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, 2004

( ) 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, Colorado 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.

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 30, 2004 was $134,876,000.

There were 8,198,646 shares outstanding of the registrant’s Common Stock, $2.50 Par Value per share (the registrant’s only class of common stock), as of March 1, 2005.

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.

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

Item

Page

PART I

1	Business	4
2	Properties	18
3	Legal Proceedings	25
4	Submission of Matters to a Vote of Security Holders	29

PART II

5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
6	Selected Financial Data	34
7	Management's Discussion and Analysis of Financial Condition and Results of Operations	35
7A	Quantitative and Qualitative Disclosures About Market Risk	66
8	Financial Statements and Supplementary Data	68
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	111
9A	Controls and Procedures	111
9B	Other Information	112

PART III

10	Directors and Executive Officers of the Registrant	113
11	Executive Compensation	113
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	113
13	Certain Relationships and Related Transactions	113
14	Principal Accountant Fees and Services	113

PART IV

15	Exhibits, Financial Statement Schedule	114

Signatures		121

Throughout this Form 10-K, we make statements which are not historical facts or information and that may be deemed “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. These forward-looking statements include, but are not limited to, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations. 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, 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; health care 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 growth and development 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 achieve anticipated cost savings and profitability targets; the Company’s ability to successfully identify new business opportunities; the Company’s ability to negotiate profitable coal contracts, price reopeners and extensions; the Company’s ability to predict or anticipate commodity price changes; the Company’s ability to maintain satisfactory labor relations; changes in the industry; competition; the Company’s ability to utilize its income tax net operating losses; the ability to reinvest cash, including cash that has been deposited in reclamation accounts, at an acceptable rate of return; weather conditions; the availability of transportation; price of alternative fuels; costs of coal produced by other countries; the demand for electricity; the performance of the ROVA Project and the structure of the ROVA Project’s contracts with its lenders and Dominion Virginia Power; our ability to complete the acquisition of the portion of the ROVA project that we do not currently own; the effect of regulatory and legal proceedings, including the bankruptcy filing by Touch America Holdings Inc. and Entech Inc.; environmental issues, including the cost of compliance with existing and future environmental requirements; the claims between the Company and Montana Power; and the other factors discussed in Items 1, 2, 3 and 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.

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 site 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

We are an energy company. We are the oldest independent coal company in the United States with our origin in 1854. We mine coal that is used to produce electric power and we own interests in power-generating plants. We began to earn royalties from the production of coalbed methane gas in the first quarter of 2004.

Coal Operations

We were the 10th largest coal producer in the United States, ranked by tons of coal mined in 2003, the last year for which data is currently available. In 2004, we increased our coal production to 29.0 million tons, about 3% of all the coal produced in the United States, and we believe that we continue to rank among the top 10 U.S. coal producers.

Mines

We own five mines; all except the Jewett Mine are located in the northern tier, a coal market extending from Montana through Minnesota and other upper Midwestern states. The mines are:

• the Absaloka Mine,

• the Rosebud Mine,

• the Jewett Mine,

• the Beulah Mine, and

• the Savage Mine.

The Absaloka Mine is owned by our subsidiary, Westmoreland Resources, Inc. The Beulah, Jewett, Rosebud, and Savage Mines are owned by our separate subsidiary, Westmoreland Mining LLC.

All of these mines are surface mines. At large surface mines, like ours, coal is frequently mined from more than one area or pit at any given time. Surface mining involves extracting coal that lies close to the surface. Where the surface layer contains rock, overburden drills are used to drill holes in the rock, explosives are inserted, and the blast loosens the layer of rock. Earth-moving equipment removes the overburden – the layer of dirt and rock that lies between the surface and the coal. A machine called a dragline is typically used to remove a substantial portion of the overburden. Draglines are very large – our largest dragline weighs approximately 7,000 tons and has a bucket capacity of 128 cubic yards. Smaller pieces of equipment, including bulldozers, front end loaders, scrapers, and dump trucks move the remainder of the overburden. Once the coal has been exposed, front-end loaders, backhoes, or electric shovels load the coal in dump trucks. After the coal has been extracted, it is processed (typically by crushing), sampled (or “assayed”), and then shipped to customers.

The Absaloka Mine is located on approximately 15,000 acres in Big Horn County, Montana, near the town of Hardin. Coal was first extracted from the Absaloka Mine in 1974. Westmoreland Resources owns the Absaloka Mine. We own 80% of the stock of Westmoreland Resources. Washington Group International, Inc. owns the remaining 20% and operates the mine. Unless otherwise indicated, we own 100% of each of our other subsidiaries.

The Rosebud Mine is located on approximately 25,000 acres in Rosebud and Treasure Counties, Montana, near the town of Colstrip, about 130 miles east of Billings. Coal was first mined near Colstrip in 1924, and production from the existing mine complex began in 1968. Westmoreland Mining’s subsidiary, Western Energy Company, owns and operates the Rosebud Mine. Westmoreland Mining acquired the stock of Western Energy from Entech, Inc., a subsidiary of the Montana Power Company, in April 2001.

The Jewett Mine is located on approximately 35,000 acres in Freestone, Leon, and Limestone Counties, Texas, near the town of Jewett, about half way between Dallas and Houston. The Jewett Mine produces lignite, a type of coal with a lower Btu value per ton than sub-bituminous or bituminous coal. “Btu” is a measure of heat energy. The higher the Btu value, the more energy is produced when the coal is burned. Lignite was first extracted from the Jewett Mine in 1985. Westmoreland Mining’s subsidiary, Texas Westmoreland Coal Company (formerly Northwestern Resources Co.), owns and operates the Jewett Mine. Westmoreland Mining acquired the stock of Northwestern Resources from Entech, Inc. in April 2001.

The Beulah Mine is located on approximately 9,300 acres in Mercer and Oliver Counties, North Dakota, near the town of Beulah. The Beulah Mine also produces lignite. Lignite was first extracted from the Beulah Mine in 1963. Westmoreland Mining’s subsidiary, Dakota Westmoreland Corporation, owns and operates the Beulah Mine. Westmoreland Mining acquired the Beulah Mine in May 2001 from Knife River Corporation, a subsidiary of MDU Resources Group, Inc.

The Savage Mine is located on approximately 1,600 acres in Richland County, Montana, near the town of Sidney. Production began at the Savage Mine in 1958. Westmoreland Mining’s subsidiary, Westmoreland Savage Corporation, owns and operates the Savage Mine. Westmoreland Mining acquired the Savage Mine in May 2001 from Knife River Corporation.

The following table presents the sales from our mines in the last three years (in thousands of tons):

Year	Absaloka	Rosebud	Jewett	Beulah	Savage
2004	6,488	12,655	6,453	3,053	375
2003	6,016	11,003	7,462	2,816	379
2002	5,160	10,061	7,105	3,006	337

Coal and the Production of Electricity

Over the last fifty years, coal has played a significant role in generating the United States’ electricity. The following table, derived from the Energy Information Administration’s data, shows coal’s share in the production of all electricity in the United States:

Year	Electricity generated by all sources (billions of kilowatt hours) (1)	Electricity generated by coal (billions of kilowatt hours)	Coal-generated electricity as a percentage of all electricity

1950	334	154	46%
1960	759	403	53%
1970	1,535	704	46%
1980	2,290	1,162	51%
1990	3,038	1,594	52%
2000	3,802	1,966	52%
2003 (2)	3,848	1,970	51%

__________

(1)	All sources include all fossil fuels, nuclear electric power, hydroelectric pumped storage, renewable energy (including conventional hydroelectric power), and other.

(2)	Preliminary.

The EIA projects that the output of coal-fired plants used to generate electricity will increase from 1,970 billion kilowatt hours in 2003 to 2,890 billion kilowatt hours in 2025 and that the demand for coal used to generate electricity will increase 1.6% per year from 2003 through 2025.

Customers, Competition, and Coal Supply Agreements

We sell almost all of the coal that we produce to plants that generate electricity. In 2004, for example, we sold about 2% of our coal to industrial and institutional users and the remainder to power-generating plants. These plants compete with all other producers of electricity to be “dispatched,” or called upon to generate power. We compete with many other suppliers of coal to provide fuel to these plants.

We believe that the competitive advantage of our mines derives from two facts:

•

all of our mines are the lowest cost-suppliers to each of their respective principal customers; and

•

nearly all of the power plants we supply were specifically designed to use our coal.

The plants we supply are among the lower cost producers of electric power in their respective regions and are among the cleaner producers of power from fossil fuels. As a result, we believe that the power-generating plants that we supply are more likely to be dispatched, and that our mines will be supplying the coal that powers these generating units. All of the power-generating plants we supply are baseloaded. The baseload is the part of the total demand for energy that does not vary over a given period of time, and a baseload or baseloaded power plant is a plant that supplies this relatively consistent demand.

From the standpoint of a purchaser of coal, two of the principal costs of burning coal are the cost of the coal and the cost of transporting the coal from the point of extraction to the purchaser. The principal customers of the Rosebud, Jewett, and Beulah Mines are located adjacent to the mines, so that the coal for these customers can be delivered by conveyor belt or in-pit truck rather than by more expensive means such as on-road truck or rail. The customers of the Savage Mine are located approximately 20 to 25 miles from the mine, so that coal can be transported most economically by on-road truck. The Absaloka Mine enjoys about a 300 mile rail advantage over its principal competitors from the Southern Powder River Basin (“SPRB”). We believe that all of our mines are the lowest cost-suppliers to each of their respective customers, and that other mines of ours could be the next lowest cost suppliers to these customers. This is the result of a transportation advantage that our mines have compared to our competitors.

The Absaloka Mine faces a different competitive situation than our other mines. The Absaloka Mine sells its coal in the rail market, to utilities located in the northern tier of the United States that are served by the BNSF. These utilities may purchase coal from us or from other producers, and we compete with other producers on the basis of price and quality, with the purchasers also taking into account the cost of transporting the coal to their plants. The Absaloka Mine was developed in part to supply the Sherburne County Station, a three unit power plant operated by Xcel Energy near Minneapolis, Minnesota, with a generating capacity of 2,292 MW. The Absaloka Mine has a transportation advantage to the Sherburne County Station because it is located about 300 rail miles closer to that power plant than other mines competing for that business. The Absaloka Mine has supplied the Sherburne County Station since 1976, when it commenced commercial operations. The Absaloka Mine has three separate coal sales contracts to supply the Sherburne County Station.

•

The Absaloka Mine supplies coal to Xcel Energy under two primary contracts, one covering 3.4 million tons per year that expires in 2007 and one covering 1.0 million tons per year that expires in 2006. We receive prices under these contracts that are adjusted by specified indices.

•

The Absaloka Mine also supplies coal to Western Fuels Association, the fuel buyer for Southern Minnesota Municipal Power Agency or SMMPA, covering almost all of SMMPA’s fuel requirements for Unit 3 at the Sherburne County Station, or approximately 1.5 million tons per year. This contract expires in 2007. The price we receive under this contract is also adjusted by specified indices.

The Absaloka Mine also sells coal to Xcel Energy’s A.S. King Station, which is located in Bayport, Minnesota, and to Consumers Energy Company through Midwest Energy Resources Company for Consumers’ Cobb and Weadock stations, which are located in Muskegon and Essexville, Michigan, under contracts expiring in 2007. The Absaloka Mine produces coal from land leased from the Crow Tribe of Indians. In February 2004, we reached agreement with the Crow Tribe for exploration of new coal reserves in order to continue serving customers beyond exhaustion of the reserves in our existing lease.

The Rosebud Mine’s primary customers are the owners of the four-unit Colstrip Station, which has a generating capacity of approximately 2,200 megawatts, or MW, and is located adjacent to the mine. The Rosebud Mine has supplied the Colstrip Station since 1975, when Colstrip Units 1&2 commenced commercial operations. Western Energy sells this coal under long-term contracts expiring in 2009 for Colstrip Units 1&2 and in 2019 for Colstrip Units 3&4. The contract with Colstrip Units 1&2 specifies a base price per ton that is subject to adjustment for certain indices and changes in our costs, we are also entitled to receive a reasonable profit. Western Energy’s coal supply agreement with the owners of Colstrip Units 3&4 is a cost-plus arrangement that provides a return on investment on mine assets as well as certain set fees. The owners of Colstrip Units 3&4 also compensate Western Energy under a separate contract for transporting the coal to them on a conveyor belt that Western Energy owns. With some exceptions, the contracts with the owners of the Colstrip Station are full requirements contracts; that is, the Colstrip Units are required to purchase all their coal requirements from or through the Rosebud Mine. The Rosebud Mine also supplies coal to Minnesota Power under a coal supply agreement that expires in 2008. Under this contract, Minnesota Power pays a base price per ton, which will increase in the future by a fixed percentage.

The Jewett Mine’s sole customer is Texas Genco II, L.P., the owner of the two-unit Limestone Electric Generating Station, which has a generating capacity of approximately 1,710 MW and is located adjacent to the mine. The Jewett Mine has supplied the Limestone Station since 1985, when it commenced commercial operations. The Jewett Mine sells lignite to Texas Genco II pursuant to an Amended Lignite Supply Agreement (“ALSA”) that expires in 2015. The ALSA provides for the annual determination of volumes and pricing, with pricing based on an equivalent value of coal from Wyoming’s SPRB, as delivered to and used at the Limestone Station. Texas Westmoreland and Texas Genco II have disputed the proper interpretation of some elements of the ALSA from time to time. In January of 2004, Texas Westmoreland and Texas Genco II settled certain of the disputes between them. Among other things, Texas Genco II committed to purchase approximately 7 million tons of lignite from the Jewett Mine per year during the years 2004 through 2007, and, for that same period, the parties agreed to the price for that lignite.

The Beulah Mine supplies the Coyote Station, which has a generating capacity of approximately 420 MW and is located adjacent to the mine, and the Heskett Station, which has a generating capacity of 100 MW and is located in Mandan, North Dakota, approximately 74 miles from the mine. Coal is shipped to the Heskett Station on the Burlington Northern Santa Fe Railway (“BNSF”). The Beulah Mine has supplied the Coyote Station since 1981, when it commenced commercial operations, and the Heskett Station since 1963. The contract with the Coyote Station expires in 2016. The contract with the Heskett Station expires in 2005, but we have a right of first refusal to renew it for an additional five years. The price of the coal under these contracts is adjusted for certain indices and mine costs, and for the Coyote Station is supplemented by a provision setting forth guaranteed minimum and maximum net income levels. The Beulah Mine’s contracts with the Coyote Station and, with a minor exception, the Heskett Station, are each full requirements contracts.

The Savage Mine supplies coal to the Lewis & Clark Station, which has a generating capacity of approximately 49 MW, and the Sidney Sugars plant, which uses coal from the Savage Mine to heat its boilers and process sugar beets. These facilities are located approximately 20 and 25 miles from the mine, respectively, so that coal can be transported to them economically by on-road truck. The Savage Mine has supplied the Lewis & Clark Station since 1958, when it commenced commercial operations. The Savage Mine’s contracts with the Lewis & Clark Station and the Sidney Sugars plant run until 2007 and 2008, respectively. These contracts, which involve smaller volumes than our other coal supply contracts, are with minor exceptions each full requirements contracts.

The following table shows, for each of the past five years, our coal revenues, the tons sold from mines that we owned at the time of production, the percentage of our coal sales made under long-term contracts, and the weighted average price per ton that we received under these long-term contracts.

Year	Coal Revenues in Dollars ⁽¹⁾ (in 000’s)	Coal Sales in Equivalent Tons (in 000’s)	Percentage of Coal Sales Under Long-Term Contracts	Weighted Average Price Per Ton Received under Long-Term Contracts^(1) (2)
2004	$ 320,291	29,024	98%	$ 11.41
2003	294,986	27,762	99%	10.45
2002	301,235	26,062	100%	11.29
2001	231,048	20,503	99%	11.05
2000	35,137	4,910	100%	7.16

(1)

In 2004, we concluded an arbitration with the owners of Colstrip Units 1&2. The arbitration determined the price we received for coal that we delivered to Colstrip Units 1&2 from July 2001. Our coal revenues for 2004, and the weighted average price per ton received under long-term contracts in 2004, include the entire amount we received pursuant to this arbitration. Excluding the portion of the arbitration award that covered coal that we had previously delivered to Colstrip Units 1&2, we earned coal revenues of $303,396,000 and received a weighted average price of $10.81 per ton under long term contracts in 2004.

(2)	The weighted average price per ton that we received declined from 2002 to 2003 principally because, as anticipated, the Jewett Mine transitioned from cost-plus-fees pricing to a market-based pricing mechanism, effective July 1, 2002.

Our coal revenues include amounts earned by our coal sales company from sales of coal produced by mines other than ours. In 2004, 2003 and 2002, such amounts were $5.8 million, $5.5 million and $6.8 million, respectively.

We consider a contract that calls for deliveries to be made over a period longer than one year a long-term contract. In 2004, our three largest contract customers, the owners of Colstrip Units 1&2, Colstrip Units 3&4 and Texas Genco II, accounted for 16%, 22% and 26%, respectively, of our coal revenues. The Colstrip Units 1&2 revenues included an arbitration award received in 2004 that increased the contract price for tons sold retroactive to July 2001. No other customer or contract accounted for as much as 10% of our coal revenues in 2004. The owners of Colstrip Units 3&4 are Avista Corporation, NorthWestern Corporation, PacifiCorp, Portland General Electric Company, PPL Montana LLC, and Puget Sound Energy, Inc.

As part of our strategy, we seek long-term coal sales contracts. These contracts typically contain price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised. The price may be adjusted in accordance with changes in broad economic indicators, such as the consumer price index; commodity-specific indices, such as the PPI-light fuel oils index; and changes in our actual costs. Contracts may also contain periodic reopeners, like the Colstrip Units 1&2 reopener discussed above, or renewal provisions, which give us the opportunity to adjust the price of our coal.

The following table presents our estimate of the sales under our existing long-term contracts for the next five years. The prices for all of these tons are subject to revision and adjustments based upon market prices, certain indices, and/or cost recovery. We also expect to continue to supply customers whose contracts expire before the end of 2009, but have not included those tonnages in this projection.


Projected Sales Tonnage Under
Existing Long-Term Contracts (in millions of tons)

2005	29.5
2006	28.9
2007	28.7
2008	22.5
2009	20.1

This table reflects existing contracts only and takes into account the scheduled outages at our customers’ plants, where known. We anticipate replacing sales as contracts expire with extensions, new contracts, or spot sales over the life of our coal reserves.

Protecting the Environment

We consider ourselves stewards of the environment. We reclaim the areas that we mine, and we believe that our activities have been in compliance with all federal, state, and local laws and regulations, except as described below for legal proceedings involving Westmoreland Resources.

Our reclamation activities consist of filling the voids created during coal removal, replacing sub-soils and top-soils and then re-establishing the vegetative cover. At the conclusion of our reclamation activities the area disturbed by our mining will look similar to what it did before we mined. Before we are released from all liability under our permits, we will have restored the area where we removed coal to a productive state that meets or exceeds the use of the land before we mined.

We address the impacts our mining operations have on wildlife habitat and on sites with cultural significance. At the Jewett Mine, we preserve the nesting area of the Interior Least Tern, a bird threatened in the region. The Rosebud Mine has altered its mining plan to preserve Native American petroglyphs on rock formations. Similar culturally significant sites have been excavated by trained archeologists. Historic buildings on mine property have been moved to preserve them. We endeavor to operate as good environmental stewards, citizens, and neighbors.

Safety

Safety is our first priority. We maintain active safety programs at all of our mines. Our mines focus on 100% compliance with safe practices, safety rules, and regulations. Based on data from the Mine Safety and Health Administration (“MSHA”), an agency of the U.S. Department of Labor, our mines had a lost-time incident rate of 1.65 in 2004, compared to the national average of 1.88 for surface mines. In 2004, the Jewett Mine had a lost-time incident rate of 0.27 and the Savage Mine had no lost-time incidents. We have taken actions, including incentive programs, to improve the safety records at the Rosebud and Beulah mines.

Independent Power Operations

Through Westmoreland Energy LLC and its direct and indirect subsidiaries, we own interests in three power-generating plants:

•

a 50% interest in the Roanoke Valley I Project, a 180 MW coal-fired plant located in Weldon, North Carolina;

•

a 50% interest in the Roanoke Valley II Project, a 50 MW coal-fired plant also located in Weldon, North Carolina; and

•

a 4.49% interest in the Fort Lupton Project, a 290 MW natural-gas fired plant located in Fort Lupton, Colorado.

We call the Roanoke Valley units ROVA I and ROVA II and both units the ROVA Project. As described below, two of our subsidiaries have agreed to purchase the 50% interest in the ROVA Project that we do not currently own.

The ROVA Project and the Fort Lupton Project are each independent power projects. Independent power projects are power-generating plants that were not built by the regulated utility that purchases the plant’s output.

Each of these projects has a long-term contract with a fuel supplier and a long-term contract with a “steam host,” a business that uses the steam that is generated in the production of power. These projects also have long-term contracts with electric utilities, which purchase the power that the projects generate. The table below presents information about each of our projects.

Project	Roanoke Valley I	Roanoke Valley II	Ft. Lupton
Location	Weldon, North Carolina	Weldon, North Carolina	Ft. Lupton, Colorado
Gross Megawatt Capacity	180 MW	50 MW	290 MW
Our Equity Ownership	50.0%	50.0%	4.49%
Electricity Purchaser	Dominion Virginia Power	Dominion Virginia Power	Public Service of Colorado
Steam Host	Patch Rubber Company	Patch Rubber Company	Rocky Mtn. Produce, Ltd.

Fuel Type	Coal	Coal	Natural Gas
Fuel Supplier	TECO Coal/ CONSOL	TECO Coal/ CONSOL	Thermo Fuels, Inc.
Commercial Operation Commencement Date	1994	1995	1994
Contracts with steam host & electricy purchaser expire in	2019 ⁽¹⁾	2020 ⁽¹⁾	Unit 1 - 2019 Unit 2 - 2009

(1)	The ROVA Project and Dominion Virginia Power can extend these contracts by mutual consent for five-year terms.

Like the power plants to which we sell coal, these projects compete with all other producers of electricity. The ROVA Project is baseloaded. In 2004, ROVA I had a capacity factor of 88% and ROVA II had a capacity factor of 87%. ROVA I produced 1,285,000 megawatt hours (MWh) in 2004; ROVA II produced 340,000 MWh during the year. The Fort Lupton Project is a “peaking” plant. It provides power only when the demand for electricity exceeds the output of baseloaded units.

On August 25, 2004, we signed an Interest Purchase Agreement with a subsidiary of LG&E Energy LLC. We use the term “LG&E” to refer to LG&E Energy LLC and its subsidiaries. In that agreement, we agreed to acquire LG&E’s 50% interest in the ROVA Project for (1) a cash payment to LG&E at closing of approximately $22 million and (2) the assumption by the Company’s subsidiaries of LG&E’s portion of the ROVA project’s debt. LG&E’s share of this debt is approximately $97 million as of January 31, 2005. The purchase price will be reduced by the amount of any distributions LG&E receives between August 2004 and closing. On January 31, 2005, LG&E received a distribution of $4.6 million. In addition, the Company must post cash or letters of credit with a value of approximately $9.8 million to replace LG&E’s portion of the ROVA project’s debt service reserve accounts. In November 2004, Dominion Virginia Power, the purchaser of the electricity generated by the ROVA Project, asserted that the power purchase agreement gives it the right of first refusal with respect to LG&E’s interest. The Company is negotiating with Dominion Virginia Power to address its claim. The Interest Purchase Agreement has not been terminated or amended and remains in effect pending resolution of Dominion Virginia Power’s claim and receipt of the remaining consents necessary to complete the transaction.

Other Activities

As part of our 2001 acquisitions, we obtained the stock of North Central Energy Company (“North Central”). North Central owns property and mineral rights in southern Colorado. In 2003, North Central leased the rights to explore, drill, and produce coalbed methane gas to Petrogulf Corporation for $300,000 and a royalty interest on production from wells drilled on North Central’s properties. Coalbed methane gas is natural gas that occurs in coal beds. Coalbed methane gas typically has a heating value, or Btu content, similar to that of other forms of natural gas and has uses identical to and competes with other forms of natural gas. Commercial production began in early 2004. In 2003, North Central also sold certain surface and mineral property to local land owners for $1.4 million.

We have elected to retain some of the risks associated with operating our company. We have established a wholly-owned, consolidated insurance subsidiary, Westmoreland Risk Management Ltd., which provides our primary layer of property and casualty insurance. By using this insurance subsidiary, we have mitigated the effect of escalating property and casualty insurance premiums and retained some of the economic benefits of our excellent loss record, which has had minimal claims and none since we established the subsidiary in 2002. We have paid premiums at market rates into Westmoreland Risk Management, which as a result has cash reserves of $2.5 million. We reduce our major exposure by insuring for losses in excess of our retained limits with a number of third party insurance companies. Westmoreland Risk Management is a Bermuda corporation. We have elected to report Westmoreland Risk Management as a taxable entity in the United States.

We previously owned a 20% partnership interest in Dominion Terminal Associates (“DTA”), the owner of a coal storage and vessel-loading facility in Newport News, Virginia. We sold our interest in DTA effective June 30, 2003.

Except for the assets of Westmoreland Risk Management, all of our assets are located in the United States. We had no export sales and derived no revenues from outside the United States during the five-year period ended December 31, 2004, except for de minimis sales to a Canadian utility.

Seasonality

Our business is somewhat seasonal:

•

The owners of the power plants to which we supply coal typically schedule maintenance for those plants in the spring and fall, when demand for electric power is typically less than it is during other seasons. For this reason, our coal revenues are usually higher in the winter and summer.

•

The ROVA Project also typically undergoes scheduled maintenance in the spring and fall, so our equity in earnings from independent power is also lower in those seasons.

Government Regulation

Numerous federal, state and local governmental permits and approvals are required for mining and independent power operations. Both our coal mining business and our independent power operations are subject to extensive governmental regulation, particularly with regard to matters such as employee health and safety, and permitting and licensing requirements which cover all phases of environmental protection. The permitting process encompasses both federal and state laws, addressing reclamation and restoration of mined land and protection of hydrologic resources. Federal regulations also protect the benefits for current and retired coal miners.

We believe that our operations comply with all applicable laws and regulations, and it is our policy to operate in compliance with all applicable laws and regulations, including those involving environmental matters. However, because of extensive and comprehensive regulatory requirements, violations occur from time to time in the mining and independent power industries. None of the violations to date or the monetary penalties assessed upon us has been material.

Environmental Laws

We are subject to various federal, state and local environmental laws. Some of these laws, discussed below, place many requirements on our mines and the independent power plants in which we own interests.

Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act of 1977, or SMCRA, which is administered by the Office of Surface Mining Reclamation and Enforcement, or OSM, establishes mining, environmental protection and reclamation standards for all aspects of surface mining. OSM may delegate authority to state regulatory programs if they meet OSM standards. OSM has approved reclamation programs in Montana, North Dakota and Texas, and these states’ regulatory agencies have assumed primacy in mine environmental protection and compliance. Mine operators must obtain permits issued by the state regulatory authority. OSM maintains oversight authority on the permitting and reclamation process. We endeavor to comply with approved state regulations and those of OSM through contemporaneous reclamation, maintenance and monitoring activities. Contemporaneous reclamation is reclamation conducted on a reasonably current basis following the mining of an area.

