences. If the companies could not reach agreement within that period, the Stock Purchase Agreement requires that their disagreements be submitted to an independent accountant for resolution. The parties have not been able to agree on either the amount of the purchase price adjustment or the methodology to calculate the adjustment, and Entech refused to refer the matter to the independent accountant. Consequently, on November 26, 2001, Westmoreland initiated an action in the Supreme Court of New York seeking specific performance of the purchase price adjustment methodology in the Stock Purchase Agreement. The Supreme Court of New York agreed with Westmoreland and ordered Entech to comply with the purchase price adjustment methodology in the Stock Purchase Agreement. Entech appealed the Court’s decision and sought to enjoin the use of the independent accountant until its appeal was heard. A temporary stay was granted pending a hearing before the full Appellate Division of the Supreme Court of New York. On March 19, 2002, the Appellate Division denied Entech’s request to continue the stay pending completion of Entech’s appeal and dissolved the temporary stay. The Appellate Division sustained the Supreme Court decision on July 5, 2002. Entech appealed both the Supreme Court decision and Appellate Division ruling to the New York Court of Appeals. Argument is set for April 29, 2003. In the interim, attempts to negotiate an acceptable engagement letter allowing the independent accountant to proceed have not been successful, however discussions continue. In addition, Westmoreland has attempted to enforce the lower court rulings through a contempt proceeding; however, the trial court has declined to act pending the results of the appeal. Although there can be no assurance as to the ultimate outcome, the Company denies Entech’s claims, believes its own claims are meritorious, and intends to pursue its rights vigorously.

99

Royalty Claims

WECO has received demand letters dated September 23, 2002 and September 24, 2002 from the Montana Department of Revenue (“DOR”), as agent for the MMS, asserting underpayment of certain royalties. DOR contends that royalty payments are due on the fees WECO receives to transport coal from the contract delivery point to the customer. DOR has claimed that approximately $3.2 million is due in respect of this claim. Secondly, DOR has alleged that royalties are also due for certain “take or pay” payments WECO received when its customers did not require coal. DOR has alleged that approximately $1.8 million is due in respect of this claim. WECO has appealed the DOR/MMS determinations and WECO believes that MMS is wrongly asserting claims for royalties on transportation and the take or pay payments. The appeal process will take several years.

Tax Assessments

WELLC’s ROVA projects are located in Halifax County, North Carolina and are the County’s largest taxpayer. Halifax County hired Tax Management Associates, Inc. (“TMA”) to review and audit the property tax returns for the past five years. TMA retains a percentage of any additional tax they cause to be paid to the County. In May 2002, the ROVA project was advised that its returns were being scrutinized for potential underpayment due to undervaluation of property subject to tax. When ROVA was being built, the partnership met with the Halifax tax authorities and agreed how the project would be taxed. The County was reminded of the prior discussions and agreement, however, the County declined to stop the process. The project management met with County officials and TMA on September 20, 2002. In late October 2002, the project received notice of an additional assessment of $4.6 million for the years 1994 to 2002. If upheld, the project’s future taxes would increase approximately $800,000 per year. The Company owns a 50% interest in the project. The project partnership will contest the assessment and has filed a protest to the additional assessment and believes the change in assessment methodology and values after the prior agreement is unfounded.

The Montana Department of Revenue has reviewed the Company’s income tax returns for 1998 and 1999 and notified the Company in 2002 that it has disallowed the exclusion of a gain on the 1999 sale of the Rensselaer Project Partnership’s primary asset, the Power Purchase and Supply Agreement with Niagra Mohawk Power Corporation (“NIMO”). In 1997, the New York Public Service Commission in an attempt to substantially reduce the economic burden of existing contracts between NIMO and the various independent power producers approved NIMO’s plan to terminate or restructure its 29 independent power project contracts. The Company’s Rensselaer project was terminated. The Company is objecting to the assessment. If the State’s assessment is upheld, the Company would owe interest of $57,000 to the State of Montana from 1998 and fully use up its Montana net operating loss carryforwards in 2002.

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A similar inquiry on the same issue was made by the State of North Carolina. On February 11, 2003, the North Carolina Department of Revenue notified the Company that it also had disallowed the exclusion of gain on the compelled sale of the Rensselaer Project’s partnership’s Power Purchase and Supply Agreement. The Company could owe a current tax of $3.5 million plus interest of $1.0 million and penalty of $0.9 million to the State of North Carolina if the assessment is upheld. The Company has filed a protest and will commence the appeal process. The Company does not have enough information about the state’s assessment at this time to evaluate its merits and consequently has not recorded any potential impact of that assessment.