Each of our mining operations must obtain all required permits before any activity can occur. Under the states’ approved program, an applicant for a permit must address requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation. While there may be some general differences between the states’ SMCRA-approved programs, they are all similar. A permit applicant must supply detailed information regarding its proposed operation including detailed studies of site-conditions before active mining begins, extensive mine plans that describe mining methods and impacts and reclamation plans that provide for restoration of all disturbed areas. The state regulatory authority reviews the submission for compliance with SMCRA and generally engages in a process that involves critical comments designed to ensure regulatory compliance and successful reclamation. When the state is satisfied that the permit application satisfies the requirements of SMCRA, it will issue a permit. To ensure that the required final reclamation will be performed, the state requires the permit-applicant to post a bond that secures the reclamation obligation. The bond will remain in place until all reclamation has been completed.

SMCRA requires compliance with many other major environmental programs. These programs include the Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act or RCRA; and Comprehensive Environmental Response, Compensation, and Liability Acts or CERCLA. Besides OSM, other Federal regulatory agencies are involved in monitoring or permitting specific aspects of mining operations. The EPA is the lead agency for states or Indian Tribes with no authorized programs under the Clean Water Act, RCRA and CERCLA. The U.S. Bureau of Alcohol, Tobacco and Firearms, or ATF, regulates the storage, handling and use of explosives.

Clean Air Act. The Clean Air Act, the 1990 amendments to the Clean Air Act, which we call the Clean Air Act Amendments, and the corresponding state laws that regulate air emissions affect our independent power interests and our mines both directly and indirectly. Direct impacts on coal mining and processing operations may occur through the Clean Air Act’s permitting requirements and/or emission control requirements. The Clean Air Act directly affects the ROVA Project and indirectly affects our mines by extensively regulating the emissions from our customers’ plants into the air of particulates, fugitive dust, sulfur dioxide, nitrogen oxides and other compounds emitted by coal-fired generating plants.

Title IV of the Clean Air Act Amendments places limits on sulfur dioxide emissions from power-generating plants and sets baseline emission standards for these facilities. The affected electricity generators have been able to meet these requirements by, among other ways, switching to lower sulfur fuels, installing pollution control devices, such as flue gas desulphurization systems, which are known as “scrubbers,” reducing electricity generating levels or purchasing sulfur dioxide emission allowances. Power-generating plants receive sulfur dioxide emission allowances each year from the EPA, which the plants may use, trade or sell.

The Clean Air Act Amendments also require power plants that are major sources of nitrogen oxides in moderate or higher ozone non-attainment areas to install reasonably available control technology for nitrogen oxides, which are precursors of ozone. In addition, the EPA promulgated final rules that would require coal-burning power plants in 19 eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions beginning in May 2004. Installation of additional control measures required under the final rules will make it more costly to operate coal-fired generating plants. We discuss these rules below in more detail in the context of the ROVA Project.

Clean Water Act. The Clean Water Act of 1972 affects coal mining operations by establishing the National Pollutant Discharge Elimination System, or NPDES, which sets standards for in-stream water quality and treatment for effluent and/or waste water discharges. Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water. States are also adopting anti-degradation regulations in which a state designates certain water bodies or streams as “high quality.” These regulations would prohibit the diminution of water quality in these streams. Waters discharged from coal mines to high quality streams will be required to meet or exceed new high quality standards. The designation of high quality streams at our coal mines could require more costly water treatment and could aversely affect our coal production. We believe that all of our mines are in compliance with current discharge requirements.

Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, which was enacted in 1976, affects coal mining operations by establishing requirements for the treatment, storage and disposal of hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management. The EPA has also exempted coal combustion wastes from hazardous waste management under RCRA. Although coal combustion wastes disposed in surface impoundments and landfills or used as mine-fill are subject to regulation as non-hazardous wastes under RCRA, we do not anticipate that the regulation of coal combustion wastes will have any material effect on the amount of coal used by electricity generators so long as the EPA continues to exempt coal combustion wastes from hazardous waste management.

New Environmental Rules

Environmental laws and regulations are subject to change. In March 2005, the EPA adopted new rules that affect airborne emissions. Because different types of coal vary in their chemical composition and combustion characteristics, the new regulations could alter the relative competitiveness among coal suppliers and coal types.

Clean Air Interstate Rule. In the Clean Air Interstate Rule, or CAIR, the EPA required that 28 eastern states and the District of Columbia reduce emissions of sulfur dioxide and nitrogen oxide. The EPA asserts that, when fully implemented, the CAIR will reduce sulfur dioxide emissions in these states by over 70 percent and nitrogen oxide emissions in those states by over 60 percent from 2003 levels. The CAIR covers the states in which the ROVA Project, the principal customers of the Jewett and Absaloka Mines, and one of the customers of the Rosebud Mine are located. According to the EPA, states will achieve the required emissions reductions using one of two options for compliance:

•

A state may require power plants to participate in an EPA-administered interstate cap and trade system that caps emissions in two stages, or

•

A state may meet an air emission budget specific to it through measures of the state’s choosing.

The EPA adopted the CAIR on March 10, 2005. We have not had adequate time to study the final rule and so are unable to determine how it will affect our business.

Mercury Rule. The EPA issued regulations pertaining to airborne emissions of mercury from power plants, known as the Mercury Rule, on March 15, 2005. We will not have had an opportunity to study this rule prior to filing of this Form 10-K and therefore are unable to determine how it could affect the coal industry and our business.

Health and Benefits

Mine Safety and Health. Congress enacted the Coal Mine Health and Safety Act in 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. The states in which we operate have programs for mine safety and health regulation and enforcement. Our safety activities are discussed above.

Black Lung. Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973.

Coal Act. As discussed in more detail below, the Coal Industry Retiree Health Benefit Act imposes substantial liabilities and costs on us.

Workers’ Compensation. We are subject to various state laws where we have or previously had employees to provide workers’ compensation benefits. We were self-insured prior to and through December 31, 1995. Beginning in 1996, we purchased third party insurance for new workers’ compensation claims.

Independent Power

Many of the environmental laws and regulations described above, including the Clean Air Act Amendments, the Clean Water Act and RCRA, apply to our independent power plants as well as to our coal mining operations. These laws and regulations 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 operators of the ROVA and Fort Lupton Projects are responsible 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, which we call the Section 126 rule. The Section 126 rule requires combined nitrogen oxide reductions of 510,000 tons during each annual ozone season (May 1 — September 30) from specified power stations in the eastern United States, including the ROVA Project. The rule responds to petitions filed by several northeastern states under Section 126 of the Clean Air Act and seeks to control nitrogen oxide emissions that the petitioning states allege prevent them from attaining the ambient air quality standards for ozone. Each source is assigned a nitrogen oxide emissions allocation, and sources can reduce emissions to meet the allocation or purchase allowances.

North Carolina has adopted regulations that require compliance with the new nitrogen oxide limits beginning in June 2004.

The ROVA Project continues to evaluate strategies for complying with the Section 126 rule. In 2000, the ROVA Project installed a neural network in its boilers. The neural network increases boiler efficiency and reduces nitrogen oxide and carbon monoxide emissions. While the neural network reduces the level of nitrogen oxide and carbon monoxide emissions from the ROVA Project, the project’s operator is evaluating additional compliance strategies, including installation of additional pollution control equipment and/or emissions trading.

Employees

Including our subsidiaries, we directly employed 943 people on December 31, 2004, compared with 919 people on December 31, 2003. Westmoreland Coal Company is not party to any agreement with the United Mine Workers of America (“UMWA”), and its last agreement with the UMWA expired on August 1, 1998. However, our Western Energy subsidiary is party to an agreement with Local 400 of the International Union of Operating Engineers (“IUOE”). In addition, our Dakota Westmoreland and Westmoreland Savage subsidiaries assumed agreements with Local 1101 of the UMWA and Local 400 of the IUOE, respectively, when we purchased Knife River’s assets.

Information about Segments

Please refer to Note 12 of the Consolidated Financial Statements for additional information about the segments of our business.

Available Information

Our Internet address is www.westmoreland.com. We do not intend for the information on our website to constitute part of this report. We make available, free of charge on or through our Internet website, our 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 Securities Exchange Act of 1934, as amended (“Exchange Act”), as soon as reasonably practicable after we file those materials electronically with, or furnish them to, the Securities and Exchange Commission.

ITEM 2

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PROPERTIES

We operate mines in Montana, Texas, and North Dakota. All of these mines are surface (open-pit) mines. These 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. 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 work. This coal does not qualify as a “coal reserve” until, among other things, we conduct a final comprehensive evaluation based upon unit cost per ton, recoverability, and other material factors and conclude that it is legally and economically feasible to mine the coal.

We include in “coal reserves” 195.5 million tons that are not fully permitted but that otherwise meet the definition of “coal reserves.” Montana, Texas, and North Dakota each use a permitting process approved by the Office of Surface Mining. We describe the permitting process above in Item 1, under “Governmental Regulation,” and we explain our assessment of that process as applied to these unpermitted tons below.

All of our final reclamation obligations are secured by bonds as required by the respective state agencies. Payment of the actual cost of the major portion of final reclamation is the responsibility of third parties. Contemporaneous reclamation activities are performed at each mine in the normal course of operations and coal production.

The following table provides information about our mines as of December 31, 2004.

	Absaloka Mine	Rosebud Mine	Jewett Mine	Beulah Mine	Savage Mine
Owned by	Westmoreland Resources, Inc.	Western Energy Company	Texas Westmoreland Coal Co.	Dakota Westmoreland Corporation	Westmoreland Savage Corporation
Location	Big Horn County, MT	Rosebud and Treasure Counties, MT	Leon, Freestone and Limestone Counties, TX	Mercer and Oliver Counties, ND	Richland County, MT
Coal Reserves (thousands of tons) Proven (1) Probable (3)	47,097(2) 64,800	221,730(2) 0	84,976 0	37,036(2) 3,815	12,525(2) 4,008
Permitted Reserves (thousands of tons)	21,500	142,287	84,976	27,683	3,925
Coal Deposits (thousands of tons)(4)	565,228	280,000	0	0	0
2004 Production (thousands of tons)	6,488	12,655	6,453	3,053	375
Lessor	Crow Tribe	Federal Govt; State of MT; Great Northern Properties	Private parties	Private parties; State of ND; Federal Govt	Federal Govt; Private parties
Lease Term	Through exhaustion	varies	varies	2009-2019	varies
Curent production capacity (millions of tons)	7	13	7	4	0.4
Coal Type	Sub-bituminous	Sub-bituminous	Lignite	Lignite	Lignite
Acres disturbed by mining	3,714	15,255	13,807	4,355	506
Acres for which reclamation is complete	2,563	6,969	9,979	2,978	209
Major Customers	Xcel Energy, Western Fuels Assoc., Midwest Energy	PPL Montana, Puget Sound, Portland General, Avista, Pacificorp, Minnesota Power	Texas Genco II	Otter Tail, MDU, Minnkota, Northwestern Public Service	MDU, Sidney Sugars
Delivery Method	Rail	Truck / Rail / Conveyor	Conveyor	Conveyor / Rail	Truck
Approx. Heat Content (BTU/lb.) (5)	8,700	8,529	6,471	7,004	6,371
Approx. Sulfur Content (%) (6)	0.65	0.74	1.00	1.04	0.45
Year Opened	1974	1975(7)	1985	1963	1958
Total Tons Mined Since Inception (millions of tons)	135	359	147	85	12.4

(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 we have committed to operating mining equipment and plant facilities.

(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)	We have assigned all coal deposits to operating mining equipment and plant facilities.
(5)	Approximate heat content applies to the coal mined in 2004.
(6)	Approximate sulfur content applies to the tons mined in 2004.
(7)	Initial sales from the current mine complex began in 1975. Mining first occurred at the site in 1924.

We lease all our coal properties except at the Jewett Mine, where some reserves are controlled through fee ownership. We believe that we have satisfied all conditions that we must meet in order to retain the properties and keep the leases in force.

Absaloka Mine

Our Westmoreland Resources subsidiary began constructing the mine in late 1972. Construction was completed in early 1974. Westmoreland Resources has been the mine’s only owner.

The Absaloka Mine’s primary excavating machine (completed in 1979) is a dragline with a bucket capacity of 110 cubic yards. Westmoreland Resources owns the dragline. The Absaloka Mine’s facilities consist of a truck dump, primary and secondary crushers, conveyors, coal storage barn, train loadout, rail loop, shop, warehouse, boiler house, deep well and water treatment plant, and other support facilities. These facilities date from the construction of the mine. Westmoreland Resources’ mining contractor and minority stockholder owns most of the other equipment at the mine.

We believe that all the coal reserves and coal deposits shown in the table above for the Absaloka Mine are recoverable through the Absaloka Mine’s existing facilities with current technology and the existing infrastructure. These reserves and deposits were estimated to be 799.8 million tons as of January 1, 1980, based principally upon a report by IntraSearch, Inc., an independent firm of consulting geologists, prepared in February 1980.

Westmoreland Resources leases all of its remaining coal reserves and coal deposits from the Crow Tribe of Indians. The lease runs until exhaustion of the mineable and merchantable coal in the acreage subject to the lease. In February 2004, Westmoreland Resources reached an agreement with the Crow Tribe to explore and develop additional acreage located on the Crow reservation immediately adjacent to the Absaloka Mine. This agreement was approved by the U.S. Department of the Interior in September 2004 and the initial exploration core drilling was completed by year-end in order to fully prove the coal deposits.

Washington Group is contractually responsible for reclaiming the Absaloka Mine, whatever the cost, except for $1.7 million, which is the responsibility of Westmoreland Resources and has been fully funded through annual installments made from 1991 through 2005. Washington Group is also contractually obligated to fund a reclamation escrow account or post security for its reclamation obligation. After reclamation is complete, Westmoreland Resources is responsible for maintaining and monitoring the reclaimed property until the release of the reclamation bond. Westmoreland Resources estimates that it will cost $2.1 million to maintain and monitor the property that it had mined through December 31, 2004 until the reclamation bond for that property is released.

Of the 111.9 million tons shown for the Absaloka Mine in the table above as proven and probable coal reserves, 90.4 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” Westmoreland Resources has chosen to permit coal reserves on an incremental basis and currently has sufficient permitted coal to meet production, given the current rate of mining and demand, through 2007. In Montana, the Department of Environmental Quality (DEQ) regulates surface mining and issues mining permits under its OSM-approved program. In Montana, it typically takes two to four years from the time an initial application is filed to obtain a new permit. Westmoreland Resources filed an application with DEQ covering an estimated 25 million tons of unpermitted reserves in June 2004, expanding the mine into Tract III South. The application was deemed administratively complete by DEQ in November 2004. Based upon the current status of this application, and our knowledge of the permitting process in Montana and the Absaloka Mine’s reserves, we expect to receive final approval by mid-2006, as required to meet production requirements.

The operator of the Absaloka Mine purchases electric power under a long-term contract with Northwestern Energy, the local utility. The mine is accessed from Route 384 via County Road 42.

Rosebud Mine

The Northern Pacific Railroad began mining coal for its steam locomotives at Colstrip in 1924 and continued to do so until 1958. In 1959, the Montana Power Company purchased the property. Montana Power formed Western Energy Company in 1966 and began selling coal to customers in 1968. Construction of Colstrip Station began in 1975. The long-term contracts required for this plant provided the foundation for a major expansion of the Rosebud Mine. We acquired the stock of Western Energy in 2001.

The Rosebud Mine’s primary excavating machines are four draglines, three with bucket-capacities of 60 cubic yards, purchased in 1975, 1976, and 1980, and one with a bucket-capacity of 80 cubic yards, purchased in 1983. The Rosebud Mine’s facilities consist of truck dumps, crushing, storage, and conveying systems, a rail loadout, rail loop, shops, warehouses, and other support facilities. These facilities date from 1974.

We estimate that the Rosebud Mine had coal reserves of 221.7 million tons as of December 31, 2004. This estimate is based on a study of the Rosebud Mine’s reserves dated October 31, 2003 conducted by Western Energy and adjusted for tons mined since that date. We estimate that the Rosebud Mine had coal deposits of approximately 280 million tons at the end of 2004. This estimate is based on a study of the reserves at the Rosebud Mine dated September 28, 1994, prepared by the Environmental and Engineering Department of Western Energy while it was owned by Montana Power. This study was updated by the Rosebud Mine’s engineering staff in 2003. Our estimate is also based in part on a lease with the U.S. Department of the Interior that Western Energy obtained in 1999. We believe that all of these reserves are recoverable through the Rosebud Mine’s existing facilities with current technology and the existing infrastructure.

We are responsible for performing reclamation activities at the Rosebud Mine. The owners of the Colstrip Station are responsible for paying the costs of reclamation relating to mine areas where its coal supply is produced, which is approximately 63% of the estimated total cost of final reclamation for the Rosebud Mine. Certain owners have satisfied these obligations by prefunding their respective portions of those costs.

Of the 221.7 million tons shown for the Rosebud Mine in the table above as proven coal reserves, 78.9 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” Western Energy 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. Based upon our current knowledge of the nature of the remaining reserves and the permitting process in Montana, we believe that there are no matters that would hinder Western Energy’s ability to obtain additional mining permits in the future.

The Rosebud Mine purchases electric power from NorthWestern Energy under regulated default supply pricing. Access to the mine is from Highway 39 via Castle Rock Road.

Jewett Mine

Development of the Jewett Mine began in 1979, when Northwestern Resources Co. and Utility Fuels, Inc. signed an agreement calling for production of “the most economic 240 million tons” from the project area to supply the planned Limestone Station. The coal deposit was evaluated through a series of exploration programs, including physical and chemical analysis, according to predetermined criteria. The Jewett Mine has been in continuous operation since 1985 and consists of five active areas with as many as four lignite seams within each area. Since 1979, ownership of the Limestone Station has been transferred several times, most recently to Texas Genco II. We acquired the stock of Northwestern Resources in 2001 and renamed the company Texas Westmoreland in 2004.

The Jewett Mine’s primary excavating machines consist of three walking draglines, each with a bucket-capacity of 84 cubic yards, one walking dragline with a bucket-capacity of 128 cubic yards, and one bucketwheel excavator. The Jewett Mine’s facilities consist of a truck dump, crusher, conveyors, coal storage, shop/warehouse complex, administrative support buildings, and water treatment facilities. These facilities date from the construction of the mine. Texas Genco II owns the draglines, the bucketwheel and other mobile equipment used to extract lignite and provides this equipment to Texas Westmoreland without charge. Texas Westmoreland is obligated to maintain the draglines and all other plant and equipment so that they continue to be serviceable and support production comparable to the original specifications.

Exploration work for the mine commenced in the late 1970s, and Texas Westmoreland’s geologists and engineers prepared the initial estimates of the mine’s reserves at a time when Montana Power owned the Jewett Mine. To further define the coal reserve, exploration drilling was utilized to delineate that part of the deposit that could economically be mined. Additional drilling has been conducted from time to time to further define the limits of the coal seams. As of December 31, 2004, all planned exploration is complete. We believe that all the Jewett Mine’s coal reserves are recoverable through its existing facilities with current technology and the existing infrastructure.

Final reclamation of the Jewett Mine, at the end of its useful life, is the financial responsibility of its customer.

The Railroad Commission of Texas, or RCT, regulates surface mining in Texas and issues mining permits under its OSM-approved program. In Texas, it typically takes eighteen months to two years from the time an initial application is filed to obtain a new permit. A permit term encompasses five years of mining. The Jewett Mine currently holds two mining permits, 32F and 47. Permit number 32F is a renewal of the original mining permit that has been in place and actively mined since the mine opened in 1985. This permit is valid through July 2008. Permit number 47 was issued in December 2001 and has a term that runs through December 2006.

The Jewett Mine purchases electric power from the Brazos River Authority and Navasota Valley Electric Cooperative. The mine may be accessed on Farm to Market Road 39.

Beulah Mine

Knife River Corporation began producing lignite at the Beulah Mine in 1963. The mine has two working areas, the West Brush Creek area and the East Beulah area. We purchased the assets of the Beulah Mine from Knife River in 2001.

On January 31, 2005, we signed an option to lease reserves in the South Beulah area. Initial drilling and mine plans have been completed. We have six months to complete detailed mine plans and diligence. The South Beulah reserves have improved quality, lower sodium and lower strip ratios than the existing mine areas. (The strip ratio is a measure of the overburden that must be removed to allow the extraction of coal; a strip ratio of 10:1 means that 10 cubic yards of overburden must be removed to permit the extraction of one ton of coal.)The owners of the Coyote Station have agreed to include the acquisition costs and development capital in the cost base under the Coyote contract.

The Beulah Mine’s primary excavating machines are a dragline with a bucket-capacity of 17 cubic yards, constructed in 1963, which operates in the West Brush Creek area, and a dragline with a bucket-capacity of 84 cubic yards, constructed in 1980, which removes overburden at East Beulah. The Beulah Mine’s facilities consist of a truck dump hopper, primary and secondary crushers, conveyors, train loadout, railroad spur, coal storage bin, and coal stockpile. The support facilities include several maintenance shops, equipment storage buildings, warehouse, employee change houses, and mine office and trailers. These facilities date from 1963 and have been replaced consistent with normal industry practices.

The Beulah Mine’s engineering staff has estimated the mine’s reserves and updated the reserves annually, adjusted for tons mined. We estimate that the total owned and leased coal reserves at the Beulah Mine were approximately 40.9 million tons at December 31, 2004. We believe that all of these reserves are recoverable through the Beulah Mine’s existing facilities with current technology and the existing infrastructure.

We are responsible for reclaiming the Beulah Mine and paying the cost of our reclamation obligations.

Of the 40.9 million tons shown for the Beulah Mine in the table above as proven and probable coal reserves, 13.2 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” Of the total reserves shown, approximately 4.2 million tons in the West Brush Creek area and 23.5 million tons at East Beulah are fully permitted at this time. Based on the current estimated production rates of 500,000 and 2.5 million tons respectively, there are roughly seven and nine years, respectively, remaining under the current permitted mine plans. North Dakota Public Service Commission regulates surface mining in North Dakota and issues mining permits under its OSM-approved program. In North Dakota, it typically takes one to two years from the time an initial application is filed to obtain a new permit. Based on our current knowledge of the permitting process in North Dakota and the environmental issues associated with these reserves, we believe that there are no matters that would hinder our ability to obtain any mining permits in the future.

The Beulah Mine purchases electric power from MDU. The mine is accessed from North Dakota Highway 49.

Savage Mine

Knife River began producing lignite at the Savage Mine in 1958. We purchased the assets of the Savage Mine from Knife River in 2001.

The Savage Mine’s primary excavating machine is a walking dragline with a bucket-capacity of 12 cubic yards. The Savage Mine’s facilities consist of a truck dump, near-pit crushing unit, conveyors, and coal stockpile; support facilities include a shop, warehouse, and mine office. These facilities date from 1958 and have been replaced consistent with normal industry practices. The processing facilities were constructed in 1996. The facilities were modified and upgraded in 2001.

We estimate that the total owned and leased coal reserves at the Savage Mine were approximately 16.5 million tons at December 31, 2004. These reserves were estimated as of January 1, 1999, based principally upon a report prepared by Weir International Mining Consultants, an independent consulting firm, and updated by our engineering staff in 2004. We believe that all of these reserves are recoverable through the Savage Mine’s existing facilities with current technology and the existing infrastructure.

We are responsible for reclaiming the Savage Mine and paying the cost of our reclamation obligations.

Of the tons shown for the Savage Mine in the table above as coal reserves, approximately 3.9 million tons are fully permitted at this time and 12.6 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” We have chosen not to permit all of the coal reserves in the Savage Mine’s plan because the mine already has sufficient coal in its current permitted mine plan given the current rate of mining and demand for its production through 2014. Based upon our current knowledge of the nature of the remaining reserves and the permitting process in Montana, we believe that there are no matters that would hinder our ability to obtain additional mining permits at the Savage Mine in the future.

The Savage Mine purchases electric power from MDU. The mine is accessed from Montana Highway 16 via County Road 107.

Other

Refer to Note 2 to our Consolidated Financial Statements for a description of Westmoreland Energy's properties.

ITEM 3

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LEGAL PROCEEDINGS

We are party to legal proceedings. We have presented the proceedings below based on the name of the Westmoreland entity that is party to the proceeding. We are vigorously contesting each of these proceedings.

Legal proceedings involving Westmoreland Coal Company

Combined Benefit Fund Litigation

Under the Coal Act, we are required to provide postretirement medical benefits for certain UMWA miners and their dependents by making premium payments into benefit plans, including the UMWA Combined Benefit Fund (“Combined Fund”). The amount we pay is a function of the number of individuals for which we must make payment – “assigned beneficiaries” – and the assessment rate. We and many other coal companies are now litigating in the U.S. District Court for the District of Maryland to determine the proper assessment rate.

In 1995, the U.S. District Court for the Northern District of Alabama held that the assessment rate under the Coal Act included the actual amount of money reimbursed to the UMWA Benefit Plans by the Health Care Financing Administration (“HCFA”). The court’s decision resulted in a lower premium obligation. In 1996, the U.S. Court of Appeals for the 11th Circuit upheld the district court’s decision. The Social Security Administration (“SSA”), which now makes these assessments, proceeded to comply with the decision and applied the assessment that yielded a lower premium to all coal companies.

In 1996, the Trustees of the Combined Fund filed suit in the U.S. District Court for the District of Columbia seeking to have the Alabama decision set aside. In November 2002, the U.S. District Court held that the provisions of the Coal Act that the Alabama court had reviewed were ambiguous and directed the SSA to explain why it had applied the Alabama decision to all coal companies, rather than just the participants in the Alabama litigation. On June 10, 2003, the SSA notified the court that it could not locate any record that would explain why it decided to apply the 1996 Alabama decision nationwide but assumed that decision was based on fairness and ease of administration for the SSA. After the June 10 letter, the SSA began to use the methodology that resulted in higher assessments for all coal companies except those party to the Alabama litigation. The Trustees of the Combined Fund notified us that we would be required to pay higher premiums and assessed a “retroactive premium” that represented the amount that we would have paid if the methodology that yields the higher premium had been used since 1995. The amount of the retroactive premium was $4.7 million, payable over the twelve months commencing October 2003. The net effect of these assessments increased our monthly payments to the Combined Fund from less than $400,000 to $859,000 for the twelve months ending October 2004.

On July 16, 2003, we and other companies with obligations to the Combined Fund filed a complaint in the U.S. District Court for the Northern District of Alabama that sought to prevent the increased assessment and retroactive assessment from taking effect. On September 10, 2003, the Trustees of the Combined Fund filed suit in the U.S. District Court for the District of Columbia. The Trustees sought to confirm that all coal companies not party to the 1996 Alabama litigation are obligated to pay the newly calculated, higher premium, as determined by the SSA on June 10, 2003.

The Trustees of the Combined Fund sought to transfer the Alabama litigation to the District of Columbia. In October 2003, the U.S. District Court for the Northern District of Alabama held that venue was proper in Alabama but transferred the case to the U.S. District Court in Baltimore, Maryland, where the SSA is headquartered. In February 2004, the U.S. District Court for the District of Columbia transferred the Trustees’ suit to Baltimore. The parties have completed discovery and in December 2004 filed cross motions for summary judgment on the question whether the Alabama decision should be applied to all coal companies. This issue has been briefed and we are awaiting the court’s decision.

Purchase Price Adjustment

We purchased Montana Power’s coal business from its subsidiary Entech in April 2001. The final purchase price is subject to adjustment. Under the Stock Purchase Agreement with Entech, the purchase price was to be adjusted as of the date the transaction closed, to reflect the net assets of the business on the closing date and the net revenues that the business earned between January 1, 2001 and the closing date. In June 2001, Entech proposed adjustments that would increase the purchase price by approximately $9.0 million. In July 2001, we objected to Entech’s adjustments and proposed our own adjustments. Our proposal would result in a substantial decrease in the purchase price. The Stock Purchase Agreement requires that the parties’ disagreements be submitted to an independent accountant for resolution. Because some of our claims involved breaches of the representations and warranties in the Stock Purchase Agreement, we also submitted a timely claim for indemnification.