Guarantee for DTA Sale

On January 29, 2003, the Company entered into a letter of intent with a subsidiary of Dominion Resources, Inc. to sell its 20% partnership interest in DTA and its industrial revenue bonds for total consideration of $10.5 million. A Purchase and Sale Agreement was executed on March 14, 2003. Under the terms of the Purchase and Sale Agreement, Westmoreland Terminal Company will guarantee throughput through the terminal for a period of three years. To secure the throughput commitment, the purchaser will deposit $6.0 million of the sale proceeds as collateral for a stand-by letter of credit for the purchaser. Westmoreland Terminal Company made certain representations about the status of its partnership interest, the industrial revenue bonds being purchased and the general condition of DTA and agreed to indemnify the purchaser for any loss incurred as a result of a breach of these representations. The liability for a breach of the representations and warranties is capped at $4.5 million. The representations and warranties will expire at various times over the next several years. Westmoreland has guaranteed Westmoreland Terminal Company’s obligations under the Purchase and Sale Agreement for a period of five years in an amount that will decline to $2.5 million after 2 1/2 years. As a result, the Company will recognize a pretax gain of approximately $4.5 million when the transaction closes. Closing is expected to take place promptly after receipt of all bank and partnership consents or following expiration of DTA partnership rights of first refusal. At closing, the purchaser will assume all of Westmoreland Terminal Company’s DTA partnership obligations. The Company will no longer incur DTA-related operating losses, which were $2,050,000, $1,922,000 and $1,800,000 in 2002, 2001 and 2000, respectively. Due to the sale of the Company’s investment, the financial results relating to DTA have been presented as Discontinued Operations.

Other Contingencies

In mid-November, 2002, Westmoreland Coal Company and Westmoreland Mining LLC were served with a Fourth Amended Complaint in a case styled McGreevey et al. v. Montana Power Company et al. The Fourth Amended Complaint added Westmoreland as a defendant in a shareholder suit against Montana Power Company, various officers of Montana Power Company, the Board of Directors of Montana Power Company, financial advisors and lawyers representing Montana Power and the purchasers of some of the businesses formerly owned by Montana Power and its subsidiary, Entech, Inc. The shareholders filed their first complaint on August 16, 2001 and seek to rescind the sale by Montana Power of its generating assets, oil and gas, transmission businesses and the sale of the coal businesses by Entech or to compel the purchasers to hold these businesses in trust for the shareholders. Plaintiffs, early in the proceeding, before Westmoreland was a party to the litigation sought and were granted certification as a class. Westmoreland has filed an answer, various affirmative defenses and a counterclaim against the plaintiffs. On January 10, 2003, attorneys for one of the defendants filed a petition in the U.S. District Court of Montana removing the case to the federal court. Plaintiffs oppose the removal and prefer to litigate the case in the Montana State Court. The U.S. District Judge has not yet ruled in the removal petition. Although there can be no assurances as to the ultimate outcome, the Company believes its defenses are meritorious and will vigorously defend this litigation.

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The Company is a party to other claims and lawsuits with respect to various matters in the normal course of business. The ultimate outcome of these matters is not expected to have a material adverse effect on the Company’s financial condition, results of operations or liquidity.

Lease Obligations

The Company leases certain of its coal reserves from third parties and pays royalties based on either a per ton rate or as a percentage of revenues received. Royalties charged to expense under all such lease agreements amounted to $25,504,000, $21,729,000 and $2,898,000 in 2002, 2001 and 2000, respectively.

The Company has operating lease commitments expiring at various dates, primarily for real property and equipment. Rental expense under operating leases during 2002, 2001 and 2000 totaled $4,333,000, $3,150,000 and $44,000, respectively. Minimum future rental obligations existing under these leases at December 31, 2002 are as follows (in thousands):

Lease Obligations
2003	$  1,968
2004	1,750
2005	1,077
2006	685
2007 and thereafter	-

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Long-Term Sales Commitments

The following table presents estimated minimum total sales tonnage under existing long-term contracts for the next five years from the Company’s existing mining operations. The prices for all future tonnage are subject to revision and adjustments based upon market prices, certain indices and/or cost recovery.

Projected Sales Tonnage Under
Existing Long-Term Contracts
(in millions of tons)
2003	27.3
2004	26.7-27.7
2005	26.2-27.2
2006	25.2-26.2
2007	24.6-25.6

The tonnages in the table above represent backlog commitments under existing, signed contracts and generally exclude pending or anticipated contract renewals or new contracts. These projections reflect customers’ scheduled major plant outages where known. The projections also assume a range of 7.0-8.0 million tons per year under the ALSA between NWR and TGN. The ALSA, which expires in 2015, provides for eighteen month forward determinations of annual volumes on a Btu basis. The parties have committed to 104 trillion Btu’s (approximately 8 million tons) for 2003 and are in the process of negotiating volumes for 2004, 2005 and potentially additional years. NWR supplied 7.1 million tons under the ALSA in 2002, 7.1 million tons in 2001, and 8.2 million tons in 2000.

15. RESTRICTED NET ASSETS OF WESTMORELAND MINING LLC

As discussed in Note 2, WML was formed for the purpose of facilitating the financing of the acquisitions completed effective April 30, 2001. The line of credit and term notes entered into by WML for that purpose significantly restrict the cash and other assets available for distribution or dividend to the parent company or other entities in the consolidated group. See Note 5 for a more detailed discussion of the restrictions and the amount of cash that is available for general use. Due to the recognition of a $55,600,000 deferred tax asset in purchase accounting relating primarily to Westmoreland Coal Company’s net operating loss carryforwards, WML’s basis in property, plant and equipment is higher than that recognized in Westmoreland’s consolidated financial statements.

During the year ended December 31, 2002, WML paid $12,909,000 of dividends and $2,000,000 of management fees to its parent. During the year ended December 31, 2001, WML paid $3,750,000 of dividends and $1,500,000 of management fees to its parent.

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The following are the condensed consolidated financial statements of WML and its subsidiaries as of and for the years ended December 31, 2002 and 2001 (in thousands):

Condensed Consolidated Balance Sheets
	December 31,
		2002		2001
Cash and cash equivalents	$	5,113	$	624
Accounts receivable, net		18,090		32,573
Restricted cash		12,883		8,371
Other current assets		19,580		18,466
Property, plant and equipment, net		208,639		216,173
Deferred tax assets		1,571		402
Reclamation deposits		49,484		47,924
Reclamation receivable		8,370		10,360
Other assets		20,148		20,920
Total Assets	$	343,878	$	355,813
Current portion of long-term debt	$	8,852	$	13,753
Accounts payable and accrued expenses		27,998		29,225
Payable to parent		19,164		10,068
Other current liabilities		2,717		2,818
Line of credit		1,500		8,000
Long-term debt, less current portion		89,305		98,157
Reclamation obligations		137,889		137,748
Other liabilities		7,691		9,409
Member’s equity		48,762		46,635
Total Liabilities and Member’s Equity	$	343,878	$	355,813

Condensed Consolidated Statement of Operations
	Year Ended December 31, 2002		Eight Months Ended December 31, 2001
Coal revenues	$	256,363	$	187,021
Cost of sales – coal		(189,274)		(139,915)
Depreciation and amortization expense		(14,516)		(9,825)
Selling and administrative expense		(18,440)		(11,559)
Management fees to parent		(2,000)		(1,500)
Operating income		32,133		24,222
Interest expense		(10,012)		(7,616)
Interest and other income		2,154		1,999
Income before income taxes		24,275		18,605
Income tax expense		(9,239)		(7,269)
Net income	$	15,036	$	11,336

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Condensed Consolidated Statement of Cash Flows
	Year Ended December 31, 2002		Eight Months Ended December 31, 2001
Net income	$	15,036	$	11,336
Depreciation and amortization expense		14,516		9,825
Deferred income tax benefit		(1,169)		(402)
Changes in operating assets and liabilities		20,456		12,540
Cash provided by operating activities		48,839		33,299
Cash paid for acquisitions		-		(164,980)
Increase in restricted cash		(4,512)		(8,371)
Fixed asset additions		(7,286)		(5,291)
Proceeds from asset sales		610		-
Cash used in investing activities		(11,188)		(178,642)
Proceeds from borrowings of long-term debt, net		-		114,719
Repayment of long-term debt		(13,753)		(12,053)
Contributions from parent		-		39,051
Borrowings (repayments) under line of credit, net		(6,500)		8,000
Dividends to parent		(12,909)		(3,750)
Cash provided by (used in) financing activities		(33,162)		145,967
Net increase in cash and cash equivalents		4,489		624
Cash and cash equivalents, beginning of year		624		-
Cash and cash equivalents, end of year	$	5,113	$	624

16. TRANSACTIONS WITH AFFILIATED COMPANIES

WRI has a coal mining contract with WGI, its 20% stockholder. Mining costs incurred under the contract were $18,013,000, $21,466,000 and $17,507,000 in 2002, 2001 and 2000, respectively.

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17. QUARTERLY FINANCIAL DATA (UNAUDITED)

The quarterly data presented below reflect the reclassification of discontinued operations identified during the fourth quarter of 2002 and as a result differ from those previously filed. Summarized quarterly financial data for 2002 and 2001 are as follows:

		Three Months Ended
		March 31		June 30		Sept. 30		Dec. 31
		(in thousands except per share data)
2002
Revenues	$	83,213	$	83,683	$	75,280	$	73,565
Costs and expenses		77,367		78,601		70,865		70,075
Operating income		5,846		5,082		4,415		3,490
Income (loss) from continuing
operations before income taxes		3,462		3,188		3,619		1,071
Income tax (expense) benefit		(802)		(512)		1,212		2,470
Loss from discontinued operations		(329)		(376)		(2,572)		(306)
Net income		2,331		2,300		2,259		3,235
Less preferred stock dividend
requirements		(444)		(444)		(444)		(440)
Income applicable to common
shareholders	$	1,887	$	1,856	$	1,815	$	2,795
Income per share applicable to   common shareholders:
Basic	$	.25	$	.24	$	.24	$	.36
Diluted	$	.23	$	.23	$	.22	$	.34
Weighted average number of   common and common equivalent   shares outstanding:
Basic		7,531		7,584		7,638		7,677
Diluted		8,103		8,159		8,146		8,172

		Three Months Ended
		March 31		June 30		Sept. 30		Dec. 31
		(in thousands except per share data)
2001
Revenues	$	16,745	$	53,728	$	90,427	$	86,019
Costs and expenses		18,490		53,334		78,723		82,760
Operating income (loss)		(1,745)		394		11,704		3,259
Income (loss) from continuing
operations before income taxes		(1,823)		(893)		9,422		937
Income tax (expense) benefit		(89)		286		(2,882)		1,457
Loss from discontinued operations		(295)		(321)		(331)		(241)
Net income (loss)		(2,207)		(928)		6,209		2,153
Less preferred stock dividend
requirements		(444)		(444)		(444)		(444)
Income (loss) applicable to common
shareholders	$	(2,651)	$	(1,372)	$	5,765	$	1,709
Income (loss) per share applicable to   common shareholders:
Basic	$	(0.37)	$	(0.19)	$	0.79	$	0.23
Diluted	$	(0.37)	$	(0.19)	$	0.73	$	0.21
Weighted average number of   common and common equivalent   shares outstanding:
Basic		7,075		7,144		7,264		7,471
Diluted		7,075		7,144		7,859		8,069

106

Independent Auditor’s Report

The Board of Directors and Shareholders
Westmoreland Coal Company:

We have audited the accompanying consolidated balance sheets of Westmoreland Coal Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, shareholders’ equity and comprehensive income and cash flows for each of the years in the three-year period ended December 31, 2002. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Westmoreland Coal Company and subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

               KPMG LLP

Denver, Colorado
March 5, 2003, except as to Notes 4 and 14,
which are as of March 14, 2003

107

ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
                 ACCOUNTING AND FINANCIAL DISCLOSURE

This item is not applicable.