Litigation in the New York courts ensued. That litigation culminated in a decision by the New York Court of Appeals, New York’s highest court, on July 1, 2003, which held that many of the Company’s objections should be treated as claims for a breach of a representation or warranty for which the exclusive remedy was an action at law. On June 18, 2003, Touch America Holdings, Inc. (formerly Montana Power Company) and Entech LLC (formerly Entech Inc.) filed bankruptcy petitions in the U.S. Bankruptcy Court in Delaware. The bankruptcy code automatically stays pending litigation against Montana Power and Entech and prevents us and others from commencing new actions against them outside the Bankruptcy Court. As a result, our prosecution of the purchase price adjustment litigation is now stayed. We have filed appropriate proofs of claim with the Bankruptcy Court.

On March 16, 2004, we received notice that Entech and Touch America Holdings had initiated an adversary proceeding against us in the U.S. Bankruptcy Court in Delaware. The complaint re-asserted Entech’s proposed adjustments to the purchase price and alleged that Westmoreland was holding approximately $9 million that is the property of the estates of Touch America and Entech. By stipulation dated September 9, 2004, Westmoreland, Touch America, and Entech agreed to refer the purchase price adjustment issues to an independent accountant as provided in the Stock Purchase Agreement. We also agreed which of our objections to Entech’s closing certificate were to be resolved by the independent accountant and which should be resolved by the U.S. District Court in Delaware as claims for breaches of the representations and warranties in the Stock Purchase Agreement. The stipulation further provided that neither party would seek to recover any monetary award from the other until both the independent accountant proceeding and breach of representation and warranty case had concluded. In November 2004, the independent accountant issued a revised closing date certificate which reflected a small adjustment in Westmoreland’s favor. Entech promptly filed a request for reconsideration by the independent accountant. The Entech request for reconsideration has not been decided and the ultimate outcome of the independent accountant proceeding is still uncertain. Our claims against Entech for breach of representations and warranties have been set for trial in October 2005. At the conclusion of this litigation, the bankruptcy court will determine the priority of any claim by Westmoreland and whether any judgment obtained by Westmoreland can be offset against any judgment obtained by Entech. At this time, the outcome of this litigation is uncertain.

McGreevey Litigation

In mid-November, 2002, we were served with a complaint – the plaintiffs’ Fourth Amended Complaint – in a case styled McGreevey et al. v. Montana Power Company et al. The complaint was filed on October 4, 2002 in a Montana State court. The plaintiffs are former stockholders of Montana Power who filed their first complaint on August 16, 2001. The Fourth Amended Complaint added us as a defendant to a suit against Montana Power, various officers of Montana Power, the Board of Directors of Montana Power, financial advisors and lawyers representing Montana Power, and the purchasers of some of the businesses formerly owned by Montana Power and Entech. The plaintiffs seek to rescind Montana Power’s sale of its generating, oil and gas, and transmission businesses, and Entech’s sale of its coal business. The plaintiffs contend that they were entitled to vote to approve the sale by Entech to the Company even though they were not shareholders of Entech. Alternatively, they seek to compel the purchasers, including us, to hold these businesses in trust for them. We filed an answer, affirmative defenses, and a counterclaim against the plaintiffs.

The litigation was transferred to the U.S. District Court in Billings, Montana. On July 12, 2004, the plaintiffs filed a status report with the U.S. District Court. In the status report, the plaintiffs stated that the insurance companies that insure the former officers and directors of Montana Power had agreed to pay $67 million into escrow, pending approval of a settlement agreement and a determination by the bankruptcy court that no other claimant or class of claimants is entitled to any portion of the settlement proceeds. As part of the proposed settlement, the McGreevey plaintiffs would dismiss their claims against us and our subsidiaries, among others. The parties continue to negotiate the terms of the proposed settlement.

Legal proceedings involving Westmoreland Coal Company and/or Westmoreland Energy

The ROVA Project is located in Halifax County, North Carolina and is the County’s largest taxpayer. In 2002, the County hired an independent consultant to review and audit property tax returns for the previous five years. In May 2002, the County advised the ROVA Project that its returns were being scrutinized for potential underpayment and undervaluation of the property subject to tax. The ROVA Project responded that its valuation was consistent with an agreement reached with the County in 1996. On November 5, 2002, the County assessed the ROVA Project $4.6 million for the years 1997 to 2001. Since that date the County has increased the amount of its claim to $5.3 million, which includes tax years 1996, 2002 and 2003. With penalty and interest, the total amount claimed due by the County is $8.3 million. The ROVA Project filed a protest with the Property Tax Commission. On May 26, 2004, the Tax Commission denied the ROVA Project’s protest and issued an order consistent with the County’s assessment. The ROVA Project appealed the Tax Commission’s decision to the North Carolina Court of Appeals on June 24, 2004. LG&E, the Company’s 50% co-owner of ROVA, has agreed that, if we complete the acquisition of their interest in ROVA as described in “Item 1 – Business Independent Power Operations”, LG&E will indemnify the ROVA Project for one-half of the taxes, penalties, and interest assessed by Halifax County for the period through December 31, 2003 and for one-half of our reasonable attorneys’ fees and expenses incurred in settling or otherwise resolving Halifax County’s claims for this period.

Niagara Mohawk Power Corporation (“NIMO”) was party to power purchase agreements with independent power producers, including the Rensselaer project, in which we owned an interest. In 1997, the New York Public Service Commission approved NIMO’s plan to terminate or restructure 29 power purchase contracts. The Rensselaer project agreed to terminate its Power Purchase and Supply Agreement after NIMO threatened to seize the project under its power of eminent domain. NIMO and the Rensselaer project executed a settlement agreement in 1998 with a payment to the project. On February 11, 2003, the North Carolina Department of Revenue notified us that it had disallowed the exclusion of gain from the settlement agreement between NIMO and the Rensselaer project. The State of North Carolina has assessed a current tax of $3.5 million, interest of $1.3 million (through 2004), and a penalty of $0.9 million. We have filed a protest. The North Carolina Department of Revenue held a hearing on May 28, 2003. In November 2003, we submitted further documentation to the State to support our position. On January 14, 2005, the North Carolina Department of Revenue concluded that the additional assessment is statutorily correct. We are currently evaluating our options, which include requesting a formal hearing and appealing the decision to the Superior Court of North Carolina, before responding to the North Carolina Department of Revenue.

Legal proceedings involving Basin Resources, Inc.

Landowner Claim

In 1998, Basin paid a landowner $48,000 to settle a claim that Basin’s operations had caused subsidence that damaged his home. On March 22, 2001, the landowner filed a second claim, in Las Animas County Court, Colorado, again alleging that Basin’s operations had caused subsidence that damaged his home. Basin contested this claim. In December 2002, a judge of that court determined that subsidence had occurred and awarded the landowner damages of $622,000 plus attorney’s fees. We believe that this award is excessive, in part because the landowner’s own expert placed the cost of repair below $100,000. We also believe that the settlement in the first case bars the second claim. We have appealed the case to the Colorado Intermediate Court of Appeals.

Legal proceedings involving Westmoreland Coal Company, Westmoreland Resources, and/or Western Energy

We have received demand letters from the Montana Department of Revenue, as agent for the Minerals Management Service (“MMS”) of the U.S. Department of the Interior, asserting underpayment of royalties allegedly due from the Rosebud Mine. The claims relate to the fees Western Energy receives to transport coal from the contract delivery point to the customer. The DOR has also asserted claims against us based on certain “take or pay” payments Western Energy received when its customers did not require coal. Finally, the DOR has asserted claims against us and our subsidiaries for adjustments for Montana severance taxes, coal resources indemnity trust tax, and coal gross proceeds tax. These assessments are dated September 23 and 24, 2002. The total amount of the claims is approximately $15.5 million, including penalties and interest, which continues to accrue. We continue to receive transportation fees. We expect that the DOR will assert claims for additional underpayment and issue more demand letters until we have completed the appeal process. The appeal process will take several years. In the event of a negative outcome with the DOR and MMS, we believe that certain of our customers are contractually obligated to reimburse us for any claims we pay, plus our legal expenses and we have put them on notice of their obligation.

On October 1, 2004, the Montana Department of Environmental Quality (“DEQ”) issued a Determination of Patterns of Violations and Order to Show Cause (“Determination and Order”) to Westmoreland Resources, Inc. (“WRI”). In the Determination and Order, DEQ stated that a series of violations had been committed by failing to properly maintain blasting records on two occasions, conducting blasts outside the geographic limits specified in published blasting schedules, violating regulations governing the control of sediment and violating regulations governing the handling of top soil. This notice was directed to WRI, the owner and therefore permittee of the Absaloka Mine near Hardin, Montana. Washington Group International (“WGI”) is the contract operator of the Absaloka Mine and as such is functionally responsible for compliance with these regulations. The DEQ directed WRI, as the permittee, to show cause why its permit should not be suspended for a term of six days. WRI contested the Determination and Order contending that issuance of the show cause was not proper and that WRI had already undertaken affirmative corrective steps that were designed to prevent future violations. WRI also immediately opened negotiations with the DEQ to resolve the issue. In December 2004, the Director of the DEQ made a determination that WRI, through its affirmative plan, had demonstrated the permit should not be suspended and no monetary penalty should be assessed. WRI is finalizing an agreement with the DEQ on the terms of an “Administrative Order of Consent” that requires an independent practices review of WRI and WGI’s mine operations. Following the review, both WRI and WGI will implement recommended steps to enhance regulatory compliance through training and improved communication. It is expected that the final order will not require either a suspension of mining or a monetary fine.

Following receipt of the Determination and Order, WRI notified WGI that WGI had breached its obligations under both the laws of the State of Montana and the mining contract between WRI and WGI. On November 22, 2004, WGI filed suit in the U.S. District Court in Denver, Colorado seeking a judicial determination that it had not breached the mining contract. WRI has filed its answer and seeks a ruling permitting WRI to terminate the contract. The case is in the very early stages and, at this time, it is impossible to predict the outcome.

Pursuant to Section 6 of the mining contract between WRI and WGI, if the parties are unable to agree on a price to mine additional reserves located adjacent to the existing Absaloka Mine (“Tract #3 Reserves”), then such price is subject to arbitration by a three member panel. On October 22, 2004, WRI submitted to WGI an Arbitration Demand Regarding Unpermitted Areas of Tract #3 under Section 6 of the agreement. The arbitration is in the preliminary stages and the parties are in the process of seeking agreement on the composition of the arbitration panel.

Other

In the ordinary course of our business, we and our subsidiaries are party to other legal proceedings that are not material.

ITEM 4

–

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matter was submitted to a vote of the Company's stockholders during the fourth quarter of 2004.

Executive Officers of the Registrant

The following table shows the executive officers of the Company, their ages as of March 1, 2005, 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


Christopher K. Seglem ⁽¹⁾	58	Chairman of the Board,	1996
		President and	1992
		Chief Executive Officer	1993

Robert W. Holzwarth ⁽²⁾	57	Senior Vice President, Power	2004

W. Michael Lepchitz ⁽³⁾	51	Vice President, General Counsel	2000
		and Secretary	2001

Ronald H. Beck ⁽⁴⁾	60	Vice President - Finance and Treasurer,	2001
		Acting Chief Financial Officer


Thomas G. Durham ⁽⁵⁾	56	Vice President, Coal Operations	2000

Todd A. Myers ⁽⁶⁾	41	Vice President, Sales and Marketing	2000

Douglas P. Kathol ⁽⁷⁾	52	Vice President, Development	2003

(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. Holzwarth joined Westmoreland in November 2004. Prior to joining Westmoreland, he was Chief Executive Officer of United Energy, a publicly-traded utility in Australia. From 1993 to 2003 he was employed by Aquila, Inc. in various management positions, including from 1999 to 2000 as Vice President and General Manager of Power Services and Generation, in which capacity he managed power plants capable of generating over 2,000 MW of electricity, and from 2002 to 2003 as Chief Executive Officer of United Energy, Australia, an electric distribution utility serving 600,000 customers.

(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. Mr. Lepchitz has resigned from the Company effective March 25, 2005.

(4)	Mr. Beck joined Westmoreland in July 2001 as Vice President - Finance and Treasurer. In September 2003, Mr. Beck also began serving as Acting Chief Financial Officer. Prior to joining Westmoreland he was a financial officer at Columbus Energy Corp. from 1985 to 2000, lastly as Vice President and Chief Financial Officer.

(5)	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 30 years of surface mine management and operations experience with various mining companies. He became a registered professional engineer in 1976.

(6)	Mr. Myers re-joined Westmoreland in January 2000 as Vice President Marketing and Business Development and in 2002 became 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.

(7)	Mr. Kathol joined Westmoreland in August 2003 as Vice President, Development. Prior to joining Westmoreland, Mr. Kathol was Senior Vice President and principal with Norwest Corporation (1985 to 2003) a firm that provides worldwide consulting services to the mining and energy industries. Mr. Kathol has held senior financial positions with other mining companies.

PART II

ITEM 5

–

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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

2003
First Quarter	13.70	10.00	32.50	30.00
Second Quarter	19.53	13.41	39.00	30.00
Third Quarter	18.19	13.81	38.75	34.00
Fourth Quarter	18.25	13.29	38.50	32.00

2004
First Quarter	19.29	15.99	42.00	36.75
Second Quarter	21.89	16.35	44.75	37.50
Third Quarter	30.32	19.25	52.75	42.25
Fourth Quarter	31.25	22.06	57.75	45.50

Approximate Number of Equity Security Holders of Record:


	Number of Holders of Record
Title of Class	(as of March 1, 2005)

Common Stock ($2.50 par value)	1,440
Depositary Shares, each representing
one-quarter share of a share of Series A
Convertible Exchangeable Preferred
Stock	15

Dividends:

We issued the Depositary Shares on July 19, 1992. Each Depositary Share represents one-quarter of a share of our Series A Convertible Exchangeable Preferred Stock. We paid quarterly dividends on the Depositary Shares until the third quarter of 1995, when we suspended dividend payments pursuant to the requirements of Delaware law, described below. We resumed dividends to preferred shareholders on October 1, 2002 as described below. The quarterly dividends which are accumulated through and including January 1, 2005 amount to $16.3 million in the aggregate ($79.72 per preferred share or $19.93 per depositary share). We cannot pay dividends on our common stock until we pay the accumulated preferred dividends in full.

There are statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which we are incorporated. Under Delaware law, we are 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 our 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 $205,000 at December 31, 2004). We had shareholders’ equity of $39.9 million and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $20.6 million at December 31, 2004.

Our Board regularly considers issues affecting our preferred shareholders, including current dividends and the accumulated amount. Our Board is committed to meeting its obligations to the preferred shareholders in a manner consistent with the best interests of all shareholders. Quarterly dividends of $0.15 per Depositary Share were paid beginning on October 1, 2002; we increased the dividend to $0.20 per Depositary Share beginning on October 1, 2003, and further increased the dividend to $0.25 per Depositary Share on October 1, 2004.

On August 9, 2002, our 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 was determined by our management based on its evaluation of our capital resources, the price of the Depositary Shares offered to us and other factors. We converted acquired Depositary Shares into shares of Series A Convertible Exchangeable Preferred Stock and retired the preferred shares. During the Depositary Share purchase program, we purchased a total of 14,500 depositary shares for an aggregate consideration of $457,000. This purchase program terminated on December 31, 2004.

The successful implementation of the initial phase of our strategic plan returned us to profitability and made it possible for us to pay preferred dividends and purchase Depositary Shares. These programs reflect our continuing commitment to our preferred shareholders.

Information regarding the Company’s equity compensation plans and the securities authorized for issuance thereunder is incorporated by reference in Item 12 below.

ITEM 6

–

SELECTED FINANCIAL DATA

Westmoreland Coal Company and Subsidiaries Five-Year Review

		2004		2003		2002		2001 ⁽¹⁾		2000

	(in thousands, except per share data)
Consolidated Statements of Operations Information
Revenue – Coal	$	320,291	$	294,986	$	301,235	$	231,048	$	35,137
– Independent power and other		12,741		15,824		14,506		15,871		32,260

Total revenues		333,032		310,810		315,741		246,919		67,397

Cost and expenses		329,076		303,695		296,908		233,307		60,170
Impairment charges		-		-		-		-		4,632

Operating income from continuing operations		3,956		7,115		18,833		13,612		2,595

Interest expense		(10,084)		(10,114)		(10,821)		(8,418)		(911)
Minority interest		(1,154)		(773)		(800)		(780)		(518)
Interest and other income		4,808		3,121		4,128		3,229		867


Income (loss) before income taxes from continuing operations		(2,474)		(651)		11,340		7,643		2,033

Income tax benefit (expense) from continuing operations		6,934		10,971		2,368		(1,228)		(428)

Income from continuing operations		4,460		10,320		13,708		6,415		1,605

Income (loss) from discontinued operations		-		2,113		(3,583)		(1,188)		(1,297)

Net income before cumulative effect of
change in accounting principle		4,460		12,433		10,125		5,227		308

Cumulative effect of change in accounting principle		-		161		-		-		-

Net income		4,460		12,594		10,125		5,227		308


Less preferred stock dividend requirements		1,744		1,752		1,772		1,776		1,776


Net income (loss) applicable to common shareholders	$	2,716	$	10,842	$	8,353	$	3,451	$	(1,468)

Net income (loss) per share applicable
to common shareholders:
Basic	$	0.34	$	1.39	$	1.10	$	0.48	$	(0.21)
Diluted	$	0.31	$	1.30	$	1.03	$	0.43	$	(0.21)
Weighted average number of common
shares outstanding:
Basic		8,099		7,799		7,608		7,239		7,070
Diluted		8,662		8,338		8,147		8,000		7,070

Balance Sheet Information
Working capital (deficit)	$	18,918	$	5,555	$	10,143	$	11,346	$	(1,557)
Net property, plant and equipment		168,628		151,349		189,532		197,271		34,693
Total assets		513,989		457,837		471,957		466,532		139,096
Total debt		117,259		93,469		100,157		122,910		-
Shareholders’ equity		39,892		33,270		18,568		10,415		3,373

⁽¹⁾	Effective April 30, 2001, the Company acquired the operating coal business of Montana Power and the coal assets of Knife River Corporation.

ITEM 7

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Disclaimer

Throughout this Form 10-K, we make statements which are not historical facts or information and that may be deemed “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. These forward-looking statements include, but are not limited to, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations. 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, 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; health care 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 growth and development 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 achieve anticipated cost savings and profitability targets; the Company’s ability to successfully identify new business opportunities; the Company’s ability to negotiate profitable coal contracts, price reopeners and extensions; the Company’s ability to predict or anticipate commodity price changes; the Company’s ability to maintain satisfactory labor relations; changes in the industry; competition; the Company’s ability to utilize its income tax net operating losses; the ability to reinvest cash, including cash that has been deposited in reclamation accounts, at an acceptable rate of return; weather conditions; the availability of transportation; price of alternative fuels; costs of coal produced by other countries; the demand for electricity; the performance of the ROVA Project and the structure of the ROVA Project’s contracts with its lenders and Dominion Virginia Power; our ability to complete the acquisition of the portion of the ROVA project that we do not currently own; the effect of regulatory and legal proceedings, including the bankruptcy filing by Touch America Holdings Inc. and Entech Inc.; environmental issues, including the cost of compliance with existing and future environmental requirements; the claims between the Company and Montana Power; and the other factors discussed in Items 1, 2, 3 and 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.

Overview

Competitive, economic and industry factors

We are an energy company. We mine coal, which is used to produce electric power, and we own interests in power-generating plants. We began to earn royalties from the production of coalbed methane gas in the first quarter of 2004. All of our five mines supply baseloaded power plants. Several of these power plants are located adjacent to our mines and we sell virtually all our coal under long-term contracts. Consequently, our mines enjoy relatively stable demand and pricing compared to competitors who sell more of their production on the spot market.

In partnership with others, we have developed eight independent power projects totaling 866 megawatts, or MW, of generating capacity. We have sold our interests in five of those projects. We currently own a 50% interest in the ROVA I and II coal-fired plants, which have a total generating capacity of 230 MW. We also retain a 4.49% interest in the gas-fired Fort Lupton Project, which has a generating capacity of 290 MW and provides peaking power to the local utility. The ROVA Project, which accounted for 98% of our equity in earnings from independent power in 2004, is baseloaded and supplies power pursuant to a long-term contract.

According to the 2005 Annual Energy Outlook prepared by the Energy Information Administration, or EIA, an agency of the U.S. Department of Energy, approximately 50% of all electricity generated in the United States in 2003 was produced by coal-fired units. The EIA projects that the demand for coal used to generate electricity will increase 1.6% per year from 2003 through 2025. Consequently, we believe that the demand for coal will grow, in part because coal is the lowest cost fossil-fuel used for generating baseload electric power.

Revenues and expenses; sources and uses of cash

In 2004, approximately three-fourths of our operating income came from coal operations, and one-fourth came from independent power projects. Our principal expenses were the cost of coal sales, heritage health benefit costs, and selling, general and administrative expenses.

In 2001, in order to finance the purchase of the Rosebud, Jewett, Beulah, and Savage Mines, Westmoreland Mining borrowed $120 million from institutional lenders under a term loan agreement. By the end of 2004, Westmoreland Mining had repaid $41.8 million of that $120 million and deposited an additional $21.9 million into two restricted accounts for the benefit of its lenders. In early March 2004, Westmoreland Mining made arrangements to borrow an additional $35 million from the lenders pursuant to what we call the add-on facility. Westmoreland Mining borrowed $20.4 million immediately and the additional $14.6 million in December 2004. The add-on facility permits Westmoreland Mining to undertake certain significant capital projects in the near term without adversely affecting cash available to us.

We may also seek additional capital in 2005 for general corporate purposes and to support our growth and development strategy.

Meeting Our Commitment to Preferred Stockholders

We remain committed to meeting our obligation for accumulated dividends to our preferred stockholders. As of January 1, 2005, $16.3 million had accumulated. A quarterly dividend of $0.25 per depositary share will be paid on April 1, 2005, to stockholders of record on March 10, 2005. The accumulated amount will continue to increase until we pay quarterly dividends of $0.53 per depositary share.

Challenges

We believe that our principal challenges today include the following:

•

inflation in medical costs and longer life expectancies, which can increase our expense for active employees and heritage health benefit costs;

•

maintaining and collateralizing our Coal Act and reclamation bonds;

•

transitioning from an approach towards growth and development that seeks to maximize the use of our net operating loss carryforwards to one that considers the impact of the alternative minimum tax;

•

managing the production and costs of our operations;

•

proposed new environmental regulations, which have the potential to significantly reduce sales primarily from our Absaloka, Jewett and Beulah Mines; and

•

addressing the claims for potential taxes asserted by various governmental entities.

We discuss these issues, as well as the other challenges we face, elsewhere in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, and under “Risk Factors.”

Critical Accounting Estimates and Related Matters

Our discussion and analysis of financial condition, results of operations, liquidity and capital resources is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require that we make estimates and judgments. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. Actual results may differ materially from these estimates.

We have made significant judgments and estimates in connection with the following accounting matters. Our senior management has discussed the development, selection and disclosure of the accounting estimates in the section below with the Audit Committee of our Board of Directors.

In connection with our discussion of these critical accounting matters, and in order to reduce repetition, we also use this section to present information related to these judgments and estimates.

Postretirement Benefits and Pension Obligations

Our most significant long-term obligation is the obligation to provide postretirement medical benefits, pension benefits, workers’ compensation and pneumoconiosis (black lung) benefits. We provide these benefits to our current and former employees and their dependents.

Estimates and Judgments

We estimate the total amount of these obligations with the help of third party professionals using actuarial assumptions and information. Our estimate is sensitive to judgments we make about the discount rate, about the rate of inflation in medical care, about mortality rates, and about the Medicare Prescription Drug Improvement and Modernization Act of 2003 or Medicare Reform Act. We review these estimates and obligations at least annually.

We pay these obligations currently and will have continuing obligations for future periods. Under generally accepted accounting principles, we are required to estimate the present value of these obligations. In order to do this, we make a judgment about the discount rate, which is an estimate about the current interest rate at which these obligations could be effectively settled on the date we estimate them. The discount rate used to calculate the present value of postretirement medical obligations was 6.75% in 2002, 6.25% in 2003 and 5.75% in 2004. The discount rate used to calculate the present value of pension obligations was 6.75% in 2002, 6.25% in 2003 and 6.00% in 2004. Significant changes to interest rates result in substantial volatility to our financial statements by influencing our estimate of these amounts. The recent trend of decreasing discount rates has significantly increased the present value of our obligations and our reported costs. An additional 1.00% change in the discount rate would change the net benefit obligation for post-retirement medical and pension benefits by approximately $30 million and $10 million, respectively.

In order to estimate the total cost of our obligation to provide medical benefits, we must make a judgment about the rate of inflation in medical costs. As our estimate of the rate of inflation of medical costs increases, our calculation of the total cost of providing these benefits increases. During 2004, we increased our assumption about this rate to 10%, and we also assumed that the rate would ultimately decline to 5% in 2012 and beyond. If we were to increase our assumption of the ultimate medical inflation rate from 5% to 6%, then all other things being equal, the present value of our postretirement medical cost obligation would increase by approximately $25 million.

Our accruals for postretirement medical, pension, workers’ compensation and black lung benefits are also affected by the mortality rate of the population for which we provide benefits. As people live longer, the cost of providing these benefits increases. However, the number of assigned beneficiaries for our Company under the Coal Act is fixed, since we discontinued our eastern underground operations, and the primary beneficiaries are elderly.

Related Information

The present value of our actuarially determined liability for postretirement medical costs increased approximately $7.8 million between December 31, 2003 and 2004, principally because of the decrease in discount rate and the increase in our assumption about medical cost inflation as described above. Actuarial valuations project that our retiree health benefit costs for our current employees and retirees will continue at a high level in the near term and then decline to zero over the next approximately sixty years as the number of eligible beneficiaries declines. We incurred cash costs of $25.1 million for postretirement medical costs during 2004 (including the Combined Fund’s retroactive assessment balance of $3.5 million, which was paid pending the outcome of that litigation) compared to $20.7 million in 2003. We expect to incur approximately $21 million for these costs in 2005.

We incurred cash costs of $1.8 million for workers’ compensation benefits during 2004 compared to $2.1 million in 2003. We expect to incur lower cash costs for workers’ compensation benefits in 2005 and expect that amount to decline nearly to zero over the next approximately 10 years. We anticipate that these costs will decline because we are no longer self-insured for workers’ compensation benefits and have had no new claimants since 1995. However, the actuarially determined expense increased $3.2 million in 2004 because of increased total remaining claims projections.

We do not pay pension or black lung benefits directly. These benefits are paid from trusts that we established and funded. As of December 31, 2004, our pension trusts are underfunded, and we expect to contribute approximately $2.2 million to these trusts in 2005. As of December 31, 2004, our black lung trust is overfunded by $4.5 million, and we do not expect to be required to make additional contributions to this trust.

The Coal Act, passed in 1992, established three benefit plans.

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First, the statute merged the UMWA 1950 and 1974 Plans into the Combined Fund. The Combined Fund provides benefits to a completely closed pool of beneficiaries, retirees who were actually receiving benefits from either the 1950 or 1974 Plan as of July 20, 1992. The Coal Act requires that the benefits provided to this group remain substantially the same as provided by the 1950 and 1974 Plans as of January 1, 1992. This group is essentially Medicare-eligible and the Combined Fund supplements the benefits this group receives under Medicare.