PART III

ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

ITEM 11 - EXECUTIVE COMPENSATION

ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
                   MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

For Items 10-13, inclusive, except for information concerning executive officers of Westmoreland included as an unnumbered item in Part I above, reference is hereby made to Westmoreland’s definitive proxy statement to be filed in accordance with Regulation 14A pursuant to Section 14(a) of the Securities Exchange Act of 1934, which is incorporated herein by reference thereto.

ITEM 14 - CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures.Based on their evaluation of the Company’s disclosure controls and procedures (as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934) as of a date within 90 days of the filing date of this Annual Report on Form 10-K, the Company’s chief executive officer and chief financial officer have concluded that the Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and are operating in an effective manner.

Changes in internal controls.There were no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls subsequent to the date of their most recent evaluation.

108

PART IV

ITEM 15 - EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON
                   FORM 8-K

a) 1.	The financial statements filed herewith are the Consolidated Balance Sheets of the Company and subsidiaries as of December 31, 2002 and December 31, 2001, and the related Consolidated Statements of Operations, Shareholders' Equity and Cash Flows for each of the years in the three-year period ended December 31, 2002 together with the Summary of Significant Accounting Policies and Notes, which are contained on pages 70 through 76 inclusive.
2.	The following financial statement schedule is filed herewith:      Schedule II - Valuation Accounts
3.	The following exhibits are filed herewith as required by Item 601 of Regulation S-K:

(2)	Plan of acquisition, reorganization, arrangement, liquidation or succession
	(a)	Westmoreland's Plan of Reorganization was confirmed by an order of the United States Bankruptcy Court for the District of Delaware on December 16, 1994, and upon complying with the conditions of the order, Westmoreland emerged from bankruptcy on December 22, 1994. A copy of the confirmed Plan of Reorganization was filed as an Exhibit to Westmoreland's Report on Form 8-K filed December 30, 1994, which is incorporated herein by reference thereto (SEC File #001-11155)..
(3)	(a)	Articles of Incorporation: Restated Certificate of Incorporation, filed with the Office of the Secretary of State of Delaware on February 21, 1995 and filed as Exhibit 3(a) to Westmoreland's 10-K for 1994 which Exhibit is incorporated herein by reference (SEC File #001-11155).
	(b)	Bylaws, as amended on June 18, 1999, and filed as Exhibit (3)(b) to Westmoreland's Report on Form 8-K filed June 21, 1999, which exhibit is incorporated herein by reference (SEC File #001-11155).
(4)	Instruments defining the rights of security holders
	(a)	Certificate of Designation of Series A Convertible Exchangeable Preferred Stock of the Company defining the rights of holders of such stock, filed July 8, 1992 as an amendment to the Company's Certificate of Incorporation, and filed as Exhibit 3(a) to Westmoreland's Form 10-K for 1992, which Exhibit is incorporated herein by reference (SEC File #001-11155).
	(b)	Form of Indenture between Westmoreland and Fidelity Bank, National Association, as Trustee relating to the Exchange Debentures. Reference is hereby made to Exhibit 4.1 to Form S-2 Registration No. 33-47872 filed May 13, 1992, and Amendments 1 through 4 thereto, which Exhibit is incorporated herein by reference.

109

	(c)	Form of Exchange Debenture. Reference is hereby made to Exhibit 4.2 to Form S-2 Registration No. 33-47872 filed May 13, 1992, and Amendments 1 through 4 thereto, which Exhibit is incorporated herein by reference.
	(d)	Form of Deposit Agreement among Westmoreland, First Chicago Trust Company of New York, as Depository and the holders from time to time of the Depository Receipts. Reference is hereby made to Exhibit 4.3 to Form S-2 Registration No. 33-47872 filed May 13, 1992, and Amendments 1 through 4 thereto, which Exhibit is incorporated herein by reference.
	(e)	Form of Certificate of Designation for the Series A Convertible Exchangeable Preferred Stock. Reference is hereby made to Exhibit 4.4 to Form S-2 Registration No. 33-47872 filed May 13, 1992, and Amendments 1 through 4 thereto, which Exhibit is incorporated herein by reference.
	(f)	Specimen certificate representing the common stock of Westmoreland, filed as Exhibit 4(c) to Westmoreland's Registration Statement on Form S-2, Registration No. 33-1950, filed December 4, 1985, is hereby incorporated by reference.
	(g)	Specimen certificate representing the Preferred Stock. Reference is hereby made to Exhibit 4.6 to Form S-2 Registration No. 33-47872 filed May 13, 1992, and Amendments 1 through 4 thereto, which Exhibit is incorporated herein by reference.
	(h)	Form of Depository Receipt. Reference is hereby made to Exhibit 4.7 to Form S-2 Registration No. 33-47872 filed May 13, 1992, and Amendments 1 through 4 thereto, which Exhibit is incorporated herein by reference.
	(i)	Amended and Restated Rights Agreement, dated as of February 7, 2003, between Westmoreland Coal Company and EquiServe Trust Company, N.A. Reference is hereby made to Exhibit 4.1 to Westmoreland's Form 8-K filed February 7, 2003, which Exhibit is incorporated herein by reference (SEC File #001-11155).
	(j)	In accordance with paragraph (b)(4)(iii) of Item 601 of Regulation S-K, Westmoreland hereby agrees to furnish to the Commission, upon request, copies of all other long-term debt instruments.
(10)	Material Contracts
	(a)	Westmoreland Coal Company 1985 Incentive Stock Option and Stock Appreciation Rights Plan is incorporated herein by reference to Exhibit 10(d) to Westmoreland's Annual Report on Form 10-K for 1984 (SEC File #0-752).
	(b)	In 1990, the Board of Directors established an Executive Severance Policy for certain executive officers, which provides a severance award in the event of termination of employment. The description of the Executive Severance Policy is incorporated herein by reference to Westmoreland's Definitive Schedule 14A filed April 20, 2000 (SEC File #001-11155).
	(c)	Westmoreland Coal Company 1991 Non-Qualified Stock Option Plan for Non-Employee Directors is incorporated herein by reference to Exhibit 10(i) to Westmoreland's Annual Report on Form 10-K for 1990 (SEC File #0-752).

110

(d)	Effective January 1, 1992, the Board of Directors established a Supplemental Executive Retirement Plan ("SERP") for certain executive officers and other key individuals, to supplement Westmoreland's Retirement Plan by not being limited to certain Internal Revenue Code limitations is incorporated herein by reference to Exhibit 10(d) to Westmoreland's Annual Report on Form 10-K for 2000 (SEC File #001-11155).
(e)	Amended Coal Lease Agreement between Westmoreland Resources, Inc. and Crow Tribe of Indians, dated November 26, 1974, as further amended in 1982, is incorporated herein by reference to Exhibit (10)(a) to Westmoreland's Quarterly Report on Form 10-Q for the quarter ended March 31, 1992 (SEC File #0-752).
(f)	Westmoreland Coal Company 1995 Long-Term Incentive Stock Plan is incorporated herein by reference to Appendix 3 to Westmoreland's Definitive Schedule 14A filed April 28, 1995 (SEC File #0-752).
(g)	Master Agreement, dated as of January 4, 1999 between Westmoreland Coal Company, Westmoreland Resources, Inc., Westmoreland Energy, Inc., Westmoreland Terminal Company, and Westmoreland Coal Sales Company, the UMWA 1992 Benefit Plan and its Trustees, the UMWA Combined Benefit Fund and its Trustees, the UMWA 1974 Pension Trust and its Trustees, the United Mine Workers of America, and the Official Committee of Equity Security Holders in the chapter 11 case of Westmoreland Coal and its official members is incorporated herein by reference to Exhibit No. 99.2 to Westmoreland's Form 8-K filed on February 5, 1999 (SEC File #001-11155).
(h)	Contingent Promissory Note between Westmoreland Coal Company, Westmoreland Resources, Inc., Westmoreland Energy, Inc., Westmoreland Coal Sales Company, and Westmoreland Terminal Company and the UMWA Combined Benefit Fund and the UMWA 1992 Benefit Plan is incorporated herein by reference to Exhibit No. 99.3 to Westmoreland's Form 8-K filed on February 5, 1999 (SEC File #001-11155).
(i)	Westmoreland Coal Company 1996 Directors' Stock Incentive Plan is incorporated herein by reference to Exhibit 10(i) to Westmoreland's Annual Report on Form 10-K for year ended December 31, 2000 (SEC File #001-11155).
(j)	Westmoreland Coal Company 2000 Nonemployee Directors' Stock Incentive Plan is incorporated herein by reference to Exhibit 10(j) to Westmoreland's Annual Report on Form 10-K for year ended December 31, 2000 (SEC File #001-11155).
(k)	Westmoreland Coal Company 2000 Long-Term Incentive Stock Plan is incorporated herein by reference to Annex A to Westmoreland's Definitive Schedule 14A filed April 20, 2000 (SEC File #001-11155).
(l)	Westmoreland Coal Company 2001 Directors Compensation Plan is incorporated herein by reference to Westmoreland's Form S-8 filed March 12, 2001 (SEC File #001-11155).