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Second, the Coal Act requires companies that had established individual employer plans, or IEPs, pursuant to prior collective bargaining agreements to maintain those IEPs and provide the beneficiaries a level of benefits substantially the same as they received as of January 1, 1992. The beneficiaries of these statutorily-required IEPs are retirees meeting age and service requirements as of February 1, 1993 and who actually retired before September 30, 1994.

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Third, the Coal Act established the 1992 UMWA Benefit Plan which serves three distinct populations: miners who were eligible to retire as of February 1, 1993 and actually retired before September 30, 1992 and whose employers are no longer in business; miners receiving benefits under an IEP but whose former employer went out of business; and new spouses or new dependants of retirees in the Combined Fund.

As required by the Coal Act, we maintain an IEP for our own retirees, and we pay premiums that cover a portion of the retired miners whose previous employers have gone out of business.

In addition, and separate from the Coal Act, we continue to provide benefits under another IEP to a smaller group of former UMWA employees who retired under our last collective bargaining agreement, which ended in 1998.

We expect that the Medicare Reform Act will reduce our prescription drug costs. The Medicare Reform Act provides a prescription drug benefit under Medicare as well as a Federal subsidy, starting in 2006 so long as an employer maintains qualifying health plans that provide prescription drug benefits. We currently estimate that the Medicare Reform Act will reduce our retiree medical claims costs by approximately $2.5 million in 2006 and annually thereafter until total drug costs begin to decline.

Asset Retirement Obligations, Reclamation Costs and Reserve Estimates

Asset retirement obligations primarily relate to the closure of mines and the reclamation of land upon cessation of mining. We account for reclamation costs, along with other costs related to mine closure, in accordance with Statement of Financial Accounting Standards No. 143 – Asset Retirement Obligations or SFAS No. 143, which we adopted on January 1, 2003. This statement requires us to recognize the fair value of an asset retirement obligation in the period in which we incur that obligation. We capitalize the present value of our estimated asset retirement costs as part of the carrying amount of our long-lived assets.

The liability “Asset retirement obligations” on our consolidated balance sheet represents our estimate of the present value of the cost of closing our mines and reclaiming land that has been disturbed by mining. This liability increases as land is mined and decreases as reclamation work is performed and cash expended. The asset, “Property, plant and equipment – capitalized asset retirement costs,” remains constant until new liabilities are incurred or old liabilities are re-estimated. We estimate the future costs of reclamation using standards for mine reclamation that have been established by the government agencies that regulate our operations as well as our own experience in performing reclamation activities. These estimates may change. Developments in our mining program also affect this estimate by influencing the timing of reclamation expenditures.

Adopting SFAS No. 143 significantly affected our financial statements. See the Summary of Significant Accounting Policies to our consolidated financial statements, which includes a discussion of the effect on our financial statements of adopting SFAS No. 143. However, the adoption of SFAS No. 143 did not affect our cash costs, because the annual cash requirements for reclamation activities are the same using SFAS No. 143 and the units-of-production accrual method, the accounting method we used prior to adopting SFAS No. 143.

We amortize our acquisition costs, development costs, capitalized asset retirement costs and some plant and equipment using the units-of-production method and estimates of recoverable proven and probable reserves. We review these estimates on a regular basis and adjust them to reflect our current mining plans. The rate at which we record depletion also depends on the estimates of our reserves. If the estimates of recoverable proven and probable reserves decline, the rate at which we record depletion increases. Such a decline in reserves may result from geological conditions, coal quality, effects of governmental, environmental and tax regulations, and assumptions about future prices and future operating costs.

Deferred Income Taxes

Estimates and Judgments

Our net income is sensitive to estimates we make about our ability to use our Federal net operating loss carryforwards, or NOLs.

As of December 31, 2004, we had approximately $176 million of NOLs. These NOLs expire at various dates through 2023. When we have taxable income, we can use our NOLs to shield that income from regular U.S. Federal income tax. Our ability to use our NOLs thus depends on all the factors that determine taxable income, including operational factors, such as new coal sales, and non-operational factors, such as increases in heritage health benefit costs. Under Federal tax law, our ability to use our NOLs would be limited if we had a “change of ownership” within the meaning of the Federal tax code.

Our NOLs are one of our deferred income tax assets. We have reduced our deferred income tax assets by a valuation allowance. The valuation allowance is primarily an estimate of the deferred tax assets that may not be realized in future periods. On a quarterly and annual basis, we estimate how much of our NOLs we will be able to use to shield future taxable income and make corresponding adjustments in the valuation allowance.

If we increase our estimated utilization of NOLs, we decrease the valuation allowance, increase our net deferred income tax assets and recognize an income tax benefit in earnings. If we decrease our estimated utilization of NOLs, we increase the valuation allowance, decrease our net deferred income tax assets and increase income tax expense. These changes can materially affect our net income and our assets. In 2004, for example, we reduced the valuation allowance by $2.8 million, in part because we improved the terms of an existing coal supply agreement. We also made other adjustments in our net deferred tax assets. As a result of these estimates and adjustments and changes in temporary differences between book and tax accounting, our net deferred income tax assets increased from $75.8 million at December 31, 2003 to $84.7 million at December 31, 2004, and we recognized income tax benefit from continuing operations of $6.9 million for 2004.

Related Information

Under the federal tax laws, there are two types of taxable income and two types of net operating loss carryforwards.

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The two types of taxable income are regular taxable income and Alternative Minimum Taxable Income, or AMTI. AMTI differs from regular taxable income in that AMTI includes items such as percentage depletion. We have significant percentage depletion because of our mining activities.

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The two types of NOLs are regular NOLs and alternative minimum tax, or AMT, NOLs.

Our NOLs are important to our strategy. Regular NOLs can offset our future regular taxable income, permit us to avoid payment of regular Federal income tax, and thereby increase our cash flow and return from profitable investments (as compared to the return that would be received by a tax-paying entity that cannot shield its income from Federal income taxation). However, regular NOLs will not shield our income from AMT.

We are subject to AMT at a 20% rate. As of December 31, 2004, we had AMT net operating loss carryforwards of approximately $18 million. Only 90% of our AMTI can be shielded each year by our AMT NOLs. Based upon our estimates of our future taxable income, we expect to fully utilize our remaining AMT NOLs in 2005 and begin paying the full 20% AMT in 2006. We may owe more than $5 million per year in AMT until we fully utilize our regular NOLs. Any AMT we pay is available as a credit against future regular Federal income tax. These credits do not expire.

As a strategic matter, we may face choices between business strategies intended to maximize the use of our regular NOLs and strategies that take account of AMT and seek to increase our after-tax profits, including the effects of AMT. Some of these strategies may involve decisions about business activities that generate AMTI, and many of these choices will require us to make judgments about matters that will arise in the future and that are therefore inherently uncertain.

Contractual Obligations and Commitments

The following table presents information about our contractual obligations and commitments as of December 31, 2004. Some of the figures below are estimates. We discuss these obligations and commitments elsewhere in this filing.

	Payments Due by Period (in thousands of dollars)
Contractual Obligations and Commitments	Total	2005	2006	2007	2008	After
Westmoreland Mining term debt ⁽¹⁾	113,200	10,300	11,300	12,000	44,600	35,000
Other debt	4,059	1,519	872	800	555	313
Interest on debt ⁽²⁾	35,044	9,431	8,407	7,313	6,088	3,805
Operating leases	7,263	2,770	2,011	1,248	901	333
Heritage Health Benefit/ Pension:
Undiscounted obligations:
Workers’ compensation	10,934	1,288	1,012	950	885	6,799
Discounted obligations:
Combined Benefit Fund (Multiemployer)	39,910 ⁽³⁾	4,826	4,684	4,412	4,139	21,849
Postretirement medical	259,776 ⁽⁴⁾	18,181	17,035	17,594	17,836	189,130
Qualified pension benefits	55,955 ⁽⁵⁾	605	836	1,125	1,542	51,847
SERP benefits	2,199 ⁽⁶⁾	76	74	71	68	1,910
Pneumoconiosis	21,755 ⁽⁷⁾	1,884	1,863	1,838	1,808	14,362
Reclamation costs	316,697 ⁽⁸⁾	5,284	10,147	4,401	6,330	290,535
Preferred dividends	16,349 ⁽⁹⁾	1,744 ⁽¹⁰⁾	1,744 ⁽¹⁰⁾	1,744 ⁽¹⁰⁾	1,744 ⁽¹⁰⁾	1,744 ⁽¹⁰⁾ per year

(1)	At December 31, 2004, Westmoreland Mining had deposited $21.9 million in two restricted accounts as collateral against these obligations.

(2)	In calculating the amount of interest on debt, we have assumed that the interest rate on Westmoreland Mining's $14.6 million of floating rate debt would not increase or decrease.

(3)	We have not accrued the present value of this obligation, because this plan is a multiemployer plan. We expense our premium payments when due.

(4)	The table presents our estimate of our gross benefit obligation. The accrued liability, net of the unrecognized net actuarial loss and the unrecognized net transition obligation, was $134.2 million as of December 31, 2004.

(5)	The fair value of plan assets at December 31, 2004 was $39.1 million. The expected pension benefit payments shown above will be made from these assets.

(6)	The table presents our estimate of our gross benefit obligation. The accrued liability, net of the unrecognized net actuarial gain and an unrecognized prior service cost, was $2.3 million as of December 31, 2004. The plan was unfunded at December 31, 2004.

(7)	The fair value of plan assets at December 31, 2004 was $26.2 million. Pneumoconiosis benefits will be paid from these assets.

(8)

The table presents our estimate of our gross cost of final reclamation. The accrued liability of $140.8 million as of December 31, 2004 will increase in present value as acres are disturbed in mining operations and as mine closures draw nearer. The accrued liability reflects the present value of contractual obligations of our customers and of Washington Group, the contract miner at the Absaloka Mine, to perform reclamation; we estimate that the present value of their combined obligations is $28.0 million. The table also does not reflect $55.6 million, the amount held in escrow as of December 31, 2004 from contributions by customers for reclamation of the Rosebud Mine. We estimate that the present value of our net obligation for final reclamation - that is, the costs of final reclamation that are not the contractual responsibilities of others - is $57.2 million at December 31, 2004.

(9)	Represents quarterly dividends that are accumulated through and including January 1, 2005.

(10)

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.

The ROVA Project’s debt is not listed in the table above because, at December 31, 2004, we were required to account for our investment in the ROVA Project using the equity method of accounting. If we complete the ROVA acquisition, we will no longer account for our investment in the ROVA Project using the equity method, and the ROVA Project’s debt will be fully consolidated on our financial statements with our debt and the debt of our subsidiaries. The ROVA Project had outstanding indebtedness of $206 million at December 31, 2004, and the principal of that debt is payable from 2005 through 2015.

Growth and Development Strategy

Our growth and development strategy is founded on the ownership and operation of assets that generate profits. We strive to identify assets that are low-cost producers and environmental leaders and that supply customers who share our orientation for low-cost production and our environmental concern. We believe that we will be more likely to achieve success in niche markets. Our goal is to acquire stable, long-term earnings. We will use our NOLs to shield that income from regular U.S. Federal income tax.

The acquisitions we completed in 2001 exemplify this strategy. Among other things, the Rosebud, Jewett, Beulah and Savage Mines are essentially adjacent to their principal customers, to which they deliver coal by conveyor belt or truck, and are the lowest-cost producers for their respective customers. These mines’ principal customers all employ modern emissions control technology. These mines are party to long-term contracts with their principal customers that generate stable earnings.

Examples of our current development efforts include the following:

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In 2004, we signed an Interest Purchase Agreement with LG&E to acquire LG&E’s 50% interest in the ROVA project.

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In 2003, we leased the rights to explore, drill, and produce coalbed methane gas on property that we own in Southern Colorado to Petrogulf Corporation for $300,000 and a royalty interest on production from that property. Petrogulf began drilling wells in 2003, production began in 2004, and we began earning royalties in the first quarter of 2004.

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In 2001, as part of our transaction with Knife River, we acquired rights to develop the lignite deposits at Gascoyne, North Dakota. Our subsidiary, Westmoreland Power, Inc., then joined with MDU Resources Group, Inc. to pursue development of a baseloaded lignite-fired power plant near Gascoyne as part of the State of North Dakota’s Lignite Vision 21 (“LV-21”) program. LV-21 is a partnership between North Dakota and the Lignite Energy Council (“LEC”) that is administered by the North Dakota Industrial Commission (“NDIC”). Westmoreland Power and MDU executed a joint development agreement in 2001, and we each own half of the venture that is seeking to develop the power plant. In September 2001, NDIC awarded the Westmoreland/MDU joint venture up to $10 million in matching funds to finance feasibility and technical studies. In January 2003, as a result of these studies, we and MDU sought additional support from NDIC to study the feasibility of substituting a 250 MW or 175 MW power plant for the 500 MW plant that had originally been proposed. NDIC awarded the funds sought, and we and MDU completed studies of generation technology, and lignite mining issues in 2003. Air quality evaluation was completed in early 2004 and in May 2004, we and MDU applied to the North Dakota Department of Health for an air quality permit for a proposed 175 MW plant.

An existing source of future income and cash flow relates to the Caballo Mine in Campbell County, Wyoming. In connection with the 2001 acquisitions, we acquired the stock of Horizon Coal Services, Inc. Horizon’s only asset is a royalty interest in coal reserves located at the Caballo Mine, which is owned by a company that is not affiliated with us. The royalty of $.10 per ton covers the mining of 225 million tons of coal, making the potential gross royalty amount $22.5 million. The latest mine plan projects that mining of coal subject to the royalty will begin in late 2007.

We discuss financial aspects of the ROVA acquisition in more detail below under “— Financial Implications of the ROVA Acquisition.” As a strategic matter, owning 100% of the ROVA Project would give us an additional long-lived asset whose value, we believe, extends well beyond the expiration of the ROVA Project’s existing contracts with Dominion Virginia Power in 2019. It also should enhance our ability to develop and implement strategies to restructure the project’s contracts with its principal customer, Dominion Virginia Power, and with the project’s lenders, to the mutual benefit of all parties, including us, as owners. The ROVA acquisition also would double the number of megawatts of generated power that we own and substantially expands the foundation for further growth of the power segment of our business. Such growth may include the development and construction of additional power-generating units at the ROVA site, the Gascoyne site or elsewhere. Such growth may also include the operation of power plants. A subsidiary of LG&E holds the contract to operate the ROVA Project and will continue to hold that operating agreement after we acquire 100% of the project. However, upon the closing of the ROVA acquisition, we will acquire the exclusive right to negotiate the purchase of this LG&E subsidiary, or some or all of its assets, including the ROVA operating agreement, before LG&E sells them to any third party.

Liquidity and Capital Resources

As discussed in the Overview section above, we believe that Westmoreland Mining’s add-on facility substantially improves our near-term liquidity. In addition, even though the requirements of Westmoreland Mining’s basic term loan agreement, including debt service requirements, restrict our access to some of Westmoreland Mining’s cash, Westmoreland Mining itself generates significant liquidity.

Cash provided by operating activities was $9.5 million in 2004, $24.8 million in 2003, and $32.4 million in 2002. Cash from operations in 2004 compared to 2003 decreased primarily because our operating income declined. Our operating income declined principally because we sold less coal and incurred higher costs at the Jewett Mine, where unusually high rainfall disrupted production, and as a result of increases in the cost of commodities we consume at our operations. We also had significantly lower distributions from the ROVA project in 2004 as compared to 2003, because the project’s lenders withheld $8.3 million (of which our share is $4.15 million) as a reserve for a disputed personal property assessment by Halifax County, North Carolina and in connection with a scheduled maintenance outage. Lastly, we made contributions to our defined benefit pension plans of $3.4 million in 2004, while no contributions were required in 2003. These reductions more than offset the positive impact of receiving a net retroactive payment of $11.9 million from the owners of Colstrip Units 1&2. Working capital was $18.9 million at December 31, 2004 compared to $5.6 million at December 31, 2003. The increase resulted primarily from additional borrowings of long-term debt, an increase in the current portion of our deferred income tax assets and a decrease in the current portion of our postretirement medical costs, principally attributable to the payment of the retroactive premium assessed by the Combined Fund.

We used $28.5 million of cash in investing activities in 2004, $17.3 million in 2003 and $3.7 million in 2002. Cash used in investing activities in 2004 included $18.3 million of additions to property, plant and equipment for mine equipment and development projects. Cash used in investing activities in 2004 also included a $10.5 million increase in our restricted cash accounts, pursuant to Westmoreland Mining’s term loan agreement and as collateral for our surety bonds. Additions to property, plant and equipment in 2003 were $13.2 million and increases in restricted cash accounts were $11.0 million. During 2003, net proceeds from sales of assets of $7.0 million included $4.5 million cash received from the sale of DTA and $1.4 million received from the sale of land and mineral rights in Colorado. In 2002, additions to property and equipment using cash totaled $7.3 million, and we received $3.6 million from the Absaloka Mine’s mining contractor to settle a dispute regarding repair of the dragline at that mine. Also during 2002, we deposited $6.4 million into restricted cash accounts. Those deposits were offset by a $6.0 million refund of collateral we received from the UMWA.

We generated cash in financing activities of $20.9 million in 2004, comprised primarily of new borrowings of $34.1 million of long-term debt. We used cash of $11.7 million for the repayment of long-term debt in 2004. We used cash of $8.1 million in financing activities in 2003, including $5.2 million for the net repayment of long-term debt and $1.5 million for the net repayment of revolving debt. Cash used in financing activities in 2002 primarily represented repayment of long-term debt of $13.8 million and the net repayment of revolving debt of $9.0 million. Dividends paid to Westmoreland Resources’ 20% shareholder in 2004, 2003 and 2002 were $1.2 million, $1.0 million and $1.2 million, respectively.

Consolidated cash and cash equivalents at December 31, 2004 totaled $11.1 million, including $4.6 million at Westmoreland Mining, $4.1 million at Westmoreland Resources, and $2.5 million at our captive insurance subsidiary. At December 31, 2003, cash and cash equivalents totaled $9.3 million, including $4.1 million at Westmoreland Mining, $4.2 million at Westmoreland Resources, and $1.5 million at the captive insurance subsidiary. The cash at Westmoreland Mining is available to us through quarterly distributions, as described below. The cash at Westmoreland Resources is available to us through dividends. In addition, we had restricted cash and bond collateral, which were not classified as cash or cash equivalents, of $32.7 million at December 31, 2004 and $25.0 million at December 31, 2003. The restricted cash at December 31, 2004 included $21.9 million in Westmoreland Mining’s debt service and long-term prepayment accounts. The restricted cash at December 31, 2003 included $17.4 million in Westmoreland Mining’s debt service reserve and long-term prepayment accounts. At December 31, 2004, our reclamation, workers’ compensation and postretirement medical cost obligation bonds were collateralized by interest-bearing cash deposits of $10.8 million, which amounts we have classified as non-current assets. In addition, we had reclamation deposits of $55.6 million at December 31, 2004 and $52.8 million at December 31, 2003, which we received from customers of the Rosebud Mine to pay for reclamation. We also had $5.0 million in interest-bearing debt reserve accounts for the ROVA Project at December 31, 2004. This cash is restricted as to its use and is classified as part of our investment in independent power projects.

In early March 2004, Westmoreland Mining entered into the add-on facility. This facility made $35 million available to us in 2004. The add-on facility permits Westmoreland Mining to undertake significant capital projects, principally at the Rosebud and Jewett Mines, in the near term without adversely affecting cash available to Westmoreland Coal Company. The terms of the add-on facility permit Westmoreland Mining to distribute this $35 million to Westmoreland Coal Company. Westmoreland Mining distributed $19.3 million to Westmoreland Coal Company in 2004 and expects to distribute the balance in 2005. The original term loan agreement, which financed our acquisition of the Rosebud, Jewett, Beulah, and Savage Mines, continues to restrict Westmoreland Mining’s ability to make distributions to Westmoreland Coal Company from ongoing operations. Until Westmoreland Mining has fully paid the original acquisition debt, which is scheduled for December 31, 2008, Westmoreland Mining may only pay Westmoreland Coal Company a management fee and distribute to Westmoreland Coal Company 75% of Westmoreland Mining’s surplus cash flow. Westmoreland Mining is depositing the remaining 25% into an account that will fund the $30 million balloon payment due December 31, 2008. At the same time that Westmoreland Mining entered into the add-on facility, it also extended its revolving credit facility to 2007 and reduced the amount of the facility to $12 million. Westmoreland Mining reduced the amount of the revolving facility to better align its capacity to its expected usage and borrowing base. As of December 31, 2004, Westmoreland Mining had the entire $12.0 million revolving facility available to borrow.

As of December 31, 2004, Westmoreland Coal Company had its entire $14.0 million revolving line of credit available to borrow.

On July 28, 2004, we filed a registration statement for a possible rights offering. If the registration statement becomes effective, it would permit holders of our common stock to purchase additional shares of common stock. As stated in the registration statement, the additional equity capital would be used to support our growth and development strategy and for general corporate purposes.

Liquidity Outlook

Significant Anticipated Variances between 2004 and 2005

We anticipate that the following events and developments, which we expect will occur in 2005 but which did not occur in 2004, and the following events and developments, which we expect will not occur in 2005 but which did occur in 2004, will affect our liquidity and our net income.

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We discuss the prospective effects of the anticipated ROVA acquisition in more detail below.

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The price adjustment required in July 2001 for the coal that we supply to Colstrip Units 1&2 was finally determined in May 2004. The arbitrators’ decision resulted in a price increase. The new price was effective as of July 30, 2001, covers coal we supplied to Colstrip Units 1&2 from July 30, 2001 through May 2004, and will remain in effect through the expiration of the contract. In 2004, we received a payment of over $11 million from the owners of Colstrip Units 1&2, which represents the extra amount owed to us for coal supplied from July 2001 through May 2004, including interest, net of applicable taxes and royalties. We do not expect any comparable event in 2005.

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We expect increased sales in 2005 from the Rosebud Mine. Overall cost of sales should decrease, in part because the costs at the Jewett Mine associated with the 2004 excessive rainfall should not be repeated, and in part because we have taken steps described below at our operations.

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We anticipate that capital expenditures related to our mining activities will be higher in 2005 than in 2004. We expect that most of the increase in 2005 will be associated with mine development at the Absaloka, Rosebud and Beulah Mines. Capital expenditures at the Jewett Mine are significant but comparable in both 2004 and 2005.

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We anticipate higher interest costs in 2005 because of the additional $35 million borrowed in 2004.

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Our results for 2004 reflect a negative impact of increased prospective and retroactive personal property taxes at the ROVA Project. Our pre-tax income was reduced by $2.0 million for the accrual of our estimated cost. Also, the lender to the Project is withholding funds in an amount equal to the total amount claimed by Halifax County, which funds are normally available for distribution, until the claim has been resolved. Our share of the amount withheld is $4.2 million.

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We expect higher depreciation, depletion and amortization expense in 2005 than in 2004 due to continued capital expenditures at our mines and an increase in the carrying value of our capitalized asset retirement costs.

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In 2004, we paid the final $3.5 million of the Combined Fund’s retroactive assessment. Our cash payments for postretirement medical costs is expected to decrease to $21 million in 2005 as compared to $25.1 million in 2004, in part because we have now fully paid this assessment. We are challenging this assessment, as discussed in Item 3 – Legal Proceedings.

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During 2005, we plan to complete implementation of a common, corporate-wide enterprise resource planning, or information technology system to enhance our reporting and analysis capability. The total investment in 2004 was approximately $3.4 million, which represents most of the expected total costs. We expect that the system will deliver an acceptable return on investment through improved efficiencies and reduced costs associated with our current, separate systems.

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In 2000, we adopted a long-term incentive plan to promote the successful implementation of our strategic plan and link the compensation of our key managers to the appreciation in the price of our common stock. The Board of Directors’ Compensation & Benefits Committee granted awards under this long-term incentive plan with a variable value in 2000, 2001, 2002 and 2004. The total expense for these awards in 2004 was $2.3 million. We are not able to predict the variable expense for these awards in 2005. New accounting rules require that we expense the value of stock options over their vesting periods, beginning no later than the third quarter of 2005. We have not determined the impact of this new requirement.

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We have three defined benefit pension plans for full-time employees. We were required to contribute $3.4 million to the plans in 2004, and we expect to make additional contributions of $2.2 million in 2005. Additional contributions will likely also be required in future years unless the return on the plans’ investments materially improves or the plans’ funding requirements change.

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In 2005, we expect that our payments for AMT will increase to $0.5 million from payments of $0.4 million in 2004. We expect that our AMT NOLs will be fully utilized in 2005, and that AMT payments in 2006 and beyond will increase significantly.

Our operating income declined in 2004 primarily because we sold less coal and incurred higher costs at the Jewett Mine, where unusually high rainfall disrupted production, and as a result of increases in the cost of commodities at our mines. Certain of our coal supply contracts allow us to recover the increased cost of commodities on a current basis. Other arrangements are in place under which the Company’s mining operations should recover in 2005 significant portions of the remaining past cost increases for commodities. We are also exploring sales, production and mine design changes that could reduce the Company’s exposure to such events as excessive rainfall, uncontrollable cost escalations, and variable mining conditions at Jewett and other operations going forward.

As a result of the difficulties at the Jewett Mine, we took no distributions from Westmoreland Mining for the third and fourth quarters of 2004. Under Westmoreland Mining’s term loan agreement, Westmoreland Mining is permitted to make quarterly distributions to Westmoreland Coal Company subject to adjustment at year end based upon audited financial information. For the year ended December 31, 2004, Westmoreland Mining distributed an amount that, based upon year end information, exceeded by $3.0 million the annual amount permitted under the term loan agreement. Westmoreland Mining intends to deduct that amount from future distributions to Westmoreland Coal Company as permitted under the term loan agreement.

Significant Factors Affecting Our Liquidity

The matters discussed above focus on anticipated differences between 2004 and 2005. A number of non-recurring events significantly influenced our 2004 results. Our operational performance, our financial results, and our liquidity may also be affected by all of the other matters discussed in this Annual Report on Form 10-K, including the legal proceedings discussed in Item 3 and the matters discussed in this Management’s Discussion and Analysis of Financial Condition and Results of Operations. Primarily because of our size and the multitude of issues related to our transition from an eastern underground producer of coal, to a western niche surface producer with significant reliance on independent power operations, we have been subject to the impact of many matters beyond our control. For all of the foregoing reasons, and while we anticipate that we will be profitable in 2005, we cannot project our overall level of profitability.

Financial Implications of the ROVA Acquisition

On August 25, 2004, we signed an Interest Purchase Agreement with a subsidiary of LG&E Energy LLC. In that agreement, we agreed to acquire the 50% interest in the ROVA Project that we do not currently own. In November 2004, Dominion Virginia Power asserted that it had a right of first refusal with respect to LG&E’s interest. For the reasons discussed in “Risk Factors” below, there can be no assurance that we will be able to complete the acquisition of LG&E’s interest in the ROVA Project.

The financial implications of the ROVA transaction will depend significantly on when it is completed (if at all), how we choose to finance the transaction, the terms of any such financing, and the terms of an agreement with Dominion Virginia Power.