111

(m)	Amended and Restated Coal Supply Agreement dated August 24, 1998, by and among The Montana Power Company, Puget Sound Energy, Inc., The Washington Water Power Company, Portland General Electric Company, PacifiCorp and Western Energy Company is incorporated herein by reference to Exhibit 10.1 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155).
(n)	Coal Transportation Agreement dated July 10, 1981, by and among the Montana Power Company, Puget Sound Power & Light Company, Puget Colstrip Construction Company, The Washington Water Power Company, Portland General Electric Company, Pacific Power & Light Company, Basin Electric Power Cooperative, and Western Energy Company is incorporated herein by reference to Exhibit 10.2 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155).
(o)	Amendment No. 1 to the Coal Transportation Agreement dated September 14, 1987, by and among The Montana Power Company, Puget Sound Power & Light Company, Puget Colstrip Construction Company, The Washington Water Power Company, Portland General Electric Company, Pacific Power & Light Company and Western Energy Company is incorporated herein by reference to Exhibit 10.3 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155).
(p)	Amendment No. 2 to the Coal Transportation Agreement dated August 24, 1998, by and among The Montana Power Company, Puget Sound Power & Light Company, Puget Colstrip Construction Company, The Washington Water Power Company, Portland General Electric Company, Pacific Power & Light Company, Basin Electric Power Cooperative, and Western Energy Company is incorporated herein by reference to Exhibit 10.4 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155).
(q)	Lignite Supply Agreement dated August 29, 1979, between Northwestern Resources Co. and Utility Fuels Inc. is incorporated herein by reference to Exhibit 10.5 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155).
(r)	Settlement Agreement and Amendment of Existing Contracts dated August 2, 1999, between Northwestern Resources Co. and Reliant Energy, Incorporated is incorporated herein by reference to Exhibit 10.6 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155).
(s)	Term Loan Agreement dated as of April 27, 2001 by and among Westmoreland Mining LLC, WCCO-KRC Acquisition Corp., Dakota Westmoreland Corporation, Western Energy Company, Northwestern Resources Co., the other entities from time to time party thereto as guarantors, and the purchasers named in Schedule A thereto is incorporated herein by reference to Exhibit 99.2 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155).
(t)	Credit Agreement dated as of April 27, 2001 by and among Westmoreland Mining LLC, WCCO-KRC Acquisition Corp., Dakota Westmoreland Corporation, Western Energy Company, Northwestern Resources Co., the other entities from time to time party thereto as guarantors, the banks party thereto, and PNC Bank, National Association, in its capacity as agent for the banks is incorporated herein by reference to Exhibit 99.3 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155).

112

(u)	First Amendment to Credit Agreement dated as of August 15, 2001 among Westmoreland Mining LLC, the Loan Parties under the Credit Agreement, the Banks under the Credit Agreement, and PNC Bank, National Association, as Agent is incorporated herein by reference to Exhibit 10.7 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155).
(v)	First Amendment to Note Purchase Agreement dated as of August 15, 2001 among Westmoreland Mining LLC, the other Obligors under the Agreement, the Purchasers under the Agreement, and PNC Capital Markets, Inc., as lead arranger is incorporated herein by reference to Exhibit 10.8 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155).
(w)	Amendment No. 2 to Credit Agreement dated February 27, 2002 among Westmoreland Mining LLC, the loan Parties under Credit Agreement, the Banks under the Credit Agreement, and PNC Bank, National Association, as Agent, is incorporated herein by reference to Exhibit 10(w) to Westmoreland's Annual Report on Form 10-K for the year ended December 31, 2001 (SEC File #001-11155).
(x)	Second Amendment to Term Loan Agreement dated February 27, 2002 among Westmoreland Mining LLC, the other Obligors under the Agreement, the Purchasers under the Agreement, and PNC Capital Markets, Inc. as lead arranger, is incorporated herein by reference to Exhibit 10(x) to Westmoreland's Annual Report on Form 10-K for the year ended December 31, 2001 (SEC File #001-11155).
(y)	Loan Agreement dated as of December 14, 2001 between Westmoreland Coal Company, a Delaware corporation, and First Interstate Bank, a Montana corporation, is incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on December 19, 2001 (SEC File #001-11155).
(z)	First Amendment dated as of December 24, 2002 to Loan Agreement dated December 14, 2001 between Westmoreland Coal Company, a Delaware corporation, and First Interstate Bank, a Montana corporation, is incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on January 28, 2003 (SEC File #001-11155).
(aa)	Second Amendment dated as of January 24, 2003 to Loan Agreement dated December 14, 2001 between Westmoreland Coal Company, a Delaware corporation, and First Interstate Bank, a Montana corporation, is incorporated herein by reference to Exhibit 10.2 on Form 8-K filed on January 28, 2003 (SEC File #001-11155).
(bb)	Pledge Agreement is dated as of April 27, 2001 by and among Westmoreland Coal Company, Westmoreland Mining LLC, the other entities from time to time party thereto as pledgors, and Firstar Bank, N.A., as collateral agent for the purchasers in connection with the Term Loan Agreement, incorporated herein by reference to Exhibit 99.4 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155).