In evaluating the terms of any proposed financing or any proposed agreement with Dominion Virginia Power, we start with the existing contracts that were negotiated initially when the project was developed. The principal contracts are two power purchase and operating contracts, pursuant to which the ROVA Project sells electricity to Dominion Virginia Power, and the agreements between the ROVA Project and its lenders that financed the project’s construction. Annual principal payments on the project’s debt are projected to increase from $22 million in 2005, to approximately $34 million in 2008, and approximately $33 million in 2009. Annual principal payments are projected to fall sharply thereafter until the project’s debt is fully paid in 2015. The revenues under the power purchase contracts were structured to permit the ROVA Project to make these principal payments, but the project’s revenues and expenses do not correspond perfectly, and under the project’s existing arrangements, cash flow from the project after payment of principal and interest is expected to decline from 2005 through 2012.

We currently expect that completing the ROVA acquisition would increase our revenues, operating income, and net income over what we expect to receive from our existing 50% ownership of the ROVA Project, but the magnitude of the impact would depend in part on the factors described in the preceding paragraph. We also expect that, through at least 2008, the ROVA acquisition would increase our cash flow on an after-tax basis over what we would have received from owning 50% of the project, but the magnitude of the impact would again depend in part on the factors described above. The alternative minimum tax also affects our return from the acquisition: we anticipate that, if we acquire LG&E’s 50% interest in the ROVA Project, we would increase our alternative minimum taxable income and alternative minimum tax payments.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements within the meaning of the rules of the Securities and Exchange Commission.

Results of Operations
2004 Compared to 2003

Coal Operations. We sold about 1.2 million more tons of coal in 2004 than we did in 2003. The increase in tons sold in 2004 came from new or extended sales contracts at the Rosebud and Absaloka Mines. Revenues increased at a greater rate primarily because, in 2004, we received an arbitration award increasing the contract price for tons sold to Colstrip Units 1&2 from our Rosebud Mine retroactive to July 2001. This resulted in the recognition in 2004 of additional revenue of $16.3 million and related production taxes and royalties of $5.1 million. The increased price will continue through the expiration of the contract with Colstrip Units 1&2 in 2009. In spite of the additional margin from this retroactive price increase, costs, as a percentage of revenues, increased to 78% in 2004 compared to 77% in 2003. This was mostly a result of weather related interruptions in 2004 at the Jewett Mine and increased costs for diesel fuel and electricity used at our mines.

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

		Year Ended
		2004		2003	Change


Revenues – thousands	$	320,291	$	294,986	9%

Volumes – millions of equivalent coal tons		29.0		27.8	4%

Cost of sales – thousands	$	249,300	$	228,433	9%

Depreciation, depletion and amortization increased to $15.9 million in 2004 compared to $12.6 million in 2003, primarily because we increased capital expenditures at the mines for both continued mine development and the replacement of mining equipment and because increased depreciation resulted from the increase in production levels. There was also higher depletion due to an increase in capitalized asset retirement costs.

Independent Power. Our equity in earnings from independent power operations decreased to $12.7 million in 2004 from $15.8 million in 2003. The decrease is attributable to a $2.0 million charge for retroactive personal property taxes, which are being challenged, and costs associated with a major five-year scheduled maintenance outage. During 2004 and 2003, the ROVA Project produced 1,625,000 and 1,653,000 megawatt hours, respectively, and achieved average capacity factors of 88% and 90%, respectively. We also recognized $317,000 in equity in earnings in 2004 from our 4.49% interest in the Ft. Lupton project compared to $582,000 in 2003.

Costs and Expenses. Selling and administrative expenses decreased to $30.9 million in 2004 from $33.4 million in 2003. Contributing to the decrease were lower expenses for both severance and long-term incentive compensation plans, continued decrease in health care costs for active employees and decreased legal fees associated with coal contract negotiations and other litigation. Long-term incentive compensation decreased to $2.3 million in 2004 from $2.5 million in 2003. This is a non-cash expense until it is paid. Payments are currently being made over a five-year period following maturity. The Compensation and Benefits Committee has elected to pay a portion of the awards in shares of common stock and future exercises of stock appreciation rights will be settled in common stock.

Heritage health benefit costs increased to $33.1 million in 2004 compared to $29.9 million in 2003. Four factors impacted these costs:

•

In 2004, we increased our estimate of outstanding workers’ compensation costs by $3.2 million based upon increased claims experience and revised actuarial projections.

•

In 2004, our costs increased because there was a decrease in the amount by which our black lung trust was overfunded.

•

In 2004, a decrease in discount rates increased costs for postretirement medical obligations.

•

In 2003, costs included a $4.7 million retroactive premium assessed by the Combined Fund.

Interest expense was $10.1 million in 2004 and 2003. Interest associated with the larger amount of outstanding debt as a result of Westmoreland Mining’s add-on facility and increased use of Westmoreland Mining’s revolver facility during the year was offset by lower interest payments due to the pay-down of the acquisition financing obtained in 2001. Interest income increased in 2004 because of larger restricted cash and surety bond collateral balances and interest of $0.7 million associated with the arbitration decision relating to Colstrip Units 1&2.

Results of Operations
2003 Compared to 2002

Coal Operations. We sold about 1.7 million more tons of coal in 2003 than we did in 2002, but our coal revenues decreased $6.3 million. Revenues declined because, for part of 2002, the Jewett Mine benefited from a “cost-plus fees” pricing structure in its contract with Texas Genco II. We sold more tons at all of our mines in 2003 than we did in 2002, with the exception of the Beulah Mine, which was adversely affected by a longer than expected major maintenance outage at the Coyote Station, that mine’s principal customer. In addition, the Rosebud Mine was adversely affected by an unscheduled outage at the Colstrip Station, its principal customer. Costs, as a percentage of revenues, increased to 77% in 2003 compared to 75% in 2002, again largely as a result of the lower average sales price in 2003 at the Jewett Mine. Also, the implementation of SFAS No. 143 increased non-cash accretion costs at all mines for future reclamation activities and reduced margins in 2003.

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

		Year Ended
		2003		2002	Change


Revenues – thousands	$	294,986	$	301,235	(2)%

Volumes – millions of equivalent coal tons		27.8		26.1	7%

Cost of sales – thousands	$	228,433	$	226,707	1%

Depreciation, depletion and amortization increased to $12.6 million in 2003 compared to $11.5 million in 2002 due to increased capital expenditures and increased depreciation resulting from the increase in production levels.

Independent Power. Our equity in earnings from independent power operations increased from $14.5 million in 2002 to $15.8 million in 2003. During 2003 and 2002, the ROVA Project produced 1,653,000 and 1,639,000 megawatt hours, respectively, and achieved average capacity factors of 90% and 89%, respectively. Also, we recognized $582,000 in equity in earnings in 2003 from our 4.49% interest in the Ft. Lupton project, most of which related to periods prior to 2003.

Costs and Expenses. Selling and administrative expenses increased from $31.7 million in 2002 to $33.4 million in 2003. Contributing to the increase were higher heritage health benefit costs and a higher compensation expense for long-term employee performance incentives. We incurred increased legal fees associated with coal contract negotiations and litigation.

Heritage health benefit costs were $29.9 million in 2003 compared to $26.9 million in 2002. Five factors contributed to the increase:

•

The Combined Fund assessed the $4.7 million retroactive premium discussed above.

•

We incurred an additional $2.3 million expense for postretirement medical obligations, principally because of a change in the discount rate and inflation in medical costs.

•

We incurred an additional $2.5 million expense resulting from negative actuarial valuation adjustments for our workers’ compensation and black lung obligations.

•

We eliminated $6.3 million in previously recognized obligations to the UMWA 1974 Pension Plan.

A redesign of our health care plans for active employees, including an increase in employees’ premium payments and aggressive management of medical expenses, reduced our health care costs for active employees in 2003 compared to 2002.

Long-term incentive compensation increased from $1.0 million in 2002 to $2.5 million in 2003. This expense was entirely attributable to the 2000 Performance Unit Plan, described above. This expense is a non-cash expense until it is paid. As permitted by the plan, we paid about 20% of the expense, $750,000 in cash and $375,000 in shares of common stock in 2003, leaving an obligation of $5.3 million as of December 31, 2003.

Interest expense was $10.1 million and $10.8 million for 2003 and 2002, respectively. The decrease was mainly due to the continued repayment of Westmoreland Mining’s debt. Interest income decreased in 2003 because of lower rates.

Other income in 2002 includes a $1.1 million gain in connection with the favorable judgment in the dispute with a customer of the Ft. Drum power project that was sold.

Terminal Operations. As discussed in Note 3 to the Consolidated Financial Statements, effective June 30, 2003, we sold our interest in DTA and recognized a pre-tax gain of approximately $4.5 million. Our consolidated financial statements for 2003 and earlier periods reflect DTA as discontinued operations. Our share of operating losses from DTA was approximately $1.0 million for the six months we owned it in 2003 compared to $2.1 million related to a full year’s ownership in 2002. During 2002, we expensed as a non-cash impairment charge our remaining investment of $3.7 million in DTA as a result of continuing losses and an agreement by one of the terminal’s other owners to sell its interest for a loss.

Cumulative Effect of Change in Accounting Principle. We adopted SFAS No. 143 during the first quarter of 2003, as described in the section on “Critical Accounting Policies” above. The cumulative effect of the change was a gain of $161,000, net of tax expense of $108,000. We also reduced our recorded liability for mine reclamation from $159 million to $115 million as of January 1, 2003 and reduced the net book value of our property, plant and equipment from $189 million to $145 million as a result of adopting this standard.

New Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123 (revised 2004) “Share-Based Payment” or SFAS 123R, which replaces SFAS No. 123 and supersedes APB Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005, with early adoption encouraged. The pro forma disclosures previously permitted under SFAS 123 no longer will be an alternative to financial statement recognition. The Company is required to adopt SFAS 123R in the third quarter of 2005, beginning July 1, 2005. Under SFAS 123R, the Company must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost, and the transition method to be used at the date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive option, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested stock options and restricted stock at the beginning of the first quarter of adoption of SFAS 123R, while the retroactive methods would record compensation expense for all unvested stock options and restricted stock beginning with the first period restated. The Company is evaluating the requirements of SFAS 123R and expects that the adoption of SFAS 123R will not have a material adverse impact on the Company’s financial position. The Company has not yet determined the method of adoption or the effect of adopting SFAS 123R, it has not determined whether the adoption will result in changes to net income that are similar to the current pro forma disclosures under SFAS 123 included in the Summary of Significant Accounting Policies accompanying the consolidated financial statement, and it has not determined if it will elect to adopt the provisions of SFAS 123R prior to July 1, 2005.

In December 2004, the FASB issued SFAS No. 153-Exchanges of Nonmonetary Assets—An Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions or SFAS 153. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29-Accounting for Nonmonetary Transactions, and replaces it with an exception for exchanges that do not have commercial substance. SFAS 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is effective for the fiscal periods beginning after June 15, 2005 and is required to be adopted by the Company in the first quarter of 2006. The Company is currently evaluating the effect that the adoption of SFAS 153 will have on its consolidated results of operations and financial condition but does not expect it to have a material impact.

Risk Factors

In addition to the trends and uncertainties described in Items 1 and 3 of this Annual Report on Form 10-K and elsewhere in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, we are subject to the risks set forth below.

Our coal mining operations are inherently subject to conditions that could affect levels of production and production costs at particular mines for varying lengths of time and could reduce our profitability.

Our coal mining operations are all surface mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production and increase the cost of mining at particular mines for varying lengths of time and negatively affect our profitability. These conditions or events include:

•

unplanned equipment failures, which could interrupt production and require us to expend significant sums to repair our capital equipment, including our draglines, the large machines we use to remove the soil that overlies coal deposits;

•

geological conditions, such as variations in the quality of the coal produced from a particular seam, variations in the thickness of coal seams and variations in the amounts of rock and other natural materials that overlie the coal that we are mining; and

•

weather conditions.

Examples of recent conditions or events of these types include the following:

•

In the first quarter of 2004, electrical components on the dragline at our Savage Mine failed. This reduced overburden removal and increased costs at that mine for a period of 10 1/2 days while the dragline was being repaired.

•

In the first quarter of 2004, our Beulah Mine experienced sloughage, a condition in which the side of the pit partially collapses and must be stabilized before mining can continue. This limited use of the dragline at that mine for a period of 4 days while the walls of the pit were being stabilized.

•

In the second quarter of 2004, our Jewett Mine received approximately 93% more rain than normal, impeding production.

Our revenues and profitability could suffer if our customers reduce or suspend their coal purchases.

In 2004, we sold approximately 98% of our coal under long-term contracts and about three-fourths of our coal under contracts that obligate our customers to purchase all or almost all of their coal requirements from us, or which give us the right to supply all of the plant’s coal, lignite or fuel requirements. Three of our contracts, with the owners of the Limestone Electric Generating Station, Colstrip Units 3&4 and with Colstrip Units 1&2, accounted for 26%, 22% and 16%, respectively, of our coal revenues in 2004. (The contract with the owners of Colstrip Units 1&2 accounted for this percentage of our 2004 revenues because we received, in 2004, an arbitration award that covered coal delivered to Colstrip Units 1&2 from July 2001.) Interruption in the purchases by or operations of our principal customers could significantly affect our revenues and profitability. Unscheduled maintenance outages at our customers’ power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. Four of our five mines are dedicated to supplying customers located adjacent to or near the mines, and these mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.

Disputes relating to our coal supply agreements could harm our financial results.

From time to time, we may have disputes with customers under our coal supply agreements. These disputes could be associated with claims by our customers that may affect our revenue and profitability. Any dispute that resulted in litigation could cause us to pay significant legal fees, which could also affect our profitability. By way of example, we have entered into a settlement agreement with Texas Genco II that addresses contract disputes through 2007, but differences may occur as to the interpretation of various contract provisions after 2007.

We may not be able to complete the ROVA acquisition.

In August 2004, we agreed to acquire from LG&E the 50% interest in the ROVA Project that we do not currently own. In November 2004, Dominion Virginia Power asserted that it had a right of first refusal with respect to LG&E’s interest in this project. In view of Dominion Virginia Power’s claim, there can be no assurance that we will be able to acquire LG&E’s interest in the ROVA Project.

Even if we are able to resolve the claim of Dominion Virginia Power, the completion of the ROVA transaction is subject to the following conditions specified in our Interest Purchase Agreement with LG&E:

•

Both we and LG&E must have performed and complied with, in all material respects, the obligations and covenants that we and LG&E are required to perform and comply with prior to the closing.

•

Our representations and warranties, and the representations and warranties of LG&E, must be true and correct in all material respects on the closing date.

•

Since August 25, 2004, there must not have been a material adverse effect on the assets, business, condition, or results of operations of the partnership that owns the ROVA Project; the condition, use, or operation of the ROVA Project itself; the payments owed to the ROVA Project by Dominion Virginia Power under the power purchase agreement; or LG&E’s 50% interest in the ROVA Project.

•

We and LG&E must have received all necessary consents to the transaction from all regulatory authorities and third parties, including the consents of the lenders to the ROVA Project.

•

We must have obtained replacement insurance that satisfies the insurance requirements of the ROVA Project’s credit agreement with its lenders.

•

LG&E and its affiliates must have been released from their obligations under the ROVA Project’s existing letters of credit, and the beneficiaries of those letters of credit must not have drawn under them.

The closing of the ROVA acquisition is also subject to other customary conditions.

We are currently negotiating with Dominion Virginia Power to address its claim, but there can be no assurance that we will be able to resolve this claim on a basis that we consider satisfactory for the Company. In addition, many of the conditions to the closing of the ROVA acquisition are beyond our control, and there can be no assurance that those conditions will be satisfied.

We are a party to numerous legal proceedings, some of which, if determined unfavorably to us, could result in significant monetary damages.

We are a party to several legal proceedings, which are described more fully in this Annual Report on Form 10-K under Item 3 – “Legal Proceedings.” Adverse outcomes in some or all of the pending cases could result in substantial damages against us or harm our business.

We currently own a 50% interest in the ROVA Project, which is located in Halifax County, North Carolina, and we have agreed to purchase the 50% interest that we do not currently own. Halifax County asserts that the ROVA Project owes $8.3 million in back taxes, penalties and interest. If we complete the ROVA acquisition, LG&E has agreed to indemnify the ROVA Project for one-half of this amount.

We acquired the Rosebud and Jewett Mines and other assets from Entech, Inc., a subsidiary of the Montana Power Company, in April 2001. Under our agreement with Entech, the final purchase price is subject to adjustment. In June 2001, Entech proposed adjustments that would increase the purchase price by approximately $9 million. In July 2001, we objected to Entech’s adjustments and proposed our own adjustments, which would result in a substantial decrease in the purchase price. In June 2003, Entech and Touch America Holdings, Inc., the successor to the Montana Power Company, filed bankruptcy petitions. In March 2004, we received notice that Entech and Touch America had commenced an adversary proceeding against us in the bankruptcy court, seeking payment of approximately $9 million. We filed an answer, a motion to dismiss and a claim for indemnification. The bankruptcy court has referred the claims regarding the purchase price adjustment dispute to the courts of the State of New York. The parties subsequently agreed to refer the purchase price adjustment issues to an independent accountant who has concluded his review. Our claim for indemnification is now set for trial in October 2005 in the U.S. District Court in Delaware.

We may not be able to manage our expanding operations effectively, which could impair our profitability.

At the end of 2000, we owned one mine and employed 31 people. In the spring of 2001, we acquired the Rosebud, Jewett, Beulah and Savage Mines from Entech and Knife River Corporation, and at the end of 2004, we employed 943 people. This growth has placed significant demands on our management as well as our resources and systems. One of the principal challenges associated with our growth has been, and we believe will continue to be, our need to attract and retain highly skilled employees and managers. If we are unable to attract and retain the personnel we need to manage our increasingly large and complex operations, our ability to manage our operations effectively and to pursue our business strategy could be compromised.

Our growth and development strategy could require significant resources and may not be successful.

We regularly seek opportunities to make additional strategic acquisitions, to expand existing businesses, to develop new operations and to enter related businesses. We may not be able to identify suitable acquisition candidates or development opportunities, or complete any acquisition or project, on terms that are favorable to us. Acquisitions, investments and other growth projects involve risks that could harm our operating results, including difficulties in integrating acquired and new operations, diversions of management resources, debt incurred in financing such activities and unanticipated problems and liabilities. We anticipate that we would finance acquisitions and development activities by using our existing capital resources, borrowing under existing bank credit facilities, issuing equity securities or incurring additional indebtedness. We may not have sufficient available capital resources or access to additional capital to execute potential acquisitions or take advantage of development opportunities.

Our expenditures for postretirement medical and life insurance benefits could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.

We provide various postretirement medical and life insurance benefits to current and former employees and their dependents. We estimate the amounts of these obligations based on assumptions described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies — Postretirement Benefits and Pension Obligations.” We accrue amounts for these obligations, which are unfunded, and we pay as costs are incurred. If our assumptions change, the amount of our obligations could increase, and if our assumptions are inaccurate, we could be required to expend greater amounts than we anticipate. We estimate that our gross obligation for postretirement medical and life insurance benefits was $259.8 million at December 31, 2004. We had an accrued liability for postretirement medical and life insurance benefits of $134.2 million at December 31, 2004, and we will accrue an additional $125.6 million over the next ten years, as permitted by Statement of Financial Accounting Standards No. 106. We regularly revise our estimates, and the amount of our accrued obligations is subject to change.

We have a significant amount of debt, which imposes restrictions on us and may limit our flexibility, and a decline in our operating performance may materially affect our ability to meet our future financial commitments and liquidity needs.

As of December 31, 2004, our total indebtedness was approximately $117.3 million, which included Westmoreland Mining’s obligations under its term loan agreement, including the add-on facility described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Revenues and expenses; sources and uses of cash.” We will assume significant non-recourse debt upon completion of the ROVA acquisition, we may incur additional indebtedness to finance the ROVA acquisition and we may incur additional indebtedness in the future, including indebtedness under our two existing revolving credit facilities.

Westmoreland Mining’s term loan agreement restricts its ability to distribute cash to Westmoreland Coal Company through 2011 and limits the types of transactions that Westmoreland Mining and its subsidiaries can engage in with Westmoreland Coal Company and our other subsidiaries. Westmoreland Mining executed the term loan agreement in 2001 and used the proceeds to finance its acquisition of the Rosebud, Jewett, Beulah and Savage Mines. The final payment on this indebtedness, which we call Westmoreland Mining’s acquisition debt, is in the amount of $30 million and is due on December 31, 2008. After payment of principal and interest, 25% of Westmoreland Mining’s surplus cash flow is dedicated to an account that is expected to fund this final payment. Westmoreland Mining has pledged or mortgaged substantially all of its assets and the assets of the Rosebud, Jewett, Beulah and Savage Mines, and we have pledged all of our member interests in Westmoreland Mining, as security for Westmoreland Mining’s indebtedness. In addition, Westmoreland Mining must comply with financial ratios and other covenants specified in the agreements with its lenders. Failure to comply with these ratios and covenants or to make regular payments of principal and interest could result in an event of default.

A substantial portion of our cash flow must be used to pay principal of and interest on our indebtedness and is not available to fund working capital, capital expenditures or other general corporate uses. In addition, the degree to which we are leveraged could have other important consequences, including:

•

increasing our vulnerability to general adverse economic and industry conditions;

•

limiting our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements; and

•

limiting our flexibility in planning for, or reacting to, changes in our business and in the industry.

If our or Westmoreland Mining’s operating performance declines, or if we or Westmoreland Mining do not have sufficient cash flows and capital resources to meet our debt service obligations, we or Westmoreland Mining may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. If Westmoreland Mining were to default on its debt service obligations, a note holder may be able to foreclose on assets that are important to our business.

At January 31, 2005, the ROVA Project had total debt of approximately $194 million. The ROVA Project’s credit agreement restricts its ability to distribute cash, contains financial ratios and other covenants, and is secured by a pledge of the project and substantially all of the project’s assets. If the ROVA Project fails to comply with these ratios and covenants or fails to make regular payments of principal and interest, an event of default could occur. A substantial portion of the ROVA Project’s cash flow must be used to pay principal of and interest on its indebtedness and is not available to us. If the ROVA Project were to default on its debt service obligations, a creditor may be able to foreclose on assets that are important to our business.

If the cost of obtaining new reclamation bonds and renewing existing reclamation bonds continues to increase, our profitability could be reduced.

Federal and state laws require that we provide bonds to secure our obligations to reclaim lands used for mining. We must post a bond before we obtain a permit to mine any new area. These bonds are typically renewable on a yearly basis and have become increasingly expensive. Bonding companies are requiring that applicants collateralize a portion of their obligations to the bonding company. In 2004, we paid approximately $2.5 million in premiums for reclamation bonds and posted approximately $3.2 million in collateral, in addition to the collateral that we had previously posted, for those bonds. Any capital that we provide to collateralize our obligations to our bonding companies is not available to support our other business activities. If the cost of our reclamation bonds continues to increase, our profitability could be reduced.

Our financial position could be adversely affected if we fail to maintain our Coal Act bonds.

The Coal Act established the 1992 UMWA Benefit Plan, or 1992 Plan. We are required to secure three years of our obligations to that plan by posting a surety bond or a letter of credit or collateralizing our obligations with cash. We presently secure these obligations with two bonds, one in an amount of approximately $21.3 million and one in an amount of approximately $5.0 million. In December 2003, the issuer of our $21.3 million bond indicated a desire to exit the business of bonding Coal Act obligations. In February 2004, this company renewed our Coal Act bond. Although we believe that the issuer of this bond must continue to renew the bond so long as we do not default on our obligations to the 1992 Plan, there can be no assurance that the issuer of this bond will not attempt to cancel the bond. If either of the companies that issue our Coal Act bonds were to cancel or fail to renew our bonds, we may be required to post another bond or secure our obligations with a letter of credit or cash. At this time, we are not aware of any other company that would provide a surety bond to secure obligations under the Coal Act. We do not believe that we could now obtain a letter of credit without collateralizing that letter of credit in full with cash. Any capital that we might provide to collateralize such a letter of credit or secure our obligations under the Coal Act would not be available to support our other business activities.

Our insurance costs may increase, which could increase our expenses and reduce our profitability.

Our insurance costs increased from July 2002 through December 2004, and we believe that insurance costs have generally increased throughout the mining industry. We have been able to address a portion of these costs by organizing Westmoreland Risk Management Ltd., our insurance subsidiary, and retaining a portion of the risk associated with our operations. However, Westmoreland Risk Management has limited capacity. Our insurance costs may increase in the future, and any such increase would increase our expenses and thereby reduce our profitability.

We face competition for sales to new and existing customers, and the loss of sales or a reduction in the prices we receive under new or renewed contracts would lower our revenues and could reduce our profitability.

Approximately one-third of the coal tonnage that we will produce in 2005 will be sold under long-term contracts to power plants that take delivery of our coal from common carrier railroads. All of the Absaloka Mine’s sales are delivered by rail and about 20% of the Rosebud Mine’s and Beulah Mine’s sales are delivered by rail. Contracts covering 90% of those rail tons are scheduled to expire between December 2006 and December 2008. As a general matter, plants that take coal by rail can buy their coal from many different suppliers. We will face significant competition, primarily from mines in the Southern Powder River Basin of Wyoming, to renew our long-term contracts with our rail-served customers, and for contracts with new rail-served customers. Many of our competitors are larger and better capitalized than we are and have coal with a lower sulfur and ash content than our coal. As a result, our competitors may be able to adopt more aggressive pricing policies for their coal supply contracts than we can. If our existing customers fail to renew their existing contracts with us on terms that are at least equivalent to those in effect today, or if we are unable to replace our existing contracts with contracts of equal size and profitability from new customers, our revenues and profitability would be reduced.

Approximately two-thirds of the coal tonnage that we will sell in 2005 will be delivered under long-term contracts to power plants located adjacent to our mines. We will face somewhat less competition to renew these contracts upon their expiration, both because of the transportation advantage we enjoy by being located adjacent to these customers and because most of these customers would be required to invest additional capital to obtain rail access to alternative sources of coal. Our Jewett Mine is an exception because our customer has already built rail unloading and associated facilities that are being used to take coal from the Southern Powder River Basin as permitted under our contract with that customer.

Stricter environmental regulations, including the EPA's proposed rule relating to mercury, could reduce the demand for coal as a fuel source and cause the volume of our sales to decline.

Coal contains impurities, including sulfur, mercury, nitrogen and other elements or compounds, many of which are released into the air when coal is burned. Stricter environmental regulation of emissions from coal-fired electric generating plants could increase the costs of using coal, thereby reducing demand for coal as a fuel source generally, and could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future. The U.S. Environmental Protection Agency, or EPA, has proposed regulations that could increase the costs of operating coal-fired power plants, including the ROVA Project. Congress is considering legislation that would have this same effect. Because different types of coal vary in their chemical composition and combustion characteristics, the proposed legislation and regulations could also alter the relative competitiveness among coal suppliers and coal types. Depending on the final forms of the rules or statutes that are ultimately adopted, any or all of our mines could be disadvantaged, and notwithstanding our coal supply contracts we could lose all or a portion of our sales volumes and face increased pressure to reduce the price for our coal, thereby reducing our revenues, our profitability and the value of our coal reserves.

On January 30, 2004, the EPA issued the Proposed National Emission Standards for Hazardous Air Pollutants, or Mercury Rule, which proposes to regulate emissions of mercury by electric generating units, or EGUs. The EPA issued a Supplemental Proposed Rule on March 16, 2004. These proposals contain three alternative methods for regulating emissions of mercury, including two alternatives that would establish standards of performance and cap-and-trade programs, and one alternative that would require EGUs to meet an emissions limit that is based on the installation of controls known as “maximum achievable control technologies,” or MACT. The MACT alternative would limit the amount of mercury that could be emitted from lignite-burning EGUs to 9.2 pounds of mercury for every trillion Btu those units produce, commencing as early as 2007. Mercury emissions from the Limestone Station, which burns lignite produced by our Jewett Mine, are higher than this level, and mercury emissions from the Coyote Station, which burns lignite produced by our Beulah Mine, may be higher than this level. According to the EPA, there are neither precombustion techniques nor proven technologies that are currently commercially available for reducing mercury emissions from lignite-burning EGUs to 9.2 pounds of mercury per trillion Btu produced, and there is also currently no proven technology for accurately measuring the mercury content in emissions. If the EPA were to adopt a version of the Mercury Rule that limits emissions of mercury to 9.2 pounds for every trillion Btu produced from lignite-burning plants, then sales from the Jewett Mine or Beulah Mine could be significantly reduced, and if the EPA were to adopt any version of the Mercury Rule, we could face increased pressure to reduce the price for our lignite to help defray the cost of complying with the regulations. The EPA has announced that it expects to adopt some version of the Mercury Rule by March 15, 2005.

The market’s reaction to proposed environmental regulations and legislation may also affect the competitiveness of coal from our mines. Market prices for sulfur dioxide emission allowances have increased from $150 in 2002 to about $720 at the end of 2004. This market appreciation began in late 2003 with speculation on the EPA’s proposed Clean Air Interstate Rule, which would effectively reduce the supply of such allowances by half in 2010 and by two-thirds in 2015. The Absaloka Mine presents an example of competitive conditions confronting the Company. Coal produced by the Absaloka Mine contains about 1.5 pounds of sulfur dioxide per million Btu, as compared to competing Southern Powder River Basin (“SPRB”) coal, which contains 0.6 pounds of sulfur dioxide per million Btu on average. Utility power plants are required under the Clean Air Act Amendments to surrender one emissions allowance for each ton of sulfur dioxide emitted during each year. As discussed above under “Business — Governmental Regulation — Proposed Environmental Rules and Legislation,” we anticipate that the EPA will adopt a version of the CAIR on March 15, 2005, if Congress has not adopted Clear Skies legislation. The Absaloka Mine’s contracts with its customers expire in 2006 and 2007, and depending on the reaction of the market for emission allowances to the final legislation or rules, the competitiveness of Absaloka coal could be reduced, we could lose all or a portion of our sales from the Absaloka Mine, and we could face increased pressure to reduce the price for Absaloka coal, thereby reducing our revenues, our profitability, and the value of the mine’s coal reserves.

New legislation or regulations in the United States aimed at limiting emissions of greenhouse gases could increase the cost of using coal or restrict the use of coal, which could reduce demand for our coal, cause our profitability to suffer and reduce the value of our assets.

A variety of international and domestic environmental initiatives are currently aimed at reducing emissions of greenhouse gases, such as carbon dioxide, which is emitted when coal is burned. If these initiatives were to be successful, the cost to our customers of using coal could increase, or the use of coal could be restricted. This could cause the demand for our coal to decrease or the price we receive for our coal to fall, and the demand for coal generally might diminish. Restrictions on the use of coal or increases in the cost of burning coal could cause us to lose sales and revenues, cause our profitability to decline or reduce the value of our coal reserves.

Demand for our coal could also be reduced by environmental regulations at the state level.

Environmental regulations by the states in which our mines are located, or in which the generating plants they supply operate, may negatively affect demand for coal in general or for our coal in particular. For example, Texas has passed regulations requiring all fossil fuel-fired generating facilities in the state to reduce nitrogen oxide emissions beginning in May 2003. In January 2004, we entered into a supplemental settlement agreement with Texas Genco II pursuant to which the Limestone Station must purchase a specified volume of lignite from the Jewett Mine. In order to burn this lignite without violating the Texas nitrogen oxide regulations, the Limestone Station is blending our lignite with coal, produced by others in the Southern Powder River Basin, and using emissions credits. Considerations involving the Texas nitrogen oxide regulations might affect the demand for lignite from the Jewett Mine in the period after 2007, which is the last year covered by the supplemental settlement agreement. Texas Genco II might claim that it is less expensive for the Limestone Station to comply with the Texas nitrogen oxide regulations by switching to a blend that contains relatively more coal from the Southern Powder River Basin and relatively less of our lignite. Other states are evaluating various legislative and regulatory strategies for improving air quality and reducing emissions from electric generating units. Passage of other state-specific environmental laws could reduce the demand for our coal.

We have significant reclamation and mine closure obligations. If the assumptions underlying our accruals are materially inaccurate, or if we are required to honor reclamation obligations that have been assumed by our customers or contractors, we could be required to expend greater amounts than we currently anticipate, which could affect our profitability in future periods.

We are responsible under federal and state regulations for the ultimate reclamation of the mines we operate. In some cases, our customers and contractors have assumed these liabilities by contract and have posted bonds or have funded escrows to secure their obligations. We estimate our future liabilities for reclamation and other mine-closing costs from time to time based on a variety of assumptions. If our assumptions are incorrect, we could be required in future periods to spend more on reclamation and mine-closing activities than we currently estimate, which could harm our profitability. Likewise, if our customers or contractors default on the unfunded portion of their contractual obligations to pay for reclamation, we could be forced to make these expenditures ourselves and the cost of reclamation could exceed any amount we might recover in litigation, which would also increase our costs and reduce our profitability.

We estimate that our gross reclamation and mine-closing liabilities, which are based upon permit requirements and our experience, were $317 million (with a present value of $141 million) at December 31, 2004. Of these liabilities, our customers have assumed a gross aggregate of $188 million and have secured a portion of these obligations by posting bonds in the amount of $50 million and funding reclamation escrow accounts that currently hold approximately $56 million, in each case at December 31, 2004. We estimate that our gross obligation for final reclamation that is not the contractual responsibility of others was $128 million at December 31, 2004, and that the present value of our net obligation for final reclamation that is not the contractual responsibility of others was $57 million at December 31, 2004.

Our profitability could be affected by unscheduled outages at the power plants we supply or own or if the scheduled maintenance outages at the power plants we supply or own last longer than anticipated.

Scheduled and unscheduled outages at the power plants that we supply could reduce our coal sales and revenues, because any such plant would not use coal while it was undergoing maintenance. We cannot anticipate if or when unscheduled outages may occur.

Our profitability could be affected by unscheduled outages at the ROVA Project or if scheduled outages at the ROVA Project last longer than we anticipate. For example, the ROVA I unit is scheduled to be out of service for 12 days in April and May 2005. The ROVA Project’s contract with Dominion Virginia Power is structured so that our annual revenues will not be adversely affected by this outage. However, if maintenance uncovers matters beyond those anticipated, the outage could be prolonged beyond the scheduled period, which could reduce the ROVA Project’s profitability and our revenues. In addition, if the maintenance uncovers a matter that must be remedied or repaired, the cost of those repairs may also adversely affect the ROVA Project’s profitability.

Increases in the cost of the fuel, electricity and materials we use to operate our mines could affect our profitability.

Under several of our existing coal supply agreements, our mines bear the cost of the diesel fuel, lubricants and other petroleum products, electricity, and other materials and supplies necessary to operate their draglines and other mobile equipment. The prices of many of these commodities have increased significantly in the last year, and continued escalation of these costs would hurt our profitability.

If we experience unanticipated increases in the capital expenditures we expect to make over the next several years, our profitability could suffer.

Over the next several years, we anticipate making significant capital expenditures, principally at the Rosebud and Jewett Mines, in order to add to and refurbish our machinery and equipment and prepare new areas for mining. We also expect to begin implementing a new enterprise resource planning system in 2005. The costs of any of these expenditures could exceed our expectations, which could reduce our profitability and divert our capital resources from other uses.

Our ability to operate effectively and achieve our strategic goals could be impaired if we lose key personnel.

Our future success is substantially dependent upon the continued service of our key senior management personnel, particularly Christopher K. Seglem, our Chairman of the Board, President and Chief Executive Officer. We do not have key-person life insurance policies on Mr. Seglem or any other employees. The loss of the services of any of our executive officers or other key employees could make it more difficult for us to pursue our business goals.

Provisions of our certificate of incorporation, bylaws and Delaware law, and our stockholder rights plan, may have anti-takeover effects that could prevent a change of control of our company that you may consider favorable, and the market price of our common stock may be lower as a result.

Provisions in our certificate of incorporation and bylaws and Delaware law could make it more difficult for a third party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our bylaws impose various procedural and other requirements that could make it more difficult for stockholders to effect some types of corporate actions. In addition, a change of control of our Company may be delayed or deterred as a result of our stockholder rights plan, which was initially adopted by our Board of Directors in early 1993 and amended and restated in February 2003. Our ability to issue preferred stock in the future may influence the willingness of an investor to seek to acquire our company. These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control of Westmoreland.

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 revenue volatility due to changes in commodity prices although some of the Company’s contracts are adjusted periodically based upon market prices. However, the Company is subject to variable costs for commodities it consumes such as diesel fuel, electricity and steel. 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, 2004.

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, 2004. Based on the balances outstanding as of December 31, 2004, a one percent change in the prime interest rate or LIBOR would increase interest expense by approximately $140,000 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

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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements	Page


Consolidated Balance Sheets	69

Consolidated Statements of Operations	71

Consolidated Statements of Shareholders’ Equity and Comprehensive Income	73

Consolidated Statements of Cash Flows	74

Summary of Significant Accounting Policies	75

Notes to Consolidated Financial Statements	82

Westmoreland Coal Company and Subsidiaries Consolidated Balance Sheets

December 31,	2004			2003

			(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	11,125		$	9,267
Receivables:
Trade		24,891			24,414
Other		4,399			4,465

		29,290			28,879
Inventories		14,952			14,289
Deferred overburden removal costs		12,034			9,559
Restricted cash		9,761			8,751
Deferred income taxes		13,501			12,921
Other current assets		6,239			4,468

Total current assets		96,902			88,134


Property, plant and equipment:
Land and mineral rights		22,234			20,740
Capitalized asset retirement cost		118,474			104,036
Plant and equipment		110,196			93,880

		250,904			218,656
Less accumulated depreciation, depletion and amortization		82,276			67,307

Net property, plant and equipment		168,628			151,349

Deferred income taxes		71,195			62,866
Investment in independent power projects		48,565			38,487
Excess of trust assets over pneumoconiosis benefit obligation		4,463			6,234
Restricted cash and bond collateral		22,921			16,218
Advanced coal royalties		3,521			4,013
Deferred overburden removal costs		3,910			3,095
Reclamation deposits		55,561			52,786
Contractual third party reclamation obligations		24,998			23,065
Other assets		13,325			11,590

Total Assets	$	513,989		$	457,837


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

Westmoreland Coal Company and Subsidiaries Consolidated Balance Sheets (Continued)

December 31,	2004			2003

			(in thousands)
Liabilities and Shareholders' Equity
Current liabilities:
Current installments of long-term debt	$	11,819		$	11,595
Accounts payable and accrued expenses:
Trade		24,769			26,559
Income taxes		71			-
Production taxes		18,316			16,127
Workers' compensation		1,288			2,016
Postretirement medical costs		16,437			20,275
1974 UMWA Pension Plan obligations		-			250
Asset retirement obligations		5,284			5,757

Total current liabilities		77,984			82,579


Long-term debt, less current installments		105,440			81,874
Workers' compensation, less current portion		9,646			7,462

Postretirement medical costs, less current portion		117,792			110,493
Pension and SERP costs		10,637			9,008
Asset retirement obligations, less current portion		135,509			117,586
Other liabilities		12,819			11,269
Minority interest		4,270			4,296

Commitments and contingent liabilities

Shareholders' equity:
Preferred stock of $1.00 par value
Authorized 5,000,000 shares;
Issued and outstanding 205,083 shares at
December 31, 2004 and 2003		205			205
Common stock of $2.50 par value
Authorized 20,000,000 shares;
Issued and outstanding 8,168,601 shares at
December 31, 2004 and 7,957,166 shares
at December 31, 2003		20,421			19,893
Other paid-in capital		75,366			72,825
Accumulated other comprehensive loss		(5,117)			(4,948)
Accumulated deficit		(50,983)			(54,705)

Total shareholders' equity		39,892			33,270

Total Liabilities and Shareholders' Equity	$	513,989		$	457,837

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

Westmoreland Coal Company and Subsidiaries Consolidated Statements of Operations

Years Ended December 31,		2004		2003		2002

		(in thousands except per share data)
Revenues:
Coal	$	320,291	$	294,986	$	301,235
Independent power projects - equity in earnings		12,741		15,824		14,506

		333,032		310,810		315,741

Cost and expenses:
Cost of sales - coal		249,300		228,433		226,707
Depreciation, depletion and amortization		15,888		12,599		11,539
Selling and administrative		30,852		33,386		31,732
Heritage health benefit costs		33,113		29,922		26,921
Loss (gain) on sales of assets		(77)		(645)		9

		329,076		303,695		296,908

Operating income from continuing operations		3,956		7,115		18,833

Other income (expense):
Interest expense		(10,084)		(10,114)		(10,821)
Interest income		3,811		1,952		2,117
Minority interest		(1,154)		(773)		(800)
Other income		997		1,169		2,011

		(6,430)		(7,766)		(7,493)

Income (loss) from continuing operations before income taxes and cumulative effect of change in accounting principle		(2,474)		(651)		11,340

Income tax benefit from continuing operations		6,934		10,971		2,368

Net income from continuing operations before cumulative effect of change in accounting principle		4,460		10,320		13,708

Discontinued operations:
Loss from operations of discontinued terminal segment (including impairment charge in 2002 of $3,712)		-		(988)		(5,971)
Gain on sale of discontinued terminal segment		-		4,509		-
Income tax benefit (expense)		-		(1,408)		2,388

Income (loss) from discontinued operations		-		2,113		(3,583)

Net income before cumulative effect of change in accounting principle		4,460		12,433		10,125

Cumulative effect of change in accounting principle, net of income tax expense of $108		-		161		-

Net income		4,460		12,594		10,125

Less preferred stock dividend requirements		1,744		1,752		1,772

Net income applicable to common shareholders	$	2,716	$	10,842	$	8,353

(Continued)

Westmoreland Coal Company and Subsidiaries Consolidated Statements of Operations (Continued)

Years Ended December 31,		2004		2003		2002

		(in thousand except per share data)
Net income per share applicable to common shareholders before cumulative effect of change in accounting principle:
Basic	$	0.34	$	1.37	$	1.10
Diluted	$	0.31	$	1.28	$	1.03
Net income per share applicable to common shareholders from cumulative effect of change in accounting principle:
Basic and diluted	$	-	$	0.02	$	-

Net income per share applicable to common shareholders:
Basic	$	0.34	$	1.39	$	1.10
Diluted	$	0.31	$	1.30	$	1.03

Pro forma amounts assuming the change in accounting principle is applied retroactively:
Net income applicable to common shareholders			$	10,681	$	8,200
Net income per share applicable to common shareholders:
Basic			$	1.37	$	1.08
Diluted			$	1.28	$	1.01

Weighted average number of common shares outstanding - basic		8,099		7,799		7,608
Weighted average number of common shares outstanding - diluted		8,662		8,338		8,147

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

Westmoreland Coal Company and Subsidiaries Consolidated Statements of Shareholders’ Equity and Comprehensive Income Years Ended December 31, 2002, 2003, and 2004

		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, 2001 (208,708 preferred 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
taxes of $2,207		-	-	-	(3,310)	-	(3,310)
Net unrealized change in interest
rate swap agreement, net of
taxes of $59		-	-	-	(88)	-	(88)
Comprehensive income							6,727

Balance at December 31, 2002 (206,833 preferred and 7,711,379 common shares outstanding)		207	19,278	70,908	(5,101)	(66,724)	18,568
Common stock issued as
compensation (131,087 shares)		-	327	1,524	-	-	1,851
Common stock options exercised
(114,700 shares)		-	288	120	-	-	408
Repurchase and retirement of
preferred shares (1,750 shares)		(2)	-	(211)	-	-	(213)
Dividends declared		-	-	-	-	(575)	(575)
Tax benefit of stock option exercises		-	-	484	-	-	484
Net income		-	-	-	-	12,594	12,594
Minimum pension liability, net of
taxes of $488		-	-	-	(732)	-	(732)
Net unrealized change in interest
rate swap agreement, net of
taxes of $590		-	-	-	885	-	885
Comprehensive income							12,747

Balance at December 31, 2003 (205,083 preferred and 7,957,166 common shares outstanding)		205	19,893	72,825	(4,948)	(54,705)	33,270
Common stock issued as
compensation (80,135 shares)		-	200	1,417	-	-	1,617
Common stock options exercised
(131,300 shares)		-	328	534	-	-	862
Dividends declared		-	-	-	-	(738)	(738)
Tax benefit of stock option exercises		-	-	590	-	-	590

Net income		-	-	-	-	4,460	4,460
Minimum pension liability, net of
taxes of $489		-	-	-	(733)	-	(733)
Net unrealized change in interest
rate swap agreement, net of
taxes of $376		-	-	-	564	-	564
Comprehensive income							4,291

Balance at December 31, 2004
(205,083 preferred and
8,168,601 common shares
outstanding)		$ 205	$ 20,421	$ 75,366	$ (5,117)	$ (50,983)	$ 39,892

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

Westmoreland Coal Company and Subsidiaries Consolidated Statements of Cash Flows

Years Ended December 31,		2004		2003		2002

		(in thousands)
Cash flows from operating activities:
Net income	$	4,460	$	12,594	$	10,125
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of independent power projects		(12,741)		(15,824)		(14,506)
Cash distributions from independent power projects		3,227		11,629		9,718
Deferred income tax benefit		(7,830)		(9,731)		(5,656)
Depreciation, depletion and amortization		15,888		12,599		11,539
Stock compensation expense		1,617		1,851		1,424
Impairment charges		-		-		3,712
Losses (gains) on sales of assets		(77)		(5,154)		9
Minority interest		1,154		773		800
Cumulative effect of change in accounting principle		-		(269)		-
Other		-		-		263
Changes in assets and liabilities:
Receivables, net		(411)		(668)		15,273
Inventories		(663)		(271)		(270)
Excess of trust assets over pneumoconiosis benefit obligation		1,771		1,431		(680)
Accounts payable and accrued expenses		561		1,343		(369)
Income taxes payable		71		(594)		537
Accrual for workers’ compensation		1,456		(1,262)		(2,301)
Accrual for postretirement medical costs		3,461		13,645		6,030
1974 UMWA Pension Plan obligations		(250)		(7,785)		(1,374)
Other assets and liabilities		(2,204)		10,447		(1,840)

Net cash provided by operating activities		9,490		24,754		32,434


Cash flows from investing activities:
Additions to property, plant and equipment		(18,324)		(13,240)		(7,323)
Reimbursement from mine operator		-		-		3,600
Change in restricted cash and bond collateral		(10,488)		(10,984)		(424)
Net proceeds from sales of assets		311		6,970		476

Net cash used in investing activities		(28,501)		(17,254)		(3,671)


Cash flows from financing activities:
Proceeds from long-term debt, net of debt issuance costs		34,104		9,373		-
Repayment of long-term debt		(11,679)		(14,561)		(13,753)
Net borrowings (repayments) of revolving lines of credit		(500)		(1,500)		(9,000)
Repurchase of preferred shares		-		(213)		(244)
Dividends paid to minority shareholders of subsidiary		(1,180)		(1,010)		(1,240)
Exercise of stock options		862		408		334
Dividends on preferred shares		(738)		(575)		(248)

Net cash provided by (used in) financing activities		20,869		(8,078)		(24,151)


Net increase (decrease) in cash and cash equivalents		1,858		(578)		4,612
Cash and cash equivalents, beginning of year		9,267		9,845		5,233

Cash and cash equivalents, end of year	$	11,125	$	9,267	$	9,845


Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest	$	9,629	$	9,814	$	10,176
Income taxes		552		737		886

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

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 entities 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.

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.

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.

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.

Until June 30, 2002, the Company was reimbursed for all operating expenses at the Jewett Mine on a current basis under the cost-plus-fees contract with its customer. Beginning July 1, 2002, the contract changed to a market-based, fixed price per ton arrangement. At that date, in compliance with its accounting policy, the Company began deferring the cost of overburden removal in advance of coal extraction until such time that the underlying coal is produced and sold. The amount to be deferred was originally based on the number of tons of exposed coal in the active pits at each period end. In order to better estimate deferred stripping expenses and achieve a proper matching of expenses with the revenues from tons sold, a change in the engineering estimates was made in 2003 to measure overburden removed above all in-pit tons, not just exposed tons. The impact of this change was an increase of $2.4 million in deferred overburden removal costs. Prior to 2003, the measurement of overburden removed above in-pit tons was not available. Therefore, the potential impact, if any, on prior periods is not determinable. The change was reflected as a change in estimate during 2003.

Workers’ Compensation and Pneumoconiosis Benefit Obligations

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

The liabilities for workers’ compensation claims and pneumoconiosis benefits are actuarially determined estimates of the ultimate losses incurred based on the Company’s experience, and include a provision for incurred but not reported losses. Adjustments to the probable ultimate liabilities are made annually based on subsequent developments and experience and are included in operations as incurred.

Reclamation Deposits and Contractual Third Party Reclamation Obligations

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 sources for use in final reclamation activities. The total reclamation deposits of $55.6 million at December 31, 2004 consist of $11.3 million of cash and cash equivalents and $44.3 million 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 $25.0 million as contractual third party reclamation obligations, representing the present value of obligations of certain customers and a contract miner.

The amortized cost, gross unrealized holding losses and fair value of held-to-maturity securities at December 31, 2004 are as follows (in thousands):

Amortized cost	$	44,325
Gross unrealized holding gains		42
Gross unrealized holding losses		(617)

Fair value	$	43,750

Maturities of held-to-maturity securities are as follows at December 31, 2004 (in thousands):

		Amortized Cost		Fair Value

Due in five years or less	$	15,898	$	15,780
Due after five years to ten years		14,203		13,946
Due in more than ten years		14,224		14,024

	$	44,325	$	43,750

Postretirement Benefits Other than Pensions

The Company accounts for health care and life insurance benefits provided for current and 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. Unrecognized actuarial gains and losses are amortized over the estimated average remaining service period for active employee plans and over the estimated average remaining life for retiree plans. 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.

Reclamation

On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”), a required new method of accounting for mine reclamation costs. Prior to the adoption of SFAS No. 143, reclamation costs were accrued on an undiscounted, units-of-production basis. SFAS No. 143 requires entities to record the fair value of asset retirement obligations using the present value of projected future cash flows, with an equivalent amount recorded as basis in the related long-lived asset. An accretion cost, representing the increase over time in the present value of the liability, is recorded each period and the capitalized cost is depreciated over the useful life of the related asset. As reclamation work is performed or liabilities are otherwise settled, the recorded amount of the liability is reduced.

Changes in the Company’s asset retirement obligations during 2004 and 2003 (in thousands) were:

		2004		2003

Asset retirement obligation - beginning of year	$	123,343	$	115,033
Accretion		8,351		7,815
Settlements (final reclamation performed)		(5,321)		(3,109)
Gains on settlements		(187)		(265)
Changes due to amount and timing of reclamation activities		14,607		3,869

Asset retirement obligation - end of year	$	140,793	$	123,343

As a result of the adoption of SFAS No. 143, in the first quarter of 2003 the Company recorded a gain of $161,000, net of tax expense of $108,000, for the cumulative effect of the change in accounting principle. The Company also reduced its recorded liability for mine reclamation from $159 million to $115 million as of January 1, 2003 and reduced the net book value of its property, plant and equipment from $189 million to $145 million on its Consolidated Balance Sheets as a result of the change from undiscounted to present values.

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.

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 2004, 2003 and 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 these dates. This additional minimum liability, net of income tax effect, 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 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 and net income per share as if the compensation cost for the Company’s stock options had been determined based on the fair value at the grant dates consistent with SFAS No. 123:

		2004		2003		2002

	(in thousands, except per share data)
Net income applicable to common shareholders:
As reported	$	2,716	$	10,842	$	8,353
Pro forma	$	1,968	$	10,067	$	6,698

Income per share applicable to common shareholders:
As reported, basic	$	0.34	$	1.39	$	1.10
Pro forma, basic	$	0.24	$	1.29	$	0.88
As reported, diluted	$	0.31	$	1.30	$	1.03
Pro forma, diluted	$	0.23	$	1.21	$	0.82

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 2003 and 2002. The weighted average fair value of options granted in 2004, 2003 and 2002 was $20.74, $11.88 and $13.92, respectively.

Options Granted	Dividend Yield	Volatility	Risk-Free Rate	Expected Life

2004	None	100%	4.05%	10 years
2003	None	100%	4.17%	10 years
2002	None	229%	5.04%	10 years

Earnings Per Share

Basic earnings per share is computed by dividing net income 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):

	2004	2003	2002

	(in thousands of shares)
Weighted average number of common shares outstanding:
Basic	8,099	7,799	7,608
Effect of dilutive instruments	563	539	539

Diluted	8,662	8,338	8,147


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.	10	374	309

Reclassifications

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

NEW ACCOUNTING PRONOUNCEMENTS

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” or SFAS 123R, which replaces SFAS No. 123 and supersedes APB Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005, with early adoption encouraged. The pro forma disclosures previously permitted under SFAS 123 no longer will be an alternative to financial statement recognition. The Company is required to adopt SFAS 123R in the third quarter of 2005, beginning July 1, 2005. Under SFAS 123R, the Company must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost, and the transition method to be used at the date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive option, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested stock options and restricted stock at the beginning of the first quarter of adoption of SFAS 123R, while the retroactive methods would record compensation expense for all unvested stock options and restricted stock beginning with the first period restated. The Company is evaluating the requirements of SFAS 123R and expects that the adoption of SFAS 123R will not have a material adverse impact on the Company’s financial position. The Company has not yet determined the method of adoption or the effect of adopting SFAS 123R, it has not determined whether the adoption will result in changes to net income that are similar to the current pro forma disclosures under SFAS 123 included in the Summary of Significant Accounting Policies above, and it has not determined if it will elect to adopt the provisions of SFAS 123R prior to July 1, 2005.

In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets—An Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions,” or SFAS 153. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. SFAS 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is effective for the fiscal periods beginning after June 15, 2005 and is required to be adopted by the Company in the first quarter of 2006. The Company is currently evaluating the effect that the adoption of SFAS 153 will have on its consolidated results of operations and financial condition but does not expect it to have a material impact.

Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements

December 31, 2004, 2003 and 2002

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 surface mines in 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 the sale of the Company’s interest in Dominion Terminal Associates (“DTA”), which was effective as of June 30, 2003, the Company was also engaged in the leasing of capacity at that coal storage and vessel loading facility. As described in Note 3, the Company’s share of DTA’s activities has been classified as discontinued operations in the Consolidated Statements of Operations.

2. WESTMORELAND ENERGY, LLC

Westmoreland Energy, LLC (“WELLC”), 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, 2004, WELLC held interests in three operating projects as listed and described in the summary below. The lenders to these 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.

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,		2004		2003

		(in thousands)
Assets
Current assets	$	47,109	$	38,549
Property, plant and equipment, net		237,343		246,796
Other assets		26,297		25,267

Total assets	$	310,749	$	310,612


Liabilities and equity
Current liabilities	$	34,019	$	29,884
Long-term debt and other liabilities		185,109		209,979
Equity		91,621		70,749

Total liabilities and equity	$	310,749	$	310,612


WELLC’s share of equity	$	48,565	$	38,487

Income Statements
For years ended December 31,		2004		2003		2002

		(in thousands)

Revenues	$	112,669	$	110,673	$	110,075
Operating income		40,768		45,918		46,731
Net income		25,063		30,446		28,935

WELLC’s share of earnings	$	12,424	$	15,242	$	14,506

WELLC performs asset management services for the partnerships and has recognized related revenues of $258,000 for each of the years ended December 31, 2004, 2003 and 2002. Management fees, net of related costs, are recorded as other income when the service is performed.