113

	(cc)	Pledge Agreement dated as of April 27, 2001, by and among Westmoreland Coal Company, Westmoreland Mining LLC, the other entities from time to time party thereto as pledgors, and Firstar Bank, N.A., as collateral agent for the banks in connection with the Revolving Credit Agreement is incorporated herein by reference to Exhibit 99.5 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155).
	(dd)	Continuing Agreement of Guaranty and Suretyship dated as of April 27, 2001 by and among WCCO-KRC Acquisition Corp., Dakota Westmoreland Corporation, Western Energy Company, Northwestern Resources Co., and each of the other persons which becomes a guarantor thereunder, in favor of the purchasers under the Term Loan Agreement is incorporated herein by reference to Exhibit 99.6 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155).
	(ee)	Continuing Agreement of Guaranty and Suretyship dated as of April 27, 2001 by and among WCCO-KRC Acquisition Corp., Dakota Westmoreland Corporation, Western Energy Company, Northwestern Resources Co., and each of the other persons which becomes a guarantor thereunder, in favor of PNC Bank, National Association, as agent for the banks in connection with that Credit Agreement is incorporated herein by reference to Exhibit 99.7 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155).
	(ff)	Security Agreement dated as of April 27, 2001 by and among Westmoreland Mining LLC, WCCO-KRC Acquisition Corp., Dakota Westmoreland Corporation, Western Energy Company, Northwestern Resources Co., and each of the other persons which becomes a guarantor under the Term Loan Agreement and Firstar Bank, N.A., as collateral agent for the purchasers under the Term Loan Agreement is incorporated herein by reference to Exhibit 99.8 to the Registrant’s Current Report on Form 8-k dated May 15, 2001 (SEC File #001-11155).
	(gg)	Stock Purchase Agreement dated as of September 15, 2000 by and between Westmoreland Coal Company and Entech, Inc. is incorporated herein by reference to Exhibit 99.1 to the Registrant's Current Report on Form 8-K filed February 5, 2001 (SEC File #001-11155).
	(hh)	Westmoreland Coal Company 2000 Performance Unit Plan is incorporated herein by reference to Exhibit 10(ff) to Westmoreland's Annual Report on Form 10-K for the year ended December 31, 2001 (SEC File #001-11155).
	(ii)	Letter Agreement dated June 18, 2002, between Reliant-HL&P and Northwestern Resources Co. is incorporated herein by reference to Exhibit 10.1 to Westmoreland’s Quarterly Report on Form 10-Q for the Quarter ended June 30, 2002 (SEC File #001-11155).
(21)		Subsidiaries of the Registrant
(23)		Consent of Independent Certified Public Accountants

114

	(99.1)	Certifications pursuant to 18 U.S.C. Section 1350, as adopted to Section 906 of the Sarbanes-Oxley Act of 2002.
b)	Reports on Form 8-K.
	(1)	On November 5, 2002, the Company filed a report on Form 8-K regarding its press release on November 1, 2002 announcing that it had received a $1.1 million payment from the U.S. Army in connection with a favorable judgment in litigation between the Army and the Ft. Drum Power Project.
	(2)	On November 8, 2002, the Company filed a report on Form 8-K announcing its Board of Directors has authorized a dividend of $0.15 per depositary share payable on January 1, 2003 to holders of record as of December 9, 2002.
	(3)	On December 11, 2002, the Company filed a report on Form 8-K announcing that the bankruptcy court presiding over Washington Group International's reorganization has approved the previously announced agreement to settle all pending claims and litigation between Westmoreland Resources, Inc. and Washington Group International.
	(4)	On December 20, 2002, the Company filed a report on Form 8-K regarding that the Railroad Commission of Texas has determined that CenterPoint Energy Houston Electric, the guarantor for the reclamation bond at the Jewett Mine, meets the qualifying criteria as a third-party guarantor under the Texas Surface Coal Mining and Reclamation Act.
	(5)	On January 28, 2003, the Company filed a report on Form 8-K regarding the execution on December 24, 2002 of the First Amendment to a Loan Agreement dated December 14, 2001 with First Interstate Bank, a Montana corporation. The amendment extended the maturity date of the revolving loan from December 14, 2003 to December 14, 2004. On January 24, 2003 the Company executed the Second Amendment to the Loan Agreement. The Second Amendment further extends the maturity date of the revolving loan to January 15, 2005 and increases the Revolving Line of Credit from $7 million to $10 million.
	(6)	On February 7, 2003, the Company filed a report on Form 8-K announcing an amendment to its Rights Agreement dated as of January 28, 1993 by entering into an Amended and Restated Rights Agreement dated as of February 7, 2003.
	(7)	On February 10, 2003, the Company filed a report on Form 8-K announcing its Board of Directors has authorized a dividend of $0.15 per depositary share payable on April 1, 2003 to holders of record as of March 7, 2003.
	(8)	On March 17, 2003, the Company filed a report on Form 8-K announcing it had reached agreement with Dominion Energy Terminal Company, Inc. for the sale of Westmoreland Terminal Company's 20% interest in Dominion Terminal Associates and associated industrial revenue bonds.

115

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	WESTMORELAND COAL COMPANY
Date:   March 27, 2003	By: /s/ Ronald H. Beck
	Ronald H. Beck
	Vice President of Finance and Treasurer
	(A Duly Authorized Officer)
Date:   March 27, 2003	By: /s/ Thomas S. Barta
	Thomas S. Barta
	Controller
	(Principal Accounting Officer)

Signature	Title	Date
Principal Executive Officer:
	Chairman of the Board, President, and
/s/ Christopher K. Seglem	Chief Executive Officer	March 27, 2003
Christopher K. Seglem
Directors:
/s/ Michael Armstrong	Director	March 27, 2003
Michael Armstrong
/s/ Thomas J. Coffey	Director	March 27, 2003
Thomas J. Coffey
/s/ Pemberton Hutchinson	Director	March 27, 2003
Pemberton Hutchinson
/s/ Robert E. Killen	Director	March 27, 2003
Robert E. Killen
/s/ William R. Klaus	Director	March 27, 2003
William R. Klaus
/s/ Thomas W. Ostrander	Director	March 27, 2003
Thomas W. Ostrander
/s/ James W. Sight	Director	March 27, 2003
James W. Sight
/s/ William M. Stern	Director	March 27, 2003
William M. Stern
/s/ Donald A. Tortorice	Director	March 27, 2003
Donald A. Tortorice

116

CERTIFICATION

I, Christopher K. Seglem, certify that:

1.	I have reviewed this annual report on Form 10-K of Westmoreland Coal Company;
2.	Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.	Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
	a.	designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
	b.	evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
	c.	presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
	a.	all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
	b.	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6.	The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date:    March 27, 2003	/s/ Christopher K. Seglem
	Name:   Christopher K. Seglem
	Title:     Chairman of the Board, President and               Chief Executive Officer

117

CERTIFICATION

I, Robert J. Jaeger, certify that:

1.	I have reviewed this annual report on Form 10-K of Westmoreland Coal Company;
2.	Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.	Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
	a.	designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
	b.	evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
	c.	presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
	a.	all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
	b.	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6.	The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date:    March 27, 2003	/s/ Robert J. Jaeger
	Name:   Robert J. Jaeger
	Title:     Senior Vice President and               Chief Financial Officer

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INDEPENDENT AUDITORS’ REPORT

The Board of Directors and Shareholders
Westmoreland Coal Company:

Under date of March 5, 2003, except as to Notes 4 and 14, which are as of March 14, 2003, we reported on the consolidated balance sheets of Westmoreland Coal Company and subsidiaries as of December 31, 2002 and 2001, and the related statements of operations, shareholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2002, which report appears in the December 31, 2002, Annual Report on Form 10-K of Westmoreland Coal Company. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related financial statement schedule II. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement schedule based on our audits.

In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

               KPMG LLP

Denver, Colorado
March 5, 2003

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Schedule II

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Valuation Accounts
Years Ended December 31, 2002, 2001 and 2000

(in thousands)

		Balance at beginning of year	Deductions credited to earnings	Other Additions		Balance at end of year
Year ended December 31, 2002:
Allowance for doubtful accounts	$	2,957	(516)	-	$	2,441	(A)
Year ended December 31, 2001:
Allowance for doubtful accounts	$	3,301	(446)	102	$	2,957	(A)
Year ended December 31, 2000:
Allowance for doubtful accounts	$	3,602	(400)	99	$	3,301	(A)

Amounts above include current and non-current valuation accounts.

(A) Includes reserves related to the uncollectibility of notes receivable reported as a reduction of other assets in the Company's Consolidated Balance Sheets.

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EXHIBIT 21
Subsidiaries of the Registrant for the year ended December 31, 2002:

Subsidiary Name	State of Incorporation
Kentucky Criterion Coal Company	Delaware
Pine Branch Mining Inc.	Delaware
WEI - Fort Lupton, Inc.	Delaware
WEI - Rensselaer, Inc.	Delaware
WEI - Roanoke Valley, Inc.	Delaware
Westmoreland Coal Sales Inc.	Delaware
Westmoreland Energy, LLC	Delaware
Westmoreland Resources, Inc.	Delaware
Westmoreland Terminal Company	Delaware
Westmoreland - Altavista, Inc.	Delaware
Westmoreland - Fort Drum, Inc.	Delaware
Westmoreland - Franklin, Inc.	Delaware
Westmoreland - Hopewell, Inc.	Delaware
Westmoreland Technical Services, Inc.	Delaware
Cleancoal Terminal Co.	Delaware
Criterion Coal Co.	Delaware
Deane Processing Co.	Delaware
Eastern Coal and Coke Co.	Pennsylvania
Westmoreland Savage Corp.	Delaware
Westmoreland Mining LLC	Delaware
Dakota Westmoreland Corporation	Delaware
Western Energy Company	Montana
Northwestern Resources Co.	Montana
Westmoreland Risk Management, Ltd.	Bermuda
Basin Resources, Inc.	Colorado
North Central Energy Company	Colorado
Horizon Coal Services, Inc.	Montana
Westmoreland Power, Inc.	Delaware

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EXHIBIT 23

Consent of Independent Certified Public Accountants

The Board of Directors
Westmoreland Coal Company:

We consent to incorporation by reference in the registration statements (No. 2-90847, No. 33-33620, No. 333-56904 and No. 333-66698) on Form S-8 of Westmoreland Coal Company of our report dated March 5, 2003, except as to Notes 4 and 14, which are as of March 14, 2003, relating to the consolidated balance sheets of Westmoreland Coal Company and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of operations, shareholders’ equity and comprehensive income and cash flows for each of the years in the three-year period ended December 31, 2002, and the report dated March 5, 2003 on the related schedule, which reports appear in the December 31, 2002, Annual Report on Form 10-K of Westmoreland Coal Company.

               KPMG LLP

Denver, Colorado
March 25, 2003

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Exhibit 99.1

STATEMENT PURSUANT TO 18 U.S.C.§1350

Pursuant to 18 U.S.C. § 1350, each of the undersigned certifies that this Annual Report on Form 10-K for the period ended December 31, 2002 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained in this report fairly presents, in all material respects, the financial condition and results of operations of Westmoreland Coal Company.

Dated:    March 27, 2003	/s/ Christopher K. Seglem
	Christopher K. Seglem
	Chief Executive Officer
Dated:    March 27, 2003	/s/ Robert J. Jaeger
	Robert J. Jaeger
	Chief Financial Officer

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