On August 25, 2004, we signed an Interest Purchase Agreement with a subsidiary of LG&E Energy LLC. The term “LG&E” refers to LG&E Energy LLC and its subsidiaries. In that agreement, the Company agreed to acquire LG&E’s 50% interest in the ROVA project for (1) a cash payment to LG&E at closing of approximately $22 million and (2) the assumption by the Company’s subsidiaries of LG&E’s portion of the ROVA project’s debt. LG&E’s share of this debt is approximately $103 million at December 31, 2004. The purchase price will be reduced by the amount of any distributions LG&E receives between August 2004 and closing. On January 31, 2005, LG&E received a distribution of $4.6 million. In addition, the Company must post cash or letters of credit with a value of approximately $9.8 million to replace LG&E’s portion of the ROVA project’s debt service reserve accounts. In November 2004, Dominion Virginia Power, the purchaser of the electricity generated by the ROVA Project, asserted that it had a right of first refusal with respect to LG&E’s interest. The Company is negotiating with Dominion Virginia Power to address its claim. The Interest Purchase Agreement has not been terminated or amended and remains in effect pending resolution of Dominion Virginia Power’s claim and receipt of the remaining consents necessary to complete the transaction.

3. INVESTMENT IN DOMINION TERMINAL ASSOCIATES (DTA)

Prior to June 30, 2003, the Company had a 20% interest in DTA, a partnership which operates a coal-storage and vessel-loading facility in Newport News, Virginia. Due to declining export business, the Company’s original investment in DTA was written down from $17.6 million to $5.5 million in 1998. The Company recognized a further non-cash impairment charge equal to the remaining book value of its investment in DTA during the third quarter of 2002 as a result of the terminal’s continuing operating losses and the terms of an agreement by one of the terminal’s other owners to dispose of its interest in DTA, but the Company continued to share in cash operating expenses and recognize losses until the sale of its own interest was completed.

Effective June 30, 2003, a subsidiary of Dominion Resources, Inc. purchased for $10.5 million the Company’s 20% partnership interest in DTA and its industrial revenue bonds. Under the terms of the Purchase and Sale Agreement, the Company guaranteed throughput at the terminal for a period of three years from the effective date of the sale. To secure the throughput commitment, $6.0 million of the purchase price was deposited into an escrow account as collateral for a stand-by letter of credit for the benefit of the purchaser. The Company does not expect to be able to deliver the minimum throughput. The Company also provided customary representations and warranties. The Company has guaranteed its obligations under the Purchase and Sale Agreement for a period of five years.

With the closing of this transaction the Company no longer incurs DTA-related operating losses, which were $1.0 million, $2.1 million and $1.9 million in 2003, 2002 and 2001, respectively. The Company also recognized a $4.5 million pretax gain in the second quarter of 2003.

As a result of 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. The basic income (loss) per share from these discontinued operations, including the gain on sale, was $.27 and ($.47) for the years ended December 31, 2003 and 2002, respectively. The diluted income (loss) per share from these discontinued operations was $.25 and ($.47) per share for 2003 and 2002, respectively.

4. LINES OF CREDIT AND LONG-TERM DEBT

The amounts outstanding at December 31, 2004 and 2003 under the Company’s lines of credit and long-term debt consist of the following:

		2004		2003

	(in thousands)
WML revolving line of credit	$	-	$	-
WML term debt		113,200		88,500
Corporate revolving line of credit		-		500
Other term debt		4,059		4,469

		117,259		93,469
Less current portion		(11,819)		(11,595)

	$	105,440	$	81,874

As of December 31, 2004, WML has a $12 million revolving credit facility (the “Facility”) with PNC Bank, National Association (“PNC”), which expires on April 27, 2007. The interest rate is either PNC’s Base Rate plus 1.50% or Euro-Rate plus 3.00%, 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.

In 2001, WML borrowed $120 million from a group of institutions using PNC Capital Markets, Inc. as lead arranger to fund the acquisitions of four coal mining operations and certain other assets. 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 of $30.0 million is due. The Series B Notes are secured by assets of WML.

The agreements governing 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 their business operations. WML is also required to maintain certain financial ratios as defined in the agreements. As of December 31, 2004, WML was in compliance with such covenants.

Under the terms of the 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) is applied to a prepayment account for repayment of the final $30 million of 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 a quarterly $500,000 management fee that WML pays the Company. At December 31, 2004, WML had funded $9.8 million in the debt service reserve account, which could be used for principal and interest payments, and $12.1 million in the long-term prepayment account. Those funds have been classified as restricted cash in the consolidated balance sheet.

On March 8, 2004, WML amended its term loan agreement to borrow an additional $35 million, $20.4 million in Series C Notes and $14.6 million in Series D Notes. The Series C Notes were drawn immediately and the Series D Notes were drawn in December 2004. Both series of notes require quarterly interest payments with principal payments beginning March 31, 2009 and final payment on December 31, 2011. The Series C Notes bear interest at a fixed rate of 6.85%, and the Series D Notes have a variable rate of interest based upon three-month LIBOR plus 2.90%. The new notes are secured by assets of WML and require the same covenants and financial ratios, as amended, as the Series A and B Notes.

The Company has a $14.0 million revolving credit agreement with First Interstate Bank. Interest is payable monthly at the Bank’s prime rate plus 1%. The Company is required to maintain certain financial ratios. The revolving credit agreement 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. The expiration date is June 30, 2006.

Other term debt consists of notes payable associated with reserve acquisitions, certain notes payable related to the purchase of real property, and capital lease obligations for mining equipment. These obligations expire at various dates through 2009 and bear interest at a weighted-average rate of 5.13%.

The maturities of all long-term debt and the revolving credit facilities outstanding at December 31, 2004 are (in thousands):

2005	$	11,819
2006		12,172
2007		12,800
2008		45,155
2009		11,980
Thereafter		23,333

	$	117,259

5. 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, $3.2 million, $834,000, and $449,000 were charged to operations in 2004, 2003 and 2002, respectively. The cash payments for workers’ compensation benefits were $1.8 million, $2.1 million and $2.8 million in 2004, 2003 and 2002, 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, 2004 and 2003, $5.0 million and $4.4 million respectively, were held in the collateral accounts.

6. PNEUMOCONIOSIS (BLACK LUNG) BENEFITS

The Company is self-insured for federal and state pneumoconiosis benefits for 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,		2004		2003

		(in thousands)
Actuarial present value of benefit obligation:
Expected claims from terminated employees	$	1,431	$	1,593
Claimants		20,324		20,368

Total present value of benefit obligation		21,755		21,961
Plan assets at fair value, primarily government-backed
securities		26,218		28,195

Excess of trust assets over pneumoconiosis benefit
obligations	$	4,463	$	6,234

The discount rates used in determining the accumulated pneumoconiosis benefit as of December 31, 2004 and 2003 were 5.75% and 6.25%, respectively.

7. 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 document. 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 than Pensions, or 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,		2004		2003

		(in thousands)
Assumptions:
Discount rate		5.75%		6.25%

Change in benefit obligation:
Net benefit obligation at beginning of year	$	237,554	$	223,478
Service cost		482		446
Interest cost		14,837		15,693
Plan amendments		(7,181)		(667)
Plan participant contributions		78		81
Actuarial loss		30,797		13,253
Gross benefits paid		(16,791)		(14,730)

Net benefit obligation at end of year		259,776		237,554

Change in plan assets:
Employer contributions		16,713		14,649
Plan participant contributions		78		81
Gross benefits paid		(16,791)		(14,730)

Fair value of plan assets at end of year		-		-

Funded status at end of year		(259,776)		(237,554)
Unrecognized net actuarial loss		92,745		73,407
Unrecognized net transition obligation		32,802		36,902

Net amount recognized at end of year	$	(134,229)	$	(127,245)

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


Year ended December 31,		2004		2003		2002

		(in thousands)
Assumptions:
Discount rate		6.25%		6.75%		7.25%

Components of net periodic benefit cost:
Service cost	$	482	$	446	$	400
Interest cost		14,837		15,693		14,989
Amortization of:
Transition obligation		4,100		4,100		4,100
Actuarial loss		4,278		4,532		2,899

Total net periodic benefit cost	$	23,697	$	24,771	$	22,388

Of the total net periodic benefit cost, $22.3 million, $23.4 million and $21.1 million, relates to the Company’s former eastern mining operations and is included in heritage health benefit costs in 2004, 2003 and 2002, respectively. The remainder of $1.4 million, $1.3 million and $0.8 million, respectively, relates to current operations.

Sensitivity of retiree welfare results (in thousands):

Effect of a one percentage point increase in assumed ultimate health care cost trend

- - on total service and interest cost components	$	1,626
- - on postretirement benefit obligation	$	27,539

Effect of a one percentage point decrease in
assumed ultimate health care cost trend

- - on total service and interest cost components	$	(1,479)
- - on postretirement benefit obligation	$	(24,840)

The health care cost trend assumed on covered charges was 11.00%, 8.50% and 9.25% for 2004, 2003 and 2002, respectively, decreasing to an ultimate trend of 5.0% in 2011 and beyond.

In December 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the “Act”) became law in the United States. The Act introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare benefit. Currently, the Company does not believe it will need to amend its plan to benefit from the Medicare benefit provided under the Act. The Company has reflected the estimated impact of the Act as a $16.5 million reduction in the present value of the accumulated post-retirement benefit obligation as of December 31, 2003.

Based on the same assumptions used in measuring the Company’s benefit obligation at December 31, 2004, the Company expects to pay benefits in each year from 2005 to 2009 of $18.2 million, $17.0 million, $17.6 million, $17.8 million and $18.0 million, respectively. The aggregate benefits expected to be paid in the five-years from 2010 to 2014 are $90.5 million.

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. The Company is required by the Coal Act to make monthly premium payments into the CBF. These payments are 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 $39.9 million at December 31, 2004. The Company expenses payments to the CBF when they are due. Payments are generally made on the due date. Payments in 2004, 2003 and 2002 were $9.4 million, $5.3 million and $5.2 million, respectively. See Note 13 to the Consolidated Financial Statements for additional information.

8. 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.

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, 2004 and 2003 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,		2004		2003		2004		2003

		(in thousands)
Assumptions:

Discount rate		6.00%		6.25%		6.00%		6.25%
Expected return on plan assets		8.50%		8.50%		N/A		8.50%
Rate of compensation increase		4.50%		4.50%		5.00%		5.00%

Change in benefit obligation:

Net benefit obligation at beginning of year	$	47,777	$	41,366	$	1,963	$	2,626
Service cost		2,407		2,138		58		59
Interest cost		3,174		2,839		128		127
Actuarial (gain) loss		3,091		2,638		126		(773)
Gross benefits paid		(494)		(1,204)		(76)		(76)

Net benefit obligation at end of year		55,955		47,777		2,199		1,963

Change in plan assets:

Fair value of plan assets at beginning of year		32,848		30,147		-		-
Actual return on plan assets		3,318		3,905		-		-
Employer contributions		3,431		-		76		76
Gross benefits paid		(494)		(1,204)		(76)		(76)

Fair value of plan assets at end of year		39,103		32,848		-		-

Funded status at end of year		(16,852)		(14,929)		(2,199)		(1,963)
Unrecognized net actuarial (gain) loss		16,355		14,659		(177)		(310)
Unrecognized prior service cost		54		105		65		75
Unrecognized net transition asset		-		(4)		-		-

Accrued benefit cost		(443)		(169)		(2,311)		(2,198)

Amounts recognized in the accompanying balance sheet consist of:

Accrued benefit cost		(443)		(169)		(2,311)		(2,198)
Minimum pension liability		(7,959)		(6,717)		-		-

Net amount recognized at end of year	$	(8,402)	$	(6,886)	$	(2,311)	$	(2,198)

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

		Qualified Pension Benefits						SERP Benefits

Year ended December 31,		2004		2003		2002		2004		2003		2002

		(in thousands)
Assumptions:

Discount rate		6.25%		6.75%		7.25%		6.25%		6.75%		7.25%
Expected return on plan assets		8.50%		8.50%		9.00%		N/A		N/A		N/A
Rate of compensation increase		4.50%		4.50%		4.50%		5.00%		5.00%		5.00%

Components of net periodic benefit cost

Service cost	$	2,407	$	2,139	$	1,943	$	58	$	59	$	76
Interest cost		3,174		2,839		2,556		128		127		170
Expected return on assets		(2,774)		(2,393)		(2,975)		-		-		-
Amortization of:
Transition asset		(4)		(6)		(6)		-		-		-
Prior service cost		50		50		50		10		84		76
Actuarial (gain) loss		851		803		97		(6)		(16)		22

Total net periodic pension cost	$	3,704	$	3,432	$	1,665	$	190	$	254	$	344

The weighted-average asset allocation of the Company’s qualified pension trusts at December 31, 2004 and 2003 was as follows:

	Allocation of Plan Assets at December 31

	2004	2003	Target Allocation

Asset Category
Cash and equivalents	-%	-%	0%-25%
Equity securities	70%	70%	40%-75%
Debt securities	28%	29%	0%-50%
Other	2%	1%	0%-10%

Total	100%	100%

The Company’s investment goals are to maximize returns subject to specific risk management policies. Its risk management policies permit investments in mutual funds, and prohibit direct investments in debt and equity securities and derivative financial instruments. The Company addresses diversification by the use of mutual fund investments whose underlying investments are in domestic and international fixed income securities and domestic and international equity securities. These mutual funds are readily marketable and can be sold to fund benefit payment obligations as they become payable.

The Company expects to contribute $2.2 million to its qualified pension plans and $76,000 to its SERP in 2005.

The benefits expected to be paid in each year from 2005 to 2009 are $605,000, $836,000, $1.1 million, $1.5 million and $1.8 million, respectively. The aggregate benefits expected to be paid in the five years from 2010 to 2014 are $15.8 million. The expected benefits are based on the same assumptions used to measure the company’s benefit obligation at December 31 and include estimated future employee service.

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 a multiemployer plan under ERISA.

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. That withdrawal occurred for the Company with the cessation of eastern mining operations, its only operations at that time which utilized UMWA employees. In 1996, the Company recorded its withdrawal liability, which was estimated by the 1974 UMWA Pension Plan at $13.8 million. The Company disputed the amount of this obligation through arbitration. In accordance with MPPA, the Company amortized this withdrawal liability, with interest, during the arbitration process by making payments of approximately $172,500 per month. The final phase of the arbitration was scheduled for April 2004. On March 8, 2004, the Company reached a settlement agreement with the 1974 UMWA Pension Plan whereby its obligation was considered fully repaid after making the monthly payment in February 2004. As a result, the Company reduced the recorded amount of its obligation and reduced the amount of its heritage health benefit costs for 2003 by $6.3 million. No further contributions will be required.

9. INCOME TAXES

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

		2004		2003		2002

		(in thousands)
Current:
Federal	$	295	$	25	$	-
State		601		251		900

		896		276		900
Deferred:
Federal		(7,074)		(9,599)		(5,605)
State		(756)		(132)		(51)

		(7,830)		(9,731)		(5,656)


Income tax benefit	$	(6,934)	$	(9,455)	$	(4,756)

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

		2004		2003		2002

		(in thousands)

Computed tax expense at statutory rate	$	(841)	$	1,067	$	1,825
Increase (decrease) in tax expense resulting from:
Tax depletion in excess of book		(3,184)		(2,865)		(3,399)
Minority interest adjustment		406		263		272
State income taxes, net		(102)		78		720
Change in valuation allowance
relating to Federal income taxes		(2,793)		(7,768)		(4,149)
Other, net		(420)		(230)		(25)

Income tax expense (benefit)	$	(6,934)	$	(9,455)	$	(4,756)

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2004 and 2003 are presented below:

		2004		2003

Deferred tax assets:		(in thousands)

Federal net operating loss carryforwards	$	59,777	$	61,326
State net operating loss carryforwards		7,903		6,160
Alternative minimum tax credit carryforwards		2,902		2,632
Accruals for the following:
Workers' compensation		4,373		3,791
Postretirement benefit and pension obligations		54,518		49,601
Asset retirement obligations		19,599		13,397
1974 UMWA pension plan obligation		-		100
Other accruals		5,759		5,273

Total gross deferred assets		154,831		142,280
Less valuation allowance		(24,137)		(25,058)

Net deferred tax assets		130,694		117,222


Deferred tax liabilities:
Investment in independent power projects	$	(13,023)	$	(12,273)
Plant and equipment, differences due to depreciation and amortization		(31,190)		(26,668)
Excess of trust assets over pneumoconiosis benefit obligation		(1,785)		(2,494)

Total gross deferred tax liabilities		(45,998)		(41,435)

Net deferred tax asset	$	84,696	$	75,787

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

		2004		2003

	(in thousands)
Deferred income tax assets - current	$	13,501	$	12,921
Deferred income tax assets - long-term		71,195		62,866

	$	84,696	$	75,787

An income tax benefit of $590,000, $484,000 and $160,000 related to the exercise of stock options during 2004, 2003 and 2002, respectively, was added to other paid-in capital.

As of December 31, 2004, a minimum of $175.8 million 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 $154.8 million. As of December 31, 2004, 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	$	42,081
2011		36,479
2012		449
2018		531
2019		88,565
after 2019		7,711

Total	$	175,816

Current tax expense results from Federal Alternative Minimum Tax and estimated state income taxes. The deferred income tax benefit recorded for 2004 included a benefit of $2.8 million due to a reduction in the deferred income tax asset valuation allowance as a result of an increase in the amount of Federal net operating loss carryforwards the Company expects to use prior to their expiration through 2019. The increase in the expected amount of Federal net operating losses to be used in future years is primarily a result of the arbitration decision in 2004, which provides for a higher coal price for deliveries to Colstrip Units 1&2 through the expiration of that agreement in 2009. The deferred income tax benefit recorded for 2003 and 2002 included a benefit of $7.8 million and $4.1 million, respectively, for a reduction in the valuation allowance as a result of anticipated increased use of future net operating loss carryforwards.

The Company has alternative minimum tax credit carryforwards of $2.9 million which are available indefinitely to offset future Federal taxes payable. For Alternative Minimum Tax purposes, the Company has net operating loss carryforwards of approximately $17.7 million as of December 31, 2004. As of December 31, 2004, the Company also has available an estimated $13.9 million in net operating loss carryforwards in Colorado to reduce future taxable income.

10. CAPITAL STOCK

Each depositary share represents one-quarter of a share of Westmoreland’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 full amount of the quarterly dividend is $2.125 per preferred share or $0.53 per depositary share. Westmoreland resumed 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, 2005 amount to $16.3 million in the aggregate ($79.72 per preferred share or $19.93 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 Westmoreland is incorporated. Under Delaware law, Westmoreland 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 Westmoreland’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 $205,000 at December 31, 2004). The Company had shareholders’ equity of $39.9 million and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $20.6 million at December 31, 2004.

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. Quarterly dividends of $0.15 per depositary share were paid beginning October 1, 2002, increased to $0.20 per depositary share beginning October 1, 2003 and further increased to $0.25 per depositary share beginning October 1, 2004.

On August 9, 2002, our 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 was determined by our management based on its evaluation of our capital resources, the price of the depositary shares offered to us and other factors. We converted acquired depositary shares into shares of Series A Convertible Exchangeable Preferred Stock and retired the preferred shares. During the depositary share purchase program, we purchased a total of 14,500 depositary shares for an aggregate consideration of $457,000, including 7,000 shares purchased in 2003 for $213,000.

11. INCENTIVE STOCK OPTION AND STOCK APPRECIATION RIGHTS PLANS

As of December 31, 2004, 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 employee plans provide for the granting of ISO’s, non-qualified options under certain circumstances, stock appreciation rights and restricted stock. ISO’s generally vest over two years, expire ten years from the date of grant, and may not have an option price that is less than the market value of the stock on the date of grant. The maximum number of shares that could be issued or granted under these plans is 1,550,000, and as of December 31, 2004, 185,906 shares are available for future issue or grant.

The non-employee director plans generally allow the grant of options for 20,000 shares when elected or appointed, and options for 10,000 shares after each annual meeting. Beginning in 2003, rather than the grant of 10,000 options, each non-employee director was granted $30,000 worth of common shares which are restricted for one year from the date of grant. The maximum number of shares that could be issued or granted under these plans is 900,000, and as of December 31, 2004, 32,064 shares are available for future issue or grant.

During 2004, the Company granted 165,626 stock appreciation rights (SAR’s). The exercise price of each SAR is equal to the fair value of a share of the Company’s common stock on the date of the grant. After the SAR’s have vested, in one-third increments in 2005, 2006 and 2007, the holders may exercise the SAR’s and be paid value in shares of common stock based on the increase in the value of the common stock between the grant date and the exercise date. Based on the value of the Company’s common stock as of December 31, 2004, the value of the SAR’s was estimated to be $1.6 million, which would be equivalent to 55,753 shares.

Information for 2004, 2003 and 2002 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, 2001	$ 2.63-18.19	892,350	$ 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	998,050	7.17
Granted in 2003	10.48-18.08	189,350	17.08
Exercised in 2003	2.81-12.86	(114,700)	3.56
Expired or forfeited in 2003	12.86-18.19	(23,300)	15.11

Outstanding at December 31, 2003	2.63-18.19	1,049,400	9.22
Granted in 2004	22.86	10,000	22.86
Exercised in 2004	2.81-18.19	(131,300)	6.58
Expired or forfeited in 2004	12.86	(2,100)	12.86

Outstanding at December 31, 2004	$ 2.63-22.86	926,000	$ 9.74

Information about stock options outstanding as of December 31, 2004 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	448,000	3.8	$ 2.90	448,000	$ 2.90
5.01-10.00	10,000	5.9	7.41	10,000	7.41
10.01-15.00	116,435	7.3	12.42	101,435	12.67
15.01-22.86	351,565	7.8	17.62	171,423	17.67

$2.63-22.86	926,000	5.8	$9.74	730,858	$ 7.79

12. 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 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 and business development expenses. Summarized financial information by segment for 2004, 2003 and 2002 is as follows:

Year ended December 31, 2004

		Coal		Independent Power		Corporate		Total

		(in thousands)
Revenues:
Coal	$	320,291	$	-	$	-	$	320,291

Equity in earnings		-		12,741		-		12,741

		320,291		12,741		-		333,032
Costs and expenses:
Cost of sales – coal		249,300		-		-		249,300

Depreciation, depletion and amortization		15,723		19		146		15,888
Selling and administrative		19,021		981		10,850		30,852

Heritage health benefit costs		-		-		33,113		33,113
Gain on sales of assets		(77)		-		-		(77)

Operating income (loss) from continuing operations	$	36,324	$	11,741	$	(44,109)	$	3,956


Capital expenditures	$	17,710	$	47	$	567	$	18,324


Property, plant and equipment (net)	$	167,648	$	75	$	905	$	168,628

Year ended December 31, 2003

		Coal		Independent Power		Corporate		Total

		(in thousands)
Revenues:
Coal	$	294,986	$	-	$	-	$	294,986

Equity in earnings		-		15,824		-		15,824

		294,986		15,824		-		310,810
Costs and expenses:
Cost of sales – coal		228,433		-		-		228,433

Depreciation, depletion and amortization		12,451		22		126		12,599
Selling and administrative		23,626		1,013		8,747		33,386

Heritage health benefit costs		-		-		29,922		29,922
Gain on sales of assets		(194)		-		(451)		(645)

Operating income (loss) from continuing operations	$	30,670	$	14,789	$	(38,344)	$	7,115


Capital expenditures	$	13,110	$	1	$	129	$	13,240


Property, plant and equipment (net)	$	150,887	$	48	$	414	$	151,349

Year ended December 31, 2002

		Coal		Independent Power		Corporate		Total

		(in thousands)
Revenues:
Coal	$	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

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:

	2004	2003	2002
		(in thousands)

Customer A	$ 83,196	$ 99,688	$ 119,658
Customer B	70,909	70,431	64,007
Customer C	50,951	28,681	25,786

Percentage of total revenue	62%	64%	66%

13. COMMITMENTS AND CONTINGENCIES

Protection of the Environment

As of December 31, 2004 the Company has reclamation bonds in place for its active mines in Montana, North Dakota and Texas and for inactive mining sites in Virginia which are now awaiting final bond release. These government-required bonds assure that coal mining operations comply with applicable Federal and State regulations relating to the performance and completion of final reclamation activities. The Company estimates that the cost of final reclamation for its mines when they are closed in the future will total approximately $316.7 million, with a present value of $140.8 million, and that the Company is financially responsible for reclamation obligations with a present value of $57.2 million. The contractual third party reclamation obligations of certain customers and a contract mine operator are discussed below. The amount of the Company’s bonds exceeds the amount of its share of estimated final reclamation obligations as of December 31, 2004.

At the Rosebud Mine, certain customers were contractually obligated under a coal supply agreement to pay the final reclamation costs for a specific area of the mine. They satisfied that obligation by pre-funding their respective portions of those costs. The funds are invested in cash equivalents and government-backed interest-bearing securities. As of December 31, 2004, the value of those funds, classified as reclamation deposits on the Consolidated Balance Sheets, was $52.7 million. One customer under the same coal supply agreement elected not to pre-fund its obligation but in 2003 began to fund a separate reclamation account over the remaining term of the coal contract to satisfy the contract provisions. The balance in that account was $2.8 million and the present value of that customer’s obligation was $4.6 million as of December 31, 2004 and is classified as contractual third party reclamation obligations on the Consolidated Balance Sheets.

Also at the Rosebud Mine, all of the owners of the Colstrip Station are contractually required to reimburse the Company for contemporaneous reclamation costs as they are incurred. As of December 31, 2004, the total amount of such costs outstanding was $3.0 million, which amount is included in other receivables on the Consolidated Balance Sheets.

At the Jewett Mine, the customer is contractually responsible for all post-production reclamation obligations and has provided a $50.0 million corporate guarantee to the Railroad Commission of Texas to assure performance of such final reclamation. The present value of the customer’s obligation was $13.7 million as of December 31, 2004, which is classified as contractual third party reclamation obligations on the Consolidated Balance Sheets.

At the Absaloka Mine, the contract miner, Washington Group International (“WGI”), is obligated to perform the vast majority of all reclamation activities, including all final backfilling, regrading and seeding. Westmoreland Resources Inc. (“WRI”) owns the Absaloka Mine, and Westmoreland owns 80% of WRI. WRI has a maximum financial responsibility for these activities of $1.7 million, which amount is being pre-funded through annual installment payments of $113,000 through 2005. Once the contract miner has performed its final reclamation obligations, WRI will be responsible for site maintenance and monitoring until final bond release. To assure compliance, and as part of a settlement of several outstanding issues in 2002, the contract miner has established an escrow account into which 6.5% of every contract mining invoice payment is being deposited. The balance as of December 31, 2004 was $3.2 million which includes WRI’s 2004 annual installment of $113,000. The present value of the contract miner’s reclamation obligation was $6.7 million as of December 31, 2004, and is classified as contractual third party reclamation obligations on the Consolidated Balance Sheets.

Royalty Claims

The Company has received demand letters from the Montana Department of Revenue (“DOR”), as agent for the Minerals Management Service (“MMS”) of the U.S. Department of the Interior, asserting underpayment of certain royalties allegedly due at the Rosebud Mine. The claims relate to the fees the Company receives to transport coal from the contract delivery point to the customer, certain “take or pay” payments the Company received when its customers did not require coal, and adjustments for certain taxes. The total amount of the claims is approximately $15.5 million, including penalties and interest, which continues to accrue. The Company continues to receive transportation fees and expects DOR to assert claims for additional underpayment and to issue more demand letters until the appeal process is completed. The Company believes that the DOR/MMS claims are improper and is vigorously contesting them. The appeal process will take several years. In the event of a negative outcome with DOR and MMS, the Company believes that certain of the Company’s customers are contractually obligated to reimburse the Company for any claims paid plus legal expenses.

100

Purchase Price Adjustment

The final purchase price for the Company’s 2001 acquisition of the coal business of Entech LLC is subject to a final adjustment. Pursuant to the terms of the Stock Purchase Agreement, 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. In June 2001, Entech submitted proposed adjustments that would have increased the purchase price by approximately $9.0 million. In July 2001, the Company objected to Entech’s adjustments and submitted its own adjustments which would result in a substantial decrease in the original purchase price. The Stock Purchase Agreement requires that the parties’ disagreements be submitted to an independent accountant for resolution. The Company also submitted a timely claim for indemnification by Entech.

On March 16, 2004, the Company received notice that Entech and Touch America Holdings had initiated an adversary proceeding against us in the U.S. Bankruptcy Court in Delaware. The complaint re-asserted Entech’s proposed adjustments to the purchase price and alleged that the Company was holding approximately $9 million that is the property of the estates of Touch America and Entech. The Company, Touch America, and Entech subsequently agreed to refer the purchase price adjustment issues to an independent accountant as provided in the Stock Purchase Agreement. We also agreed which of Westmoreland’s objections to Entech’s closing certificate were to be resolved by the independent accountant and which should be resolved by the U.S. District Court in Delaware as claims for breaches of the representations and warranties in the Stock Purchase Agreement. In November 2004, the independent accountant issued a revised closing date certificate which related a small adjustment in Westmoreland’s favor. Entech promptly filed a request for reconsideration by the independent accountant. The Entech request for reconsideration has not been decided and the ultimate outcome of the independent accountant proceeding is still uncertain. Our claims against Entech for breach of representations and warranties have been set for trial in October 2005. At the conclusion of this litigation, the bankruptcy court will determine the priority of any claim by the Company and whether any judgment obtained by the Company can be offset against any judgment obtained by Entech. At this time, the outcome of this litigation is uncertain.

101

Tax Assessments

The ROVA project is located in Halifax County, North Carolina and is the County’s largest taxpayer. In 2002, the County hired an independent consultant to review and audit the property tax returns for the previous five years. In May 2002, the County advised the ROVA project that its returns were being scrutinized for potential underpayment due to undervaluation of property subject to tax. ROVA responded to the County that its valuation was consistent with a preconstruction agreement reached with the County in 1996. In late 2002, the ROVA projects received notice of an assessment of $4.6 million for the years 1997 to 2001. Since that date the County has increased the amount of its claim to $5.3 million, which includes tax years 1996, 2002 and 2003. With penalty and interest, the total amount claimed due by the County is $8.3 million. The ROVA Project filed a protest with the Property Tax Commission. On May 26, 2004, the Tax Commission denied the ROVA Project’s protest and issued an order consistent with the County’s assessment. The ROVA Project appealed the Tax Commission’s decision to the North Carolina Court of Appeals on June 24, 2004. LG&E has agreed that, if we complete the ROVA acquisition, LG&E will indemnify the ROVA Project for one-half of the taxes, penalties, and interest assessed by Halifax County for the period through December 31, 2003 and for one-half of our reasonable attorneys’ fees and expenses incurred in settling or otherwise resolving Halifax County’s claims for this period.

Other Contingencies

McGreevey Litigation

In late 2002, the Company was served with a complaint in a case styled McGreevey et al. v. Montana Power Company et al. in a Montana State court. The plaintiffs are former stockholders of Montana Power who filed their first complaint on August 16, 2001. This was the Plaintiffs’ Fourth Amendment Complaint which added Westmoreland as a defendant to a 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 Company and the purchasers of some of the businesses formerly owned by Montana Power Company and Entech, Inc., a subsidiary of Montana Power Company. The plaintiffs seek to rescind the sale by Montana Power of its generating, oil and gas, and transmission businesses, and the sale by Entech of its coal business or to compel the purchasers to hold these businesses in trust for the shareholders. The Plaintiffs contend that they were entitled to vote to approve the sale by Entech to the Company even though they were not shareholders of Entech. Westmoreland has filed an answer, various affirmative defenses and a counterclaim against the plaintiffs.

102

Combined Benefit Fund

The Company makes monthly premium payments to the UMWA Combined Benefit Fund (“CBF”), a multiemployer health plan neither controlled nor administered by the Company. The previous amount of the monthly premiums was less than $400,000 and is recalculated each October. In 1996, a Federal Court ordered a decrease in the premiums charged by the CBF as a result of a finding that the formula being used by the government to determine reimbursement for health benefits under the Coal Act had been discontinued and that the actual amounts received by the CBF should be used instead. In connection with a separate case brought by the CBF, the Trustees of the CBF obtained notice of a premium increase on June 10, 2003 for beneficiaries assigned to companies under the Coal Act from the Social Security Administration (“SSA”). The CBF seeks to impose the increase retroactively to 1995 and has imposed a retroactive “catch-up” premium equal to the entire amount alleged to be due for the period from 1995 through October 2003, payable over the twelve months commencing October 2003. The net effect of these assessments increased the Company’s monthly payments to the CBF to $859,000 for the twelve months ending September 2004. The Company paid the higher monthly invoices and is vigorously pursuing its legal remedies. The Company accrued the entire retroactive portion of the CBF premiums in 2003. In late 2004, the parties to this case filed motions for summary judgment and the Company is currently awaiting the Court’s decision.

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 $27.2 million, $24.2 million and $25.5 million in 2004, 2003 and 2002, respectively.

103

The Company has operating lease commitments expiring at various dates, primarily for real property and equipment. Rental expense under operating leases during 2004, 2003 and 2002 totaled $3.4 million, $2.9 million and $4.3 million, respectively. Minimum future rental obligations existing under these leases at December 31, 2004 are as follows (in thousands):


Lease Obligations

2005	$ 2,770
2006	2,011
2007	1,248
2008	901
2009 and thereafter	333

Long-Term Sales Commitments

The following table presents estimated 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)

2005	29.5
2006	28.9
2007	28.7
2008	22.5
2009	20.1

The tonnages in the table above represent estimated sales tonnage under existing, signed contracts and generally exclude pending or anticipated contract renewals or new contracts. These projections reflect customers’ scheduled major plant outages, if known.

14. RESTRICTED NET ASSETS OF WESTMORELAND MINING LLC

WML was formed for the purpose of facilitating the financing of two separate acquisitions completed effective April 30, 2001. The agreements governing the line of credit and term notes entered into by WML for that purpose restrict the cash and other assets available for distribution or dividend to the parent company or other entities in the consolidated group. See Note 4 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 $55.6 million 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 years ended December 31, 2004, 2003 and 2002, WML paid dividends and management fees to Westmoreland of $11.9 million, $14.7 million and $14.9 million, respectively. In addition, WML paid Westmoreland $19.3 million in 2004 to reduce its intercompany payable.

104

The following are the condensed consolidated financial statements of WML and its subsidiaries as of and for the years ended December 31, 2004 and 2003 (in thousands):

Condensed Consolidated Balance Sheets
	December 31,
		2004		2003
Cash and cash equivalents	$	4,627	$	4,053
Accounts receivable, net		23,951		19,452
Restricted cash		21,874		17,427
Deferred overburden removal costs		15,944		12,654
Other current assets		18,911		17,868
Property, plant and equipment, net		182,339		168,788
Reclamation deposits		55,561		52,786
Contractual third party reclamation obligations		18,278		19,843
Deferred income tax assets		2,633		-
Other assets		9,469		8,128

Total Assets	$	353,587	$	320,999


Accounts payable and accrued expenses	$	33,181	$	31,187
Payable to parent		10,000		23,018
Long-term debt and line of credit		117,259		92,969
Deferred tax liabilities		-		114
Asset retirement obligations		132,740		115,852
Other liabilities		13,286		11,874
Member’s equity		47,121		45,985

Total Liabilities and Member’s Equity	$	353,587	$	320,999

Condensed Consolidated Statement of Operations

	Year Ended December 31,
		2004		2003

Coal revenues	$	265,646	$	245,871
Cost of sales – coal		(204,738)		(186,855)
Depreciation and amortization expense		(17,195)		(14,478)
Selling and administrative expense		(19,061)		(20,627)
Management fees to parent		(2,000)		(2,000)


Operating income		22,652		21,911

Interest expense		(9,663)		(9,371)
Interest and other income		3,087		1,995


Income before income taxes and cumulative effect of change in accounting principle		16,076		14,535

Income tax expense		(5,027)		(5,020)


Net income before cumulative effect of change in accounting principle	$	11,049	$	9,515
Cumulative effect of change in accounting principle		-		358

Net income	$	11,049	$	9,873

105

Condensed Consolidated Statements of Cash Flows

	Year Ended December 31,
		2004		2003

Net income	$	11,049	$	9,873
Depreciation and amortization expense		17,195		14,478
Deferred income tax expense (benefit)		(2,747)		1,685
Cumulative effect of change in accounting principle		-		(358)
Changes in operating assets and liabilities		(14,450)		12,233

Cash provided by operating activities		11,047		37,911

Fixed asset additions		(16,067)		(12,760)
Increase in restricted cash		(7,222)		(7,846)
Proceeds from asset sales		302		973

Cash used in investing activities		(22,987)		(19,633)

Proceeds from borrowings of long-term debt, net		34,106		4,590
Repayment of long-term debt		(11,679)		(9,778)
Borrowings (repayments) under line of credit, net		-		(1,500)
Dividends to parent		(9,913)		(12,650)

Cash used in financing activities		12,514		(19,338)


Net increase in cash and cash equivalents		574		(1,060)
Cash and cash equivalents, beginning of year		4,053		5,113

Cash and cash equivalents, end of year	$	4,627	$	4,053

15. TRANSACTIONS WITH AFFILIATED COMPANIES

WRI has a coal mining contract with WGI, its 20% stockholder. Mining costs incurred under the contract were $22.3 million, $20.5 million and $18.0 million in 2004, 2003 and 2002, respectively.

106

16. QUARTERLY FINANCIAL DATA (UNAUDITED)

The quarterly data presented below reflect the reclassification of discontinued operations identified during the fourth quarter of 2003 and as a result differ from those previously filed. Summarized quarterly financial data for 2004 and 2003 are as follows:

		Three Months Ended
		March 31		June 30		Sept. 30		Dec. 31

		(in thousands except per share data)
2004
Revenues	$	82,537	$	88,701	$	84,096	$	77,698
Costs and expenses		78,933		84,411		82,558		83,174

Operating income (loss) from
continuing operations		3,604		4,290		1,538		(5,476)
Income (loss) from continuing
operations before income taxes and cumulative effect of
change in accounting principle		1,661		2,996		(455)		(6,676)
Income tax (expense) benefit from
continuing operations		875		1,829		1,678		2,552
Net income (loss)		2,536		4,825		1,223		(4,124)
Less preferred stock dividend
requirements		(436)		(436)		(436)		(436)

Net income applicable to common
shareholders	$	2,100	$	4,389	$	787	$	(4,560)

Net income per share applicable to common shareholders:
Basic	$	0.26	$	0.54	$	0.10	$	(0.56)
Diluted	$	0.25	$	0.51	$	0.09	$	(0.56)

Weighted average number of common and common equivalent shares outstanding:
Basic		8,009		8,082		8,141		8,163
Diluted		8,503		8,590		8,710		8,163

		Three Months Ended
		March 31		June 30		Sept. 30		Dec. 31

		(in thousands except per share data)
2003
Revenues	$	78,284	$	70,455	$	83,291	$	78,780
Costs and expenses		75,775		73,585		84,025		70,310

Operating income (loss) from
continuing operations		2,509		(3,130)		(734)		8,470
Income (loss) from continuing
operations before income taxes and cumulative effect of
change in accounting principle		605		(4,941)		(2,948)		6,633
Income tax (expense) benefit from
continuing operations		910		3,459		4,228		2,374
Income (loss) from discontinued operations		(184)		2,306		(9)		-
Cumulative effect of change in accounting principle		161		-		-		-
Net income		1,492		824		1,272		9,006
Less preferred stock dividend
requirements		(440)		(440)		(436)		(436)

Net income applicable to common
shareholders	$	1,052	$	384	$	836	$	8,570

Net income per share applicable to common shareholders:
Basic	$	0.14	$	0.05	$	0.11	$	1.08
Diluted	$	0.13	$	0.05	$	0.10	$	1.02

Weighted average number of common and common equivalent shares outstanding:
Basic		7,728		7,762		7,805		7,899
Diluted		8,223		8,331		8,378		8,426

107

Report of Independent Registered Public Accounting Firm

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, 2004 and 2003, 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, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Westmoreland Coal Company and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

As discussed in the summary of significant accounting policies to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of the Sponsoring Organizations of the Treadway Commission, and our report dated March 15, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Denver, Colorado
March 15, 2005

108

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Westmoreland Coal Company

We have audited management’s assessment, included in the accompanying Management Report on Internal Control over Financial Reporting, that Westmoreland Coal Company and subsidiaries (Westmoreland or the Company) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Westmoreland’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

109

In our opinion, management’s assessment that Westmoreland maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Westmoreland maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Westmoreland and subsidiaries as of December 31, 2004 and 2003, 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, 2004, and our report dated March 15, 2005 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Denver, Colorado
March 15, 2005

110

ITEM 9

–

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

This item is not applicable.

ITEM 9A

–

CONTROLS AND PROCEDURES

The Company’s management, with the participation of the Company’s chief executive officer and chief financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of December 31, 2004. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, means controls and other procedures of a company that 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. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Based on the evaluation of the Company’s disclosure controls and procedures as of December 31, 2004, the Company’s chief executive officer and chief financial officer concluded that, as of such date, the Company’s disclosure controls and procedures were effective at the reasonable assurance level.

No change in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended December 31, 2004 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management Report on Internal Control Over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) or 15d-15(f) under the Securities Exchange Act of 1934).

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.

111

Based on our assessment, management believes that, as of December 31, 2004, the Company’s internal control over financial reporting is effective based on those criteria.

The Company’s independent auditors have issued an audit report on our assessment of the Company’s internal control over financial reporting.

ITEM 9B

–

OTHER INFORMATION

All reports on Form 8-K that were required were filed during the fourth quarter of 2004.

112

PART III

ITEM 10

–

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The Company has adopted a code of ethics that applies to its directors, officers and employees. This code of ethics, known as the Code of Business Conduct, is available in the Investor Relations section of the Company’s Internet website, www.westmoreland.com, under “Corporate Governance.”

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 set forth in Item 10 above and 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

–

PRINCIPAL ACCOUNTANT FEES AND SERVICES

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.

113

PART IV

ITEM 15

–

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

a) 1.	The financial statements filed herewith are the Consolidated Balance Sheets of the Company and subsidiaries as of December 31, 2004 and December 31, 2003, 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, 2004 together with the Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements, which are contained in Item 8.

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 Current 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 of Westmoreland Coal Company (filed as Exhibit 3.1 to Westmoreland's Registration Statement on Form S-1 (Registration No. 333-117709) filed July 28, 2004 and incorporated herein by reference).

	(b)	Certificate of Correction to the Restated Certificate of Incorporation of Westmoreland Coal Company filed as Exhibit 3.1 to Westmoreland's Current Report on Form 8-K filed October 21, 2004, which Exhibit is incorporated herein by reference (SEC File #001-11155).

	(c)	Bylaws, as amended on June 18, 1999, and filed as Exhibit (3)(b) to Westmoreland's Current 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).

114


		(b)	Indenture between Westmoreland and Fidelity Bank, National Association, as Trustee relating to the Exchange Debentures (filed as Exhibit 4.2 to Westmoreland's Registration Statement on Form S-1 (Registration No. 333-117709) filed July 28, 2004 and incorporated herein by reference).

		(c)	Form of Exchange Debenture (filed as Exhibit 4.3 to Westmoreland's Registration Statement on Form S-1 (Registration No. 333-117709) filed July 28, 2004 and incorporated herein by reference).

		(d)	Deposit Agreement among Westmoreland, First Chicago Trust Company of New York, as Depository and the holders from time to time of the Depository Receipts (filed as Exhibit 4.4 to Westmoreland's Registration Statement on Form S-1 (Registration No. 333-117709) filed July 28, 2004 and 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, which Exhibit is incorporated herein 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 4.5 to Westmoreland's Registration Statement on Form S-1 (Registration No. 333-117709) filed July 28, 2004, 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 Executive Severance Policy was filed as Exhibit 10.2 to Westmoreland's Registration Statement on Form S-1 (Registration No. 333-117709) filed July 28, 2004 and is incorporated herein by reference.

115


		(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).

		(d)	Supplemental Executive Retirement Plan, effective January 1, 1992, for certain executive officers and other key individuals, to supplement Westmoreland's Retirement Plan 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 February 4, 1999 (SEC File #001-11155).

		(h)	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).

		(i)	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).

		(j)	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).

		(k)	Westmoreland Coal Company 2001 Directors Compensation Policy is incorporated herein by reference to Exhibit 10.11 to Westmoreland's Registration Statement on Form S-1 (Registration No. 333-117709) filed July 28, 2004.

116

		(l)	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).

		(m)	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).

		(n)	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).

		(o)	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).

		(p)	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).

		(q)	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).

		(r)	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 Westmoreland's Current Report on Form 8-K filed May 15, 2001 (SEC File #001-11155).

117

		(s)	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 Westmoreland's Current Report on Form 8-K filed May 15, 2001 (SEC File #001-11155).

		(t)	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).

		(u)	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).

		(v)	Amendment No. 2 to Credit Agreement dated February 27, 2002 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(w) to Westmoreland's Annual Report on Form 10-K for the year ended December 31, 2001 (SEC File #001-11155).

		(w)	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).

		(x)	Third Amendment to Term Loan Agreement dated March 8, 2004 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 10.1 to Westmoreland's Current Report on Form 8-K filed March 10, 2004 (SEC File #001-11155).

		(y)	Third Amendment to Credit Agreement dated March 8, 2004 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 10.2 to Westmoreland's Current Report on Form 8-K filed March 10, 2004 (SEC File #001-11155).

		(z)	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 to Westmoreland's Current Report on Form 8-K filed December 19, 2001 (SEC File #001-11155).

118

		(aa)	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 to Westmoreland's Current Report on Form 8-K filed January 28, 2003 (SEC File #001-11155).

		(bb)	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 to Westmoreland's Current Report on Form 8-K filed January 28, 2003 (SEC File #001-11155).

		(cc)	Third Amendment effective as of June 24, 2004 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 to Westmoreland's Current Report on Form 8-K filed June 30, 2004 (SEC File #011-11155).

		(dd)	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 purchasers in connection with the Term Loan Agreement, is incorporated herein by reference to Exhibit 99.4 to Westmoreland's Current Report on Form 8-K filed May 15, 2001 (SEC File #001-11155).

		(ee)	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 Westmoreland's Current Report on Form 8-K filed May 15, 2001 (SEC File #001-11155).

		(ff)	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 Westmoreland's Current Report on Form 8-K filed May 15, 2001 (SEC File #001-11155).

		(gg)	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 Westmoreland's Current Report on Form 8-K filed May 15, 2001 (SEC File #001-11155).

119

		(hh)	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 Westmoreland's Current Report on Form 8-K filed May 15, 2001 (SEC File #001-11155).

		(ii)	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 Westmoreland's Current Report on Form 8-K filed February 5, 2001 (SEC File #001-11155).

		(jj)	Westmoreland Coal Company 2002 Long-Term Incentive Stock Plan is incorporated herein by reference to Annex A to Westmoreland's Definitive Proxy Statement filed April 23, 2002 (SEC File #001-11155).

		(kk)	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).

		(ll)	Approved Westmoreland Coal Company 2000 Performance Unit Plan, dated May 22, 2003, is incorporated herein by reference to Exhibit 10.1 to Westmoreland's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (SEC File #001-11155).

		(mm)	First Amendment to Westmoreland Coal Company 2000 Non-employee Directors' Stock Incentive Plan, dated May 22, 2003, is incorporated herein by reference to Exhibit 10.2 to Westmoreland's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (SEC File #001-11155).

		(nn)	Termination Agreement for Robert J. Jaeger, Chief Financial Officer, is incorporated herein by reference to Exhibit 10.3 to Westmoreland's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (SEC File #001-11155).

		(oo)	Supplemental Settlement Agreement and Amendment of Existing Contracts Between Northwestern Resources Company and Texas Genco, L.P., dated January 30, 2004, is incorporated herein by reference to Exhibit 10(nn) to Westmoreland's Annual Report on Form 10-K for the year ended December 31, 2003 (SEC File #001-11155).

(21)

Subsidiaries of the Registrant

(23)

Consent of Independent Certified Public Accountants

(31)

Rule 13a-14(a)/15d-14(a) Certifications

(32)

Certifications pursuant to 18 U.S.C. Section 1350

120

SIGNATURES

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

	WESTMORELAND COAL COMPANY

Date: March 16, 2005	By: /s/ Ronald H. Beck
	Ronald H. Beck
	Vice President of Finance and Treasurer
	(A Duly Authorized Officer)

Date: March 16, 2005	By: /s/ Thomas S. Barta
	Thomas S. Barta
	Controller
	(Principal Accounting Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date

Principal Executive Officer:
	Chairman of the Board, President, and
/s/ Christopher K. Seglem	Chief Executive Officer	March 16, 2005
Christopher K. Seglem


Directors:


/s/ Michael Armstrong	Director	March 16, 2005
Michael Armstrong


/s/ Thomas J. Coffey	Director	March 16, 2005
Thomas J. Coffey


/s/ Pemberton Hutchinson	Director	March 16, 2005
Pemberton Hutchinson


/s/ Robert E. Killen	Director	March 16, 2005
Robert E. Killen


/s/ Thomas W. Ostrander	Director	March 16, 2005
Thomas W. Ostrander


/s/ James W. Sight	Director	March 16, 2005
James W. Sight


/s/ William M. Stern	Director	March 16, 2005
William M. Stern

121

/s/ Donald A. Tortorice	Director	March 16, 2005
Donald A. Tortorice

122

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Westmoreland Coal Company:

Under date of March 15, 2005, we reported on the consolidated balance sheets of Westmoreland Coal Company and subsidiaries as of December 31, 2004 and 2003, 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, 2004, which are included in the December 31, 2004 Annual Report on Form 10-K of Westmoreland Coal Company and subsidiaries. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related consolidated 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, present fairly, in all material respects, the information set forth therein.

KPMG LLP

Denver, Colorado
March 15, 2005

123

Schedule II

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

Valuation Accounts
Years ended December 31, 2004, 2003 and 2002

(in thousands)

		Balance at beginning of year	Deductions credited to earnings	Other Additions		Balance at end of year

Year ended December 31, 2004:

Allowance for doubtful accounts	$	2,441	-	-	$	2,441	(A)

Year ended December 31, 2003:

Allowance for doubtful accounts	$	2,441	-	-	$	2,441	(A)

Year ended December 31, 2002:

Allowance for doubtful accounts	$	2,957	(516)	-	$	2,441	(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.

124

EXHIBIT 21
Subsidiaries of the Registrant for the year ended December 31, 2004:

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
Texas Westmoreland Coal 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

125

EXHIBIT 23

Consent of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Westmoreland Coal Company:

We consent to the incorporation by reference in the registration statement (No. 2-90847, No. 33-33620, No. 333-56904, No. 333-66698, and No. 333-106852) on Form S-8 of Westmoreland Coal Company and subsidiaries of our reports dated March 15, 2005, with respect to the consolidated balance sheets Westmoreland Coal Company and subsidiaries as of December 31, 2004 and 2003, 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, 2004, and the related financial statement schedule, management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2004 and the effectiveness of internal control over financial reporting as of December 31, 2004, which reports appear in the December 31, 2004 Annual Report on Form 10-K of Westmoreland Coal Company.

Our reports refer to the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003.

KPMG LLP

Denver, Colorado
March 15, 2005

126

Exhibit 31

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 report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

	3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

	4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

		b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

		c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

		d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

127


	5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 16, 2005

/s/ Christopher K. Seglem

	Name:	Christopher K. Seglem
	Title:	Chairman of the Board, President and Chief Executive Officer

CERTIFICATION

I, Ronald H. Beck, certify that:

	1.	I have reviewed this Annual Report on Form 10-K of Westmoreland Coal Company;

	2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

	3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

	4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

128

		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

		b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

		c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

		d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 16, 2005

/s/ Ronald H. Beck

	Name:	Ronald H. Beck
	Title:	Vice President-Finance and Treasurer Acting Chief Financial Officer

129

Exhibit 32

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, 2004 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 16, 2005	/s/ Christopher K. Seglem
	Christopher K. Seglem
	Chief Executive Officer

Dated: March 16, 2005	/s/ Ronald H. Beck
	Ronald H. Beck
	Acting Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Westmoreland Coal Company and will be retained by Westmoreland Coal Company and furnished to the Securities and Exchange Commission or its staff upon request.

130

SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2004

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

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

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

PART I

PART II

PART III

PART IV

Coal Operations

Independent Power Operations

Other Activities

Seasonality

Government Regulation

Employees

Information about Segments

Available Information

Absaloka Mine

Rosebud Mine

Jewett Mine

Beulah Mine

Other

Legal proceedings involving Westmoreland Coal Company

Legal proceedings involving Westmoreland Coal Company and/or Westmoreland Energy

Legal proceedings involving Basin Resources, Inc.

Legal proceedings involving Westmoreland Coal Company, Westmoreland Resources, and/or Western Energy

Other

Executive Officers of the Registrant

Market Information:

Approximate Number of Equity Security Holders of Record:

Dividends:

Forward-Looking Disclaimer

Overview

Meeting Our Commitment to Preferred Stockholders

Critical Accounting Estimates and Related Matters

Contractual Obligations and Commitments

Growth and Development Strategy

Liquidity and Capital Resources

Liquidity Outlook

Financial Implications of the ROVA Acquisition

Off-Balance Sheet Arrangements

Risk Factors

Commodity Price Risk

Interest Rate Risk

Consolidation Policy

Use of Estimates

Coal Revenues

Cash Equivalents

Inventories

Property, Plant and Equipment

Advanced Coal Royalties

Deferred Overburden Removal Costs

Workers’ Compensation and Pneumoconiosis Benefit Obligations

Reclamation Deposits and Contractual Third Party Reclamation Obligations

Postretirement Benefits Other than Pensions

Reclamation

Income Taxes

Comprehensive Income

Incentive Stock Options

Earnings Per Share

Reclassifications

NEW ACCOUNTING PRONOUNCEMENTS

Westmoreland Coal Company and SubsidiariesNotes to Consolidated Financial Statements

1. NATURE OF OPERATIONS

2. WESTMORELAND ENERGY, LLC

3. INVESTMENT IN DOMINION TERMINAL ASSOCIATES (DTA)

4. LINES OF CREDIT AND LONG-TERM DEBT

5. WORKERS’ COMPENSATION BENEFITS

6. PNEUMOCONIOSIS (BLACK LUNG) BENEFITS

7. POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS

Single-Employer Plans

Multiemployer Plan

8. RETIREMENT PLANS

Defined Benefit Pension Plans

Supplemental Executive Retirement Plan

1974 UMWA Pension Plan

9. INCOME TAXES

10. CAPITAL STOCK

11. INCENTIVE STOCK OPTION AND STOCK APPRECIATION RIGHTS PLANS

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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

Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements