10-K 1 wcc_10k05.htm FORM 10-K Form 10-K

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, 2005

OR

(  ) TRANSITION 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.)

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

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

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

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

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

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

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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

                 Yes  ___          No   X 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

                 Yes  ___          No   X 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days.

                 Yes   X           No  ___

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

                          X            

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer ___ Accelerated filer  X  Non-accelerated filer ___

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

                 Yes  ___          No   X 

The aggregate market value of voting common stock held by non-affiliates as of June 30, 2005 was $147,054,000.

There were 8,425,323 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, 2006.

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

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


Item   Page

PART I

1 Business 5
1A Risk Factors 19
1B Unresolved Staff Comments 29
2 Properties 30
3 Legal Proceedings 38
4 Submission of Matters to a Vote of Security Holders 45

PART II

5 Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 49
6 Selected Financial Data 51
7 Management's Discussion and Analysis of Financial Condition and Results of Operations 52
7A Quantitative and Qualitative Disclosures About Market Risk 74
8 Financial Statements and Supplementary Data 75
9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 121
9A Controls and Procedures 121
9B Other Information 125

PART III

10 Directors and Executive Officers of the Registrant 126
11 Executive Compensation 126
12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 126
13 Certain Relationships and Related Transactions 126
14 Principal Accountant Fees and Services 126

PART IV

15 Exhibits, Financial Statement Schedule 127
 
Signatures 128

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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; the Company’s ability to complete the acquisition of the portion of the ROVA project that it does not currently own; the effect of regulatory and legal proceedings; environmental issues, including the cost of compliance with existing and future environmental requirements; the contingencies of the Company discussed in Note 20 to the Consolidated Financial Statements; the risk factors set forth below; 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.

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PART I

The words “we,” “our,” or “the Company” as used in this report refer to Westmoreland Coal Company and its applicable subsidiary or subsidiaries.

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.

Coal Operations

               We were the 8th largest coal producer in the United States, ranked by tons of coal mined in 2005. In 2005, we increased our coal production to 30.0 million tons, about 3% of all the coal produced in the United States.

               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.

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               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. We own 100% of each of our other subsidiaries, unless otherwise indicated.

               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. The Savage Mine produces lignite. 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    Total
2005    6,463    13,377    6,951    2,873    326    29,990
2004    6,488    12,655    6,453    3,053    375    29,024
2003    6,016    11,003    7,462    2,816    379    27,676

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               Coal and the Production of Electricity

               Over the last fifty years, coal has played a significant role in generating electricity in the United States. The following table, derived from the U.S. Energy Information Administration (“EIA”), 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   3,027   1,594   53%
2000   3,789   1,966   52%
2004 (2)   3,941   1,976   50%

__________

(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 1,976 billion kilowatt hours in 2004 to 2,754 billion kilowatt hours in 2025 and that the demand for coal used to generate electricity will increase 1.5% per year from 2004 through 2025.

               Customers, Competition, and Coal Supply Agreements

               We sell almost all of the coal that we produce to plants that generate electricity. In 2005, for example, we sold about 1% 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.

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               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 off road 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 principal customers, and that the next lowest-cost suppliers to these customers could be other mines of ours. 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 Burlington Northern Santa Fe Railway (“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 megawatts, or 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 at the end of 2007 and one covering 1.0 million tons per year that expires at the end of 2006. We receive prices under these contracts that are adjusted by specified inflation 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 at the end of 2009. The price we receive under this contract was increased beginning in 2006 and is also adjusted by specified inflation 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 at the end of 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.

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               The Rosebud Mine’s primary customers are the owners of the four-unit Colstrip Station, which has a generating capacity of approximately 2,200 MW, and is located adjacent to the mine. The Rosebud Mine has supplied the Colstrip Station since 1975 and 1976, 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, and 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 and contains two one-year extensions at the customer’s option. 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 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 Limestone Station is currently owned by NRG Texas, LLC (“NRGT”), a wholly owned subsidiary of NRG Energy, Inc. NRG acquired Texas Genco, LLC on February 2, 2006. The Jewett Mine has supplied the Limestone Station since 1985, when it commenced commercial operations. The Jewett Mine sells lignite to NRGT 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 NRGT’s predecessor have disputed the proper interpretation of some elements of the ALSA from time to time. In January of 2004, Texas Westmoreland and NRGT’s predecessor settled certain of the disputes between them. Among other things, Texas Genco, LLC committed to purchase approximately 6.5 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. A new interim agreement was reached in September 2005 that enhanced the economics of the Jewett Mine over previous interim pricing arrangements, provides capital to support mine development, improves the mechanics for determining equivalent market pricing pursuant to the parties’ underlying contract after 2007, and has returned Texas Westmoreland to a stable and satisfactory level of financial performance through the end of 2007, when the price will be determined annually based on equivalent market value or until the current long-term supply agreement is modified further or restructured.

               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 approximately 100 MW and is located in Mandan, North Dakota, approximately 74 miles from the mine. Coal is shipped to the Heskett Station on the 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 expired at the end of 2005, but we have continued shipments at new pricing levels pending execution of a new agreement. 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.

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               The Savage Mine supplies coal to the Lewis & Clark Station, which has a generating capacity of approximately 49 MW, and the American Crystal Sugars — 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)
2005   $  361,963   29,990     99%   $  11.47
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

(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 the Jewett Mine transitioned from cost-plus-fees pricing to a market-based pricing mechanism, effective July 1, 2002. That mechanism was, in turn, replaced by a fixed price in January 2004 and then a modified cost plus agreement in September 2005.


               Our coal revenues include amounts earned by our coal sales company from sales of coal produced by mines other than ours. In 2005, 2004 and 2003, such amounts were $9.8 million, $5.8 million and $5.5 million, respectively.

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               We consider a contract that calls for deliveries to be made over a period longer than one year a long-term contract. In 2005, our three largest contracts, with the owners of Colstrip Units 1&2, Colstrip Units 3&4 and Limestone Generating Station, accounted for 11%, 21% and 31%, respectively, of our coal revenues. No other contract accounted for as much as 10% of our coal revenues in 2005.

               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/or changes in our actual costs. Contracts may also contain periodic price 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 to reflect developments in the marketplace.

               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 2010, but have not included those tonnages in this projection.



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


2006 28.5
2007 28.1
2008 24.5
2009 20.8
2010 16.6

               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. The pending Heskett contract is not included in the table.

               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.

               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 non-mining use of the land before we mined.

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               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 involving all employees at all of our mines. Our mines focus on 100% compliance with safe practices, safety rules, and regulations.

               In 2005, we achieved a new record for safety performance. Our four Company-operated mines had no lost-time accidents and the Absaloka mine, which is operated by our contractor, had only one lost-time accident. Based on data from the Mine Safety and Health Administration (“MSHA”), an agency of the U.S. Department of Labor, our five mines had a lost-time incident rate of 0.10 in 2005, compared to the national average of 1.61 (preliminary) for surface 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 we refer to both units together as the ROVA Project. As described below, we 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.

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               The ROVA Project has a long-term contract with a fuel supplier and all three have 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
Fort Lupton
Location Weldon,
North Carolina
Weldon,
North Carolina
Fort 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 Xcel Energy
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 N/A
Contracts with fuel supplier expire in 2014 2014 N/A
Commercial Operation Commencement Date 1994 1995 1994
Contracts with steam host & electricity 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 2005, ROVA I had a capacity factor of 87% and ROVA II had a capacity factor of 86%. A plant’s capacity factor is the ratio of the amount of electricity it produced to the amount of electricity it could produce if it operated at maximum output. ROVA I produced 1,266,000 megawatt hours (MW) in 2005; ROVA II produced 334,000 MW 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 to acquire the 50% interest in the ROVA project that we do not currently own. LG&E Energy LLC is now a subsidiary of E.ON U.S. In November 2004, Dominion Virginia Power (“Dominion”), 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 Energy’s 50% interest. On March 24, 2005, Dominion filed a Petition for Declaratory Judgment in Virginia in the Circuit Court of the City of Richmond seeking an order validating its alleged right of first refusal under the power purchase agreement to acquire LG&E’s partnership interest in the ROVA Project. On April 29, 2005, the ROVA Project filed a demurrer in the Circuit Court of the City of Richmond requesting the Petition for Declaratory Judgment be denied.

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               On September 2, 2005, the Richmond Circuit Court granted the Partnership’s demurrer motion, effectively denying Dominion’s claim that it has a right of first refusal under the structure of the proposed acquisition. Dominion filed a motion for reconsideration of the court’s ruling and their motion was denied. Dominion can now file a new Motion for Summary Judgment based on amendments to the acquisition agreement or it can appeal the ruling on the Partnership’s demurrer motion.

               We are currently in discussions with Dominion and LG&E in the hope that this dispute can be resolved on business terms acceptable to all parties.

Other Activities

               As part of our April 2001 acquisition of the coal business of Montana Power Company, we obtained the stock of North Central Energy Company (“North Central”). North Central owned 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 $0.3 million and a royalty interest on production from wells drilled on North Central’s properties. Commercial production began in early 2004. In 2003, North Central sold certain surface and mineral property to local land owners for $1.4 million. North Central sold its undivided mineral interests including the royalty interest on coalbed methane production in early 2006 for approximately $5 million.

Insurance Subsidiary

               We have elected to retain some of the risks associated with operating our company. To do this, we established a wholly-owned, consolidated insurance subsidiary, Westmoreland Risk Management Ltd., in 2002 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 $3.4 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.

               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, 2005, except for de minimis sales to a Canadian utility.

Seasonality

Our business is somewhat seasonal:

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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.

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               Each of our mining operations must obtain all required permits before any activity can occur. Under the states’ approved programs, 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 (“SO2”) 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 ROVA Project is exempt from the Title IV SO2 program.

               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 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.

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               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 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 SO2 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. The effect of the rule on the power industry is still uncertain, and at this time we 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. Some states, including Montana, are considering laws and/or regulations pertaining to airborne emissions of mercury. We are unable at this time to determine how the Federal or state regulations could affect the coal industry and our business.

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               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 of 1992 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 adopted regulations that required compliance with the new nitrogen oxide limits beginning in June 2004.

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               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 1,052 people on December 31, 2005, compared with 943 people on December 31, 2004. 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 13 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 1A 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 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;


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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:

 

A dragline at Jewett experienced mechanical failures in July 2005 that took the machine out of service and reduced production for approximately four weeks.


 

In the second quarter of 2005, our Beulah Mine experienced unusually heavy rainfall including record rainfall in June that adversely impacted overburden stability and resulted in highwall and spoil sloughage, a condition in which the side of the pit partially collapses and must be stabilized before mining can continue. Unstable conditions in the pits impacted dragline operations at that mine for a period of time. This resulted in a reduction in coal production during the quarter and caused inventory to fall which negatively affected third and fourth quarter results.


 

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 2005, we sold approximately 99% 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 Generating Station, Colstrip Units 3&4 and Colstrip Units 1&2, accounted for 31%, 21% and 11%, respectively, of our coal revenues for 2005. 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.

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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 Item 3 – “Legal Proceedings” above, and in Note 20 (“Commitments and Contingencies”) to our Consolidated Financial Statements. Adverse outcomes in some or all of the pending cases could result in substantial damages against us or harm our business.

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 2005, we employed 1,052 people, including employees at subsidiaries.  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. In the second quarter of 2005, we hired a new Chief Financial Officer and new General Counsel. Eight of the eleven professional positions in our corporate-level finance and accounting department and both of the positions in our legal department are filled by individuals who have joined the Company since the beginning of 2005.  To manage our financial, accounting and legal matters effectively, these individuals must absorb considerable, necessary background information on the Company and we must successfully integrate them into our ongoing activities.  In the second quarter of 2005, we began to implement a new company-wide computer system.  The start-up of this new system has imposed increased demands on employees, particularly our finance and accounting staff.  If we are unable to attract and retain the personnel we need to manage our increasingly large and complex operations, if we are unable to integrate successfully our new officers and employees, and if we are unable to complete successfully the implementation of our new computer system, our ability to manage our operations effectively and to pursue our business strategy could be compromised.

The implementation of a new company-wide computer system could disrupt our internal operations.

               We are in the process of implementing a new company-wide computer system to replace the various systems that have been in place at our corporate offices, at the operations we owned in 2001, and at the operations we acquired in 2001. Once implemented, we expect this system to help establish standard, uniform, best practices and reporting in a number of areas, increase productivity and efficiency, and enhance management of our business.  Certain aspects of our information technology infrastructure and operational activities have and may continue to experience difficulties in connection with this transition and implementation.  Such difficulties can cause delay, be time consuming and more resource intensive than planned, and cost more than we anticipated.   There can be no assurance that we will achieve the cost savings and return on investment intended from this project.

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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 Estimates and Related Matters” herein and in Note 8 to the Consolidated Financial Statements. 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 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, 2005, our total gross indebtedness was approximately $112.2 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 — Liquidity and Capital Resources.” We will assume significant non-recourse debt if we successfully complete the ROVA acquisition. We may also 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. The $35 million add-on facility is scheduled to be paid-down from 2009 through 2011. 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 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.

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               A substantial portion of our cash flow must be used to pay principal 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 December 31, 2005, the ROVA Project had total debt of approximately $183 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 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 2005, we paid approximately $2.3 million in premiums for reclamation bonds and posted approximately $24.5 million in collateral, in addition to the collateral that we had previously posted, for those bonds. As we permit additional areas for our mines in 2006 and 2007, the bonding requirements are expected to increase significantly and the collateral posted is expected to increase as well. 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.

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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 with XL Specialty Insurance Company (“XL”) and an affiliate and one in an amount of approximately $5.0 million. In December 2003, XL indicated a desire to exit the business of bonding Coal Act obligations. In February 2004, XL renewed our Coal Act bond. Although we believe that XL must continue to renew the bond so long as we do not default on our obligations to the 1992 Plan, XL filed a Complaint for Declaratory Judgment on May 11, 2005 to force our payment of $21.3 million and 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. The Company does not currently have $21.3 million in cash available.

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 2006 will be sold under long-term contracts to power plants that take delivery of our coal from common carrier railroads. Most of the Absaloka Mine’s sales are delivered by rail (with 6% by truck starting in 2006) 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 2006 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.

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Stricter environmental regulations, including regulations recently adopted by the EPA, 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, adopted regulations in March 2005, that could increase the costs of operating coal-fired power plants, including the ROVA Project. Congress has considered legislation that would have this same effect. At this time, we are unable to predict the impact of these new regulations on our business. However, we expect that the new regulations may alter the relative competitiveness among coal suppliers and coal types. The new regulations could also disadvantage some or all of our mines, 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.

               In March 2005, the EPA issued the Clean Air Interstate Rule (“CAIR”) and Clean Air Mercury Rule (“CAMR”). The CAIR will reduce emissions of sulfur dioxide and nitrogen oxide in 28 eastern States and the District of Columbia. Texas and Minnesota, in which customers of the Jewett and Absaloka mines are located, and North Carolina, where the ROVA Project is located, are subject to the CAIR. The CAIR requires these States to achieve required reductions in emissions from electric generating units, or EGUs, in one of two ways: (1) through participation in an EPA-administered, interstate “cap and trade” system that caps emissions in two stages, or (2) through measures of the State’s choice. Under the cap and trade system, the EPA will allocate emission “allowances” for nitrogen oxide to each State. The 28 States will distribute those allowances to EGUs, which can trade them. To control sulfur dioxide, the EPA will reduce the existing allowance allocations for sulfur dioxide that are currently provided under the acid rain program established pursuant to Title IV of the Clean Air Act Amendments. EGUs may choose among compliance alternatives, including installing pollution control equipment, switching fuels, or buying excess allowances from other EGUs that have reduced their emissions. Aggregate sulfur dioxide emissions are to be reduced from 2003 levels in two stages, a 45% reduction by 2010 and a 57% reduction by 2015. Aggregate nitrogen oxide emissions are also to be reduced from 2003 levels in two stages, a 53% reduction by 2009 and a 61% reduction by 2015.

               The CAMR applies to all States. The CAMR establishes a two-stage, nationwide cap on mercury emissions from coal-fired EGUs. Aggregate mercury emissions are to be reduced from 1999 levels in two stages, a 20% reduction by 2010 and a 70% reduction by 2018. The EPA expects that, in the first stage, emissions of mercury will be reduced in conjunction with the reductions of sulfur dioxide and nitrogen oxide under the CAIR. The EPA has assigned each State an emissions “budget” for mercury, and each state must submit a State Plan detailing how it will meet its budget for reducing mercury from coal-fired EGUs. Again, States may participate in an interstate “cap and trade” system or achieve reductions through measures of the States’ choice. The CAMR also establishes mercury emissions limits for new coal-fired EGUs (new EGUs are power plants for which construction, modification, or reconstruction commenced after January 30, 2004).

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               These new rules are likely to affect the market for coal for at least three reasons:

 

Different types of coal vary in their chemical composition and combustion characteristics. For example, the lignite from our Jewett and Beulah mines is inherently higher in mercury than bituminous and sub-bituminous coal, and sub-bituminous coal from different seams can differ significantly.


 

Different EGUs have different levels of emissions control technology. For example, the ROVA Project has “state of the art” emissions control technology that reduces its emissions of sulfur dioxide, nitrogen oxide and, collaterally, mercury.


 

The CAIR is likely to affect the existing national market for sulfur dioxide emissions allowances, thereby indirectly affecting coal producers and consumers that are not directly subject to the CAIR.


               For all the foregoing reasons, and because it is unclear how States will allocate their emissions budgets, we are unable to predict at this time how these new rules will affect the Company.

               The Company’s contracts protect our sales positions, including volumes and prices, to varying degrees. However, we could face disadvantages under the new regulations that could result in our inability to renew some or all of our contracts as they expire or reach scheduled price reopeners or that could result in relatively lower prices upon renewal, thereby reducing our relative revenue, profitability, and/or the value of our 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 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 NRGT 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 four- year fixed price agreement. Not withstanding our contractual right to deliver approximately 6.5 million tons per year, NRGT 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.

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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 $396.1 million (with a present value of $158.4. million) at December 31, 2005. Of these liabilities, our customers have assumed a gross aggregate of $201 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 $58.8 million, in each case at December 31, 2005. We estimate that our gross obligation for final reclamation that is not the contractual responsibility of others was $195 million at December 31, 2005.

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.

Increases in the cost of the fuel, electricity and materials and the availability of tires we use in the operation of 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. In particular, the cost of tires for our heavy equipment at the mines has increased drastically in 2005 as the supply has tightened due to world-wide demand, which impacts productivity and could even reduce production if replacement tires are not available. The prices of many of these commodities have increased significantly in the last year, and continued escalation of these costs would hurt our profitability or threaten the financial condition of certain operations in the absence of corresponding increases in revenue.

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

               Certain of our contracts provide for our customers to reimburse us for our capital expenditures on a depreciation and amortization basis, plus in some instances, a stated return-on-investment. Certain contracts provide reimbursement of capital expenditures in full as such expenditures are incurred. Other contracts feature set prices that adjust only for changes in a general inflation index. When we spend capital at our operations, it affects our near term liquidity in most instances and if capital is spent where the customer is not specifically obligated to reimburse us, that capital could be at risk if market conditions and contract duration do not match up to the investment.

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 bring about 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.

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Our ability to operate effectively and achieve our strategic goals depends on maintaining satisfactory labor relations.

               A significant portion of the workforce at each of the Company’s mines, except Jewett, is represented by labor unions. While we believe that our relationships with our employees at the mines is very good, the nature of collective bargaining is such that there is a risk of a disruption in operations when any collective bargaining agreement reaches its expiration dates unless a renewal or extension has been accepted by the employees who are covered by the agreement. While labor strikes are generally a force majeure event in long-term coal supply agreements, thereby exempting the mine from its delivery obligations, the loss of revenue for even a short period of time could have a material adverse effect on the Company’s financial results.

We have had material weaknesses in internal control over financial reporting in the past and cannot assure you that additional material weaknesses will not be identified in the future. Our failure to maintain effective internal control over financial reporting could result in material misstatements in our financial statements which could require us to restate financial statements, cause investors to lose confidence in our reported financial information and have a negative effect on our stock price.

               During the past year, the Company identified two material weaknesses in internal controls over financial reporting as defined in the Public Company Accounting Oversight Board’s Auditing Standard No. 2 that, if undetected, could have affected our financial statements for the year ended December 31, 2005. The material weaknesses in our internal control over financial reporting during the past year related to ineffective management review of certain processes. See “Item 9A – Controls and Procedures” for more specific details.

               We cannot assure that additional significant deficiencies or material weaknesses in our internal control over financial reporting will not be identified in the future. Any failure to maintain or implement new or improved controls, or any difficulties we encounter in their implementation, could result in additional significant deficiencies or material weaknesses, and cause us to fail to meet our periodic reporting obligations or result in material misstatements in our financial statements. Any such failure could also adversely affect the results of periodic management evaluations and annual auditor attestation reports regarding the effectiveness of our internal control over financial reporting required under Section 404 of the Sarbanes-Oxley Act of 2002 and the rules promulgated under Section 404. The existence of a material weakness could result in errors in our financial statements that could result in a restatement of financial statements, cause us to fail to meet our reporting obligations and cause investors to lose confidence in our reported financial information, leading to a decline in our stock price.

ITEM 1B UNRESOLVED STAFF COMMENTS

               None

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ITEM 2 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” 199.2 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.

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The following table provides information about our mines as of December 31, 2005.

  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)(4)
  Probable (3)
38,212(2)
64,800
242,818(2)
0
75,223
0
41,411(2)
14,672
8,385(2)
0
Permitted Reserves
(thousands of tons)
13,465 168,498 75,223 26,588 2,570
Coal Deposits
(thousands of tons)(3)
487,000 186,160 0 0 10,095
2005 Production
(thousands of tons)
6,463 13,407 6,973 2,876 330
Lessor Crow Tribe Federal Govt;
State of MT;
Great Northern
Properties
Private parties;
State of Texas
Private parties;
State of ND;
Federal Govt
Federal Govt;
Private parties
Lease Term Through exhaustion Varies Varies 2009-2019 Varies
Current production capacity
(thousands of tons)
7,000 13,300 7,000 4,000 400
Coal Type Sub-bituminous Sub-bituminous Lignite Lignite Lignite
Acres disturbed by Mining 3,820 15,819 14,460 4,521 534
Acres for which reclamation is complete 2,675 7,123 10,253 3,118 209
Major Customers Xcel Energy, Western Fuels Assoc., Midwest Energy, Rocky Mountain Power Colstrip 1&2 owners, Colstrip 3&4 owners, Minnesota Power NRGT Otter Tail, MDU, Minnkota, Northwestern Public Service MDU, Sidney Sugars
Delivery Method Rail/Truck Truck / Rail / Conveyor Conveyor Conveyor / Rail Truck
Approx. Heat Content
(BTU/lb.) (5)
8,700 8,529 6,613 6,941 6,371
Approx. Sulfur Content
(%) (6)
0.65 0.74 1.06 1.05 0.45
Year Opened 1974 1968(7) 1985 1963 1958
Total Tons Mined Since Inception
(thousands of tons)
142,000 372,000 154,000 88,000 12,700

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(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. Deposits are reserves which are defined with less geologic information than probable reserves and for which no well defined mine plan has been prepared.

(4)  

We have assigned all Proven Reserves to operating mining equipment and plant facilities.

(5)  

Approximate heat content applies to the coal mined in 2005.

(6)  

Approximate sulfur content applies to the tons mined in 2005.

(7)  

Initial sales from the current mine complex began in 1968. 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 800 million tons as of January 1, 1980, based principally upon a report by IntraSearch, Inc., an independent firm of consulting geologists, prepared that year.

               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 in 2004 in order to fully prove the coal deposits. Further core drilling was completed in the fall of 2005 for final mine plan development and permit submittal.

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               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. Our amount 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, 2005 until the reclamation bond for that property is released.

               Of the 103.0 million tons shown for the Absaloka Mine in the table above as proven and probable coal reserves, 89.5 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. Colstrip Station Units 1&2 entered commercial operation in 1975 and 1976.  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 242.8 million tons as of December 31, 2005.  This estimate is based on a study of the Rosebud Mine’s reserves dated October 1, 2005 conducted by Western Energy and adjusted for tons mined since that date.  We estimate that the Rosebud Mine had coal deposits of approximately 186.2 million tons at the end of 2005. This estimate is based on a study of the reserves at the Rosebud Mine prepared by the Environmental and Engineering Department of Western Energy when Western Energy was owned by Montana Power. We believe that all of these reserves  are recoverable through the Rosebud Mine’s existing facilities with current technology and the existing infrastructure.

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               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 their 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 242.8 million tons shown for the Rosebud Mine in the table above as proven coal reserves, 74.3 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 2019. 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 NRGT. We acquired the stock of Northwestern Resources in 2001 and renamed the company Texas Westmoreland Coal Company 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. NRGT 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. Through 2004, additional drilling was conducted from time to time to further define the limits of the coal seams. We believe that all the Jewett Mine’s coal reserves are recoverable through its existing facilities with current technology and the existing infrastructure.

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               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 Electric Power Cooperative, Inc. 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 July 11, 2005, we executed an option and acquired additional reserves in the South Beulah area. Initial drilling and mine plans have been completed. 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 or maintained 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 56.1 million tons at December 31, 2005.  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.

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               Of the 56.1 million tons shown for the Beulah Mine in the table above as proven and probable coal reserves, 29.5 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” Of the total reserves shown, approximately 5.3 million tons in the West Brush Creek area and 21.2 million tons at East Beulah are fully permitted at this time. Based on the current estimated production rates of 800,000 and 2.2 million tons respectively, there are roughly seven and ten 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 or maintained 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 8.4 million tons at December 31, 2005. These reserves were estimated as of January 1, 1999, based principally on a report prepared by Weir International Mining Consultants, an independent consulting firm, and updated by our engineering staff in 2005 based on drilling completed 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 2.6 million tons are fully permitted at this time and 5.8 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 into 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 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.

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Other

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

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ITEM 3 LEGAL PROCEEDINGS

               We are involved in legal proceedings the outcome of which could be material to the Company. We have presented the proceedings below based on the Westmoreland entity that is party to the proceeding.

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 payments into certain benefit plans, one of which is the UMWA Combined Benefit Fund (“CBF”).

               The Coal Act merged the UMWA 1950 and 1974 Benefit Plans into the CBF, and beneficiaries of the CBF were assigned to coal companies across the country. Congress authorized the Department of Health & Human Services (“HHS”) to calculate the amount of the premium to be paid by each coal company to whom beneficiaries were assigned. Under the statute, the premium was to be based on the aggregate amount of health care payments made by the 1950 and 1974 Plans in the plan year beginning July 1, 1991, less reimbursements, divided by the number of individuals covered. That amount is increased each year by a cost of living factor.

               Prior to the creation of the CBF, the UMWA 1950 and 1974 Plans had an arrangement with HHS pursuant to which they would pay the health care costs of retirees entitled to Medicare, and would then seek reimbursement for the Medicare-covered portion of the costs from HHS. The determination of the amount to be reimbursed to the Plans proved to be complex and time-consuming, which led the parties to enter into a capitation agreement in which they agreed that HHS would pay the Plans a specified per-capita reimbursement amount for each beneficiary each year, rather than trying to ascertain each year the actual amount to be reimbursed. The capitation agreement was in effect for the plan year beginning July 1, 1991, the year specified by the Coal Act as the baseline for the calculation of Coal Act premiums.

               On August 12, 2005, the United States District Court for the District of Maryland issued a decision in a case filed by a large group of coal operators (including Westmoreland) against the Commissioner of the Social Security Administration (“Social Security”), successor to HHS in this matter, and the Trustees of the CBF (the “Trustees”). The case involved the proper calculation of premiums payable to the CBF pursuant to the Coal Act. Specifically, the issue before the court was the meaning of the term “reimbursements” as used in the statutory provision describing how premiums are to be calculated. The position of the coal operators is that “reimbursements” means actual reimbursements received by the CBF pursuant to the capitation agreement, whereas the Social Security Administration has calculated the premiums using the amounts of Medicare-covered expenses, i.e., the amount that would be reimbursed to the CBF if the reimbursement schedule for Medicare-covered expenses were being applied. The method of calculating “reimbursements” used by the Social Security Administration resulted in higher premiums for coal operators than would have been the case if the actual reimbursements received by the CBF had been used in the calculation of premiums.

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               This issue has been in litigation for over ten years in two different United States Circuit Courts of Appeals. In 1995, the Court of Appeals for the Eleventh Circuit ruled, in a victory for coal companies, that the meaning of the statute was clear, i.e., that it meant the actual amount by which the CBF was reimbursed, regardless of the amount of the CBF’s Medicare-covered expenditures. In 2002, the Court of Appeals for the District of Columbia Circuit ruled that the statute was ambiguous, and remanded the case to the Commissioner of Social Security for an explanation of its interpretation so that the court could evaluate whether the interpretation was reasonable. In the August 2005 decision, the Maryland District Court agreed with the Eleventh Circuit that the term “reimbursements” unambiguously means the actual amount by which the CBF was reimbursed, and the Court granted summary judgment to the coal operators.

               The difference in premium payments for Westmoreland is substantial. Pursuant to the holdings of the Eleventh Circuit and the Maryland District Court, Westmoreland has overpaid and expensed premiums by more than $6 million for the period from 1993 through 2005.

               On August 25, 2005, the Trustees filed a motion with the Maryland District Court asking the court to clarify its order or grant a stay to prevent the coal companies from claiming a refund or applying the overpayment against current premiums pending appeal of the court’s order. Subsequently, the CBF Plan Trustees and the Commissioner of SSA appealed the order of the Maryland District Court to the United States Court of Appeals for the Fourth Circuit.

               Oral arguments before the Fourth Circuit Court of Appeals are expected to take place during the week of May 22, 2006.

               On December 2, 2005, the Maryland federal district court judge who granted summary judgment in favor of the coal companies on the premium calculation issue held a hearing on the motion the CBF filed in August seeking an order barring the coal companies from offsetting their plan year 2006 premiums by the amount of the premium overpayments. The judge ruled that until the case is final and all appeals are exhausted, the CBF can retain the premium overpayments. However, he applied the new premium calculation prospectively.

               The Company now pays premiums to the CBF of approximately $332,000 per month, compared to $396,000 per month prior to Maryland District Court decision.

               1992 UMWA Benefit Plan Surety Bond

               On May 11, 2005, XL Specialty Insurance Company and XL Reinsurance America, Inc. (together, “XL”), filed in the U.S. District Court, Southern District of New York, a Complaint for Declaratory Judgment against Westmoreland Coal Company and named Westmoreland Mining LLC as a co-defendant. The Complaint asks the court to confirm XL’s right to cancel a $21.3 million bond that secures Westmoreland’s obligation to pay premiums to the UMWA 1992 Plan, and also asks the court to direct Westmoreland pay $21.3 million to XL to reimburse XL for the $21.3 million that would be drawn under the bond by the 1992 Plan Trustees upon cancellation of the bond.

               On July 19, 2005, Westmoreland filed a motion to dismiss for lack of personal jurisdiction and on the grounds of improper venue. XL filed a response on August 2, 2005. At a hearing held on January 31, 2006, the judge changed the venue to the United States District Court for New Jersey.

               We believe that we have no obligation to reimburse XL for draws under the bond unless the draw is the result of a default by the Company under its obligations to the UMWA 1992 Plan. No default has occurred. If XL prevails on its claim, the Company will, in effect, be required to provide cash collateral of $21.3 million for its obligations to the 1992 Plan or, alternatively, put up a letter of credit in such amount.

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               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 Amended Complaint; it 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. Shortly after the Company was named as a defendant, the litigation was transferred from Montana State Court to the U.S. District Court in Billings, Montana.

               There has been no significant activity in the case involving Westmoreland for the past three years. Settlement discussions between the plaintiffs and other defendants appear to have been unsuccessful. We have never participated in settlement discussions with the plaintiffs because we believe that the case against the Company is totally without merit. Even if the plaintiffs could establish that shareholder consent was required for the sale of Montana Power’s coal business in 2001, there is virtually no legal support for the argument that such a sale to a buyer acting in good faith and relying on the seller’s representations can be rescinded. Indeed, the practical issues relating to such rescission would present a significant obstacle to such a result, particularly when the business has been operated by the buyer for five years and the original seller is in bankruptcy and has no means to complete a repurchase or operate the business following a repurchase.

               The Company has considered seeking a dismissal of the claims against it but is waiting for the outcome of a matter under review in the bankruptcy proceedings in Delaware involving Touch America (formerly Montana Power Company). In those proceedings, the unsecured creditors have asserted that the claims originally filed by McGreevey in Montana—the claims against the officers and directors which, if successful, would likely result in a payment by the insurance carrier that provided D&O insurance to Montana Power Company—belong to the creditors, not the shareholders who are the plaintiffs in the McGreevey action. If the Delaware Bankruptcy Court holds that those claims are “derivative” and thus belong to the corporation, then the unsecured creditors own them. Although the Delaware Bankruptcy Court will not directly decide that issue with respect to the claims against the various asset purchasers, including the Company, such a decision would likely affect the analysis of the Montana District Court where our case is pending.

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Legal Proceedings involving Westmoreland Coal Company and/or Westmoreland Energy

               ROVA Acquisition

               On August 25, 2004, we signed an Interest Purchase Agreement with a subsidiary of LG&E Energy LLC to acquire the 50% interest in the ROVA project that we do not currently own. LG&E Energy LLC is now a subsidiary of E.ON U.S. In November 2004, Dominion, 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 Energy’s 50% interest. On March 24, 2005, Dominion filed a Petition for Declaratory Judgment in Virginia in the Circuit Court of the City of Richmond seeking an order validating its alleged right of first refusal under the power purchase agreement to acquire LG&E’s partnership interest in the ROVA Project. On April 29, 2005, the ROVA Project filed a demurrer in the Circuit Court of the City of Richmond requesting the Petition for Declaratory Judgment be denied.

               On September 2, 2005, the Richmond Circuit Court granted the Partnership’s demurrer motion, effectively denying Dominion’s claim that it has a right of first refusal under the structure of the proposed acquisition. Dominion filed a motion for reconsideration of the court’s ruling and their motion was denied. Dominion can now file a new Motion for Summary Judgment based on amendments to the acquisition agreement or it can appeal the ruling on the Partnership’s demurrer motion.

               We are currently in discussion with Dominion and LG&E in the hope that this dispute can be resolved on business terms acceptable to all parties.

               Halifax County Property Tax

               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. In late 2002, the ROVA Project received notice of an assessment of $3.2 million for the years 1997 to 2001. Since that date the County has increased the amount of its assessment for tax years 1996, 2002, 2003, 2004 and 2005.

               In January, 2006, the Partnership paid $7.1 million to Halifax County as full payment for the years 1996 to 2001. The ROVA Project is negotiating with the county in an attempt to resolve claims by the county totaling approximately $3.6 million covering the years 2002 through 2005. These amounts, totaling $10.7 million, have been accrued at the ROVA Project as at yearend.

               North Carolina Income Tax

               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 assessed a tax of approximately $6 million, including penalties and interest.

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               In February 2006, we proposed a settlement to the North Carolina tax authority under which we would pay $2.1 million as full settlement of this claim. This amount was fully reserved by the Company during 2005. We are awaiting a response to our proposal.

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 was excessive, in part because the landowner’s own expert placed the cost of repair below $100,000. We also believe the settlement in the first case bars the second claim. We appealed to the Colorado Intermediate Court of Appeals, which affirmed the lower court’s decision on November 17, 2005. We filed a motion for reconsideration on December 1, 2005. If the motion for reconsideration is denied, we intend to appeal to the Colorado Supreme Court.

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

               Royalty Claims by Minerals Management Service and Related Tax Claims by Montana Department of Revenue

               The Company acquired WECO from Montana Power Company in 2001. WECO produces coal from the Rosebud Mine, which includes federal leases, a state lease and some privately owned leases near Colstrip, Montana. The Rosebud Mine supplies coal to the four units of the adjacent Colstrip Power Plant. In the late 1970‘s, a consortium of six utilities, including Montana Power, entered into negotiations with WECO for the long-term supply of coal to Units 3&4 of the Colstrip Plant, which would not be operational until 1984 and 1985, respectively. The parties could not reach agreement on all the relevant terms of the coal price and arbitration was commenced. The arbitration panel issued its opinion in 1980. As a result of the arbitration order, Western Energy and the Colstrip owners entered into a Coal Supply Agreement and a separate Coal Transportation Agreement. Under the Coal Supply Agreement, the Colstrip Owners pay a price for the coal F.O.B. mine. Under the Coal Transportation Agreement, the Colstrip Owners pay a separate fee for the transportation of the coal from the mine to Colstrip Units 3&4 on a conveyor belt that was designed and constructed by WECO and has been continuously operated and maintained by WECO.

               In 2002, the State of Montana, as agent for the Minerals Management Service (“MMS”) of the U.S. Department of the Interior, conducted an audit of the royalty payments made by WECO on the production of coal from the federal leases. The audit covered two periods: October 1991 through December 1995, and January 1996 through 2001. Based on these audits, the Office of Minerals Revenue Management (“MRM”) of the Department of the Interior issued orders directing WECO to pay royalties in the amount of $7.0 million on the proceeds received from the Colstrip owners under the Coal Transportation Agreement during the two audit periods. Both orders claimed that the payments for transportation were deemed to be payments for the production of coal. Only the costs paid for coal production are subject to the federal royalty, not payments for transportation.

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               WECO appealed the orders of the MRM to the Directors of MMS. On March 28, 2005, the MMS issued a decision stating that payments to WECO for transportation across the conveyor belt were part of the purchase price of the coal and therefore subject to the royalty charged by the federal government under the federal leases. However, the MMS dismissed the royalty claims for periods more than seven years before the date of the order on the basis that the statute of limitations had expired.

               On June 17, 2005, WECO appealed the decision of the MMS on the transportation charges to the United States Department of the Interior, Office of Hearings and Appeals, Interior Board of Land Appeals (“IBLA”). On September 6, 2005, the MMS filed its answer to WECO’s appeal.

               The total amount of the MMS royalty claims through the end of 2003 was approximately $5.0 million, including interest through the end of 2003. This amount, if payable, is subject to interest through the date of payment.

               In 2003, the State of Montana Department of Revenue (“DOR”) assessed state taxes for years 1997 and 1998 on the transportation charges collected by WECO from the Colstrip 3&4 owners. The taxes are payable only if the transportation charges are considered payments for the production of coal. The DOR is relying upon the same arguments used by the MMS in its royalty claims. WECO has disputed the state tax claims. It is anticipated that the state tax claims will be resolved following the outcome of WECO’s appeal of the MMS royalty claims or subsequent proceedings in federal court. The total of the state tax claims through the end of 2003 was approximately $3.6 million. If this amount is payable it is subject to interest from the time the tax payment was due.

               The MMS has asserted two other royalty claims against WECO. In 2002, the MMS held that “take or pay” payments received by WECO during the period from October 1, 1991 to December 31, 1995 from two Colstrip 3&4 owners were subject to the federal royalty. The MMS is claiming that these “take or pay” payments are payments for the production of coal, notwithstanding that no coal was produced. WECO filed a notice of appeal with MMS on October 22, 2002, disputing this royalty demand. No ruling has yet been issued by MMS. The total amount of the royalty demand, including interest through August 2003, is approximately $2.7 million.

               In 2004, the MMS issued a demand for a royalty payment in connection with a settlement agreement dated February 21, 1997 between WECO and one of the Colstrip owners, Puget Sound Energy. This settlement agreement reduced the coal price payable by Puget Sound as a result of certain “inequities” caused by the fact that the mine owner at the time, Montana Power, was also one of the Colstrip owners. The MMS has claimed that the coal price reduction is subject to the federal royalty. WECO has appealed this demand to the MMS, which has not yet ruled on the appeal. The amount of the royalty demand, with interest through mid-2003, is approximately $1.3 million.

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               Finally, in May 2005 the State of Montana asserted a demand for unpaid royalties on the state lease for the period from January 1, 1996 through December 31, 2001. This demand, which was for $0.6 million, is based on the same arguments as those used by the MMS in its claim for payment of royalties on transportation charges and the 1997 retroactive “inequities” adjustment of the coal price payable to Puget Sound.

               Neither the MMS nor the DOR has made royalty or tax demands for all periods during which WECO has received payments for transportation of coal. Presumably, the royalty and tax demands for periods after the years in dispute—generally, 1997 to 2001—and future years will be determined by the outcome of the pending proceedings. However, if the MMS and DOR were to make demands for all periods through the present, including interest, the total amount claimed against WECO, including the pending claims and interest thereon through the present, could exceed $40 million.

               We believe that WECO has meritorious defenses against the royalty and tax demands made by the MMS and the DOR. We expect a favorable ruling from the IBLA, although it could be a year or more before the IBLA issues its decision. If the outcome is not favorable to Western Energy, we will seek relief in Federal district court.

               Moreover, in the event of a final adverse outcome with DOR and MMS, we believe that certain of the Company’s customers are contractually obligated to reimburse the Company for any royalties and taxes imposed on the Company, plus legal expenses.

Derivative Action brought by Washington Group International, Inc., in connection with sales agency agreement

               On February 17, 2006, we were served with a complaint filed by Washington Group International, Inc. in Colorado District Court, City and County of Denver. The defendants in this legal action are Westmoreland Coal Company, Westmoreland Coal Sales Company, Westmoreland Resources, Inc., and certain directors and officers of Westmoreland Resources. Washington Group owns a 20% interest in Westmoreland Resources and the Company owns the other 80%. This litigation relates to a coal sales agency agreement between Westmoreland Resources and Westmoreland Coal Sales Company, a wholly owned subsidiary of the Company that was entered into in January of 2002. Under this coal sales agency agreement, Westmoreland Coal Sales Company agreed to act as agent for Westmoreland Resources in marketing and selling Westmoreland Resources’ produced coal, in exchange for an agency fee per ton sold. Washington Group objected to this fee and is now claiming that the directors of Westmoreland Resources and its President breached their fiduciary duty by granting an over-market agency fee to an affiliated company. The total amount in dispute, if the fee were to be rescinded retroactively to 2002, is in the range of $1.2 million to $1.5 million. The Company intends to vigorously defend this action and strongly believes that the directors and the President of Westmoreland Resources acted in good faith and made a reasonable determination with respect to the agency fee. We further believe that the sales agency fee reflected the market rate for marketing and selling coal, as of 2002 and that Westmoreland Coal Sales Company provides significant value to Westmoreland Resources for which it should be compensated at a market rate.

Other

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

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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 2005.

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Executive Officers of the Registrant

               The following table shows the executive officers of the Company, their ages as of March 1, 2006, 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) 59 Chairman of the Board, 1996
President and 1992
Chief Executive Officer 1993
         
David J. Blair (2) 52 Chief Financial Officer 2005
         
Roger D. Wiegley (3) 57 General Counsel and Secretary 2005
         
Robert W. Holzwarth (4) 58 Senior Vice President, Power 2004
         
Todd A. Myers (5) 42 Vice President, Sales and Marketing 2000
         
John V. O'Laughlin (6) 54 Vice President, Coal Operations 2005
         
Ronald H. Beck (7) 61 Vice President, Finance and Treasurer, 2001
Assistant Secretary 2005
         
Thomas G. Durham (8) 57 Vice President, Planning and Engineering 2000
         
Douglas P. Kathol (9) 53 Vice President, Development 2003
         
Thomas M. Cirillo (10) 51 Vice President, Administration 2003
         
Gregory S. Woods (11) 52 Vice President, Eastern Operations 2000
         
Diane S. Jones (12) 47 Vice President, Corporate Relations 2000
         
Bronwen J. Turner (13) 51 Vice President, Government and Community Relations 2006

(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. Blair joined Westmoreland in April 2005. He joined Westmoreland after a seventeen year career with Nalco Chemical Company where he was most recently acting Chief Financial Officer for Ondeo Nalco Company, a global specialty chemical company.


(3)

Mr. Wiegley joined Westmoreland in May 2005. Prior to joining Westmoreland he held legal positions with Credit Suisse Group from 1999 to 2005 and served as General Counsel for one of its affiliates. Mr. Wiegley served as outside counsel for Westmoreland from 1992 to 1996 while a partner with Sidley Austin Brown & Wood and later with Pillsbury Winthrop LLP.


(4)

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 1997 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.


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(5)

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.


(6)

Mr. O’Laughlin joined Westmoreland in February 2001 as Vice President, Mining, and was named President and General Manager of Dakota Westmoreland Corporation in March 2001. He later became President and General Manager of Western Energy Company and President of Texas Westmoreland Coal Company and was promoted to Vice President of Coal Operations for Westmoreland Coal Company in May 2005. Prior to joining Westmoreland Mr. O’Laughlin was with Morrison Knudsen Corporation’s mining group for twenty-eight years, most recently as Vice President of Mine Operations which included responsibility for the contract mining services at the Absaloka Mine.


(7)

Mr. Beck joined Westmoreland in July 2001 as Vice President – Finance and Treasurer. From September 2003 to April 2005, Mr. Beck also served as Acting Chief Financial Officer. He was appointed as Assistant Secretary in April 2005. 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.


(8)

Mr. Durham joined Westmoreland as Vice President, Coal Operations in April 2000 and was named Vice President, Planning and Engineering in May 2005. 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.


(9)

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.


(10)

Mr. Cirillo joined Westmoreland in June 2002 as Director, Planning and Administration. Prior to joining Westmoreland, Mr. Cirillo held various senior positions in defense contracting following a twenty year career as a U.S Navy pilot. He was named Vice President, Administration in January 2003.


(11)

Mr. Woods joined Westmoreland in May 1973 and held various corporate accounting and management information systems positions while at Westmoreland’s Virginia and West Virginia coal mining operations. Mr. Woods has been with Westmoreland Energy, LLC since 1990 and has held the positions of Controller, Asset Manager, and Vice President, Finance and Asset Management. Mr. Woods was elected to his current positions as Vice President, Eastern Operations of Westmoreland Coal Company in June 2000, as Executive Vice President of Westmoreland Energy, LLC in February 1997, and as President of Westmoreland Technical Services, Inc. in April 2001.


(12)

Ms. Jones joined Westmoreland in March 1993 as Manager, Business Development of Westmoreland Energy, LLC and became Manager of Business Development and Corporate Relations for Westmoreland Coal Company in 1995. She was named Vice President Corporate Business Development and Corporate Relations in 2000 and then named Vice President Corporate Relations in August 2003. Prior to joining Westmoreland, Ms. Jones held engineering and business development positions in the utility industry. She became a registered professional engineer in 1985.


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(13)

Ms. Turner joined Westmoreland in August 2003 as Director, Government and Community Relations and was named Vice President, Corporate Government and Community Relations in January, 2006. Prior to joining Westmoreland she was a policy analyst for the Education Commission of the States and director of marketing and communications for Quark Inc. She has over 25 years experience in various positions in marketing, communications and public policy, including representing communities impacted by energy development.


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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





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
         
2005
First Quarter    33.65    24.26    59.00    48.50
Second Quarter    25.80    16.92    49.25    38.00
Third Quarter    28.70    20.54    52.00    42.00
Fourth Quarter    29.42    20.48    51.50    41.75






Approximate Number of Equity Security Holders of Record:



Number of Holders of Record
Title of Class (as of March 1, 2006)


Common Stock ($2.50 par value) 1,395
Depositary Shares, each representing
    one-quarter share of a share of Series A
    Convertible Exchangeable Preferred
    Stock 16


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, 2006 amount to $17.2 million in the aggregate ($84.03 per preferred share or $21.01 per Depositary Share). We cannot pay dividends on our common stock until we pay the accumulated preferred dividends in full.

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               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, 2005). We had shareholders’ equity of $52.7 million and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $21.2 million at December 31, 2005.

               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.

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ITEM 6 SELECTED FINANCIAL DATA

Westmoreland Coal Company and Subsidiaries
Five-Year Review











2005 2004 2003 2002 2001 (1)











(in thousands, except per share data)
Consolidated Statements of Operations Information
Revenue – Coal $ 361,963 $ 320,291 $ 294,986 $ 301,235 $ 231,048
         – Independent power and other 12,727 12,741 15,824 14,506 15,871











Total revenues 374,690 333,032 310,810 315,741 246,919
                     
Cost and expenses 370,426 328,194 303,005 296,218 232,847











Operating income from continuing operations 4,264 4,838 7,805 19,523 14,072
                     
Interest expense (10,948) (10,966) (10,804) (11,511) (8,878)
Minority interest (950) (1,154) (773) (800) (780)
Interest and other income 5,250 4,808 3,121 4,128 3,229











Income (loss) from continuing operations
    before income taxes
(2,384) (2,474) (651) 11,340 7,643
                     
Income tax benefit (expense) from continuing operations 12,897 6,934 10,971 2,368 (1,228)











Net income from continuing operations 10,513 4,460 10,320 13,708 6,415
                     
Income (loss) from discontinued operations - - 2,113 (3,583) (1,188)











Net income before cumulative effect of
   change in accounting principle 10,513 4,460 12,433 10,125 5,227
Cumulative effect of change in accounting principle, net 1,597 - 161 - -











Net income 12,110 4,460 12,594 10,125 5,227
                     
Less preferred stock dividend requirements 1,744 1,744 1,752 1,772 1,776











Net income applicable to common shareholders $ 10,366 $ 2,716 $ 10,842 $ 8,353 $ 3,451











Net income per share applicable to
   common shareholders:
      Basic $ 1.25 $ 0.34 $ 1.39 $ 1.10 $ 0.48
      Diluted $ 1.17 $ 0.31 $ 1.30 $ 1.03 $ 0.43
Weighted average number of common
   shares outstanding:
      Basic 8,280 8,099 7,799 7,608 7,239
      Diluted 8,868 8,662 8,338 8,147 8,000











Balance Sheet Information
Working capital $ 9,493 $ 18,918 $ 5,555 $ 10,143 $ 11,346
Net property, plant and equipment 173,040 168,628 151,349 189,532 197,271
Total assets 556,599 513,989 457,837 471,957 466,532
Total debt 112,243 117,259 93,469 100,157 122,910
Shareholders' equity 52,666 39,892 33,270 18,568 10,415












(1)  

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


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

Forward-Looking Disclaimer

               Please keep the Forward-Looking Disclaimer on page 3 in mind as you review the following discussion and analysis.

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. 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. We also earned royalties for the production of coalbed methane gas from the first quarter of 2004 until early in 2006.

               In partnership with others, we have developed eight independent power projects totaling 866 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 96% of our equity in earnings from independent power in 2005, is baseloaded and supplies power pursuant to long-term contracts.

               According to the 2005 Annual Energy Outlook prepared by the EIA, approximately 50% of all electricity generated in the United States in 2004 was produced by coal-fired units. The EIA projects that the demand for coal used to generate electricity will increase 1.5% per year from 2004 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 2005, approximately $32 million of our operating income came from coal operations, and almost $11 million came from independent power projects. This income was mostly offset by over $38 million of expenses in the corporate segment for our heritage health benefit expenses 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 2005, Westmoreland Mining had repaid $52.1 million of that $120 million and deposited an additional $22.2 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.

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               We may also seek additional capital in 2006 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. Due to legal and business constraints, no dividends were declared from the third quarter of 1995 until 2002. On October 1, 2002 and for the following three quarters, a partial dividend of $0.15 per Depositary Share was paid. In October 2003 and October 2004, the quarterly dividend was increased to $0.20 and $0.25, respectively. As of January 1, 2006, $17.2 million of arrearages had accumulated ($84.03 per preferred share or $21.01 per Depositary Share). A quarterly dividend of $0.25 per Depositary Share will be paid on April 1, 2006, to stockholders of record on March 17, 2006. 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:

 

re-determining sales prices to reflect significantly higher market prices and commodity and production costs;


 

addressing the potential impact of limited availability of tires for heavy equipment used at our mines;


 

high ongoing heritage health benefit expenses associated with inflation in medical costs, potentially longer life expectancies for retirees and active employees and the failure of the UMWA Health and Benefit Fund to manage those costs;


 

maintaining and collateralizing, where necessary, our Coal Act and reclamation bonds;


 

funding required contributions to pension plans that are underfunded at the end of 2005;


 

providing adequate capital for on-going operations and our growth initiatives;


 

completing the acquisition of LG&E’s 50% interest in the ROVA Project and obtaining the necessary financing;


 

implementation of a new company-wide computer system to support our mining and corporate segments;


 

integration of new personnel, especially in the area of finance and accounting;


 

new environmental regulations, which have the potential to significantly reduce sales from our mines; and


 

claims for potential taxes and royalties asserted by various governmental entities.


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               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.”

Internal Control over Financial Reporting

               We had two material weaknesses in internal control over financial reporting in 2005. In connection with the audit of our 2005 financial statements, we identified matters involving our internal controls over financial reporting that constituted material weaknesses as defined by the Public Company Accounting Oversight Board in Auditing Standard No. 2, pursuant to which:

 

material weaknesses are defined as a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected; and


 

a significant deficiency is a control deficiency, or combination of control deficiencies, that adversely affects our ability to initiate, authorize, record, process, or report external financial data reliably in accordance with generally accepted accounting principles such that there is more than a remote likelihood that a misstatement of our annual or interim financial statements that is more than inconsequential will not be prevented or detected.


               We are committed to maintaining effective internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Our accounting personnel report regularly to our audit committee on all accounting and financial matters. In addition, our audit committee actively communicates with and oversees the engagement of our independent registered public accounting firm.

               We describe the actions that we have taken in response to the identification of the material weakness in more detail in Item 9A – “Controls and Procedures.”

               We believe we have remediated the material weaknesses that were identified in connection with the audit of our 2005 financial statements. However, we cannot assure you that additional significant deficiencies or material weaknesses in our internal control over financial reporting will not be identified in the future. Failure to implement and maintain effective internal control over financial reporting could result in material misstatements in our financial statements. See Item 1A, “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.

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               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 obligations are the obligations 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. See Notes 5, 6, 7, 8 and 9 to the Consolidated Financial Statements for current information about these assumptions, estimates, and obligations.

  Estimates and Judgments

               We estimate the total amount of these obligations with the help of third party professionals using actuarial assumptions and information. Our estimates are sensitive to judgments we make about the discount rate, about the rate of inflation in medical costs, 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. 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.

               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.

               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

               Actuarial valuations project that our retiree health benefit costs for current employees and retirees will continue at the current level in the near term and then decline to zero over the next approximately sixty years as the number of eligible beneficiaries declines.

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               We expect to incur lower cash payments for workers’ compensation benefits in 2006 than in 2005 and expect that amount to decline over time. We anticipate that these payments will decline because we are no longer self-insured for workers’ compensation benefits and have had no new claimants since 1995.

               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, 2005, our pension trusts were underfunded by $25.8 million, and we expect to contribute approximately $1.4 million to these trusts in 2006. As of December 31, 2005, our black lung trust was overfunded by $7.5 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.

 

First, the statute merged the UMWA 1950 and 1974 Plans into the CBF. The CBF provides benefits to a 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 CBF supplements the benefits this group receives under Medicare.


 

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.


 

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 CBF.


               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.

               One of the estimates we have made relates to the implementation of the Medicare Reform Act. As provided for under that Act, we recognized a benefit to our anticipated future prescription drug costs for retirees and their dependents in 2003 based on a coordinated implementation of the Medicare Reform Act and our existing benefit programs, including the UMWA 1992 Plan. In 2005, the government issued regulations which made the subsidy approach the only practical alternative given our existing programs. In October 2005, we adopted the subsidy approach for 2006. The subsidy approach will limit our annual benefit to 28% (to a maximum of $1,330/participant) of actual costs. A revised actuarial analysis reduced the projected net present value benefit to us from the Medicare Reform Act as reflected in our Postretirement medical obligations, but caused a higher resultant future annual expense of approximately $1.3 million compared to what we had previously anticipated with a coordinated benefits approach.

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               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.

               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 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 can and do 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.

               See Note 3 to the Consolidated Financial Statements for current information about these obligations, costs and reserve estimates.

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               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. See Note 10 to the Consolidated Financial Statements for a complete analysis of our current income tax position.

               As of December 31, 2005, we have significant NOLs. These NOLs expire at various dates through 2025. 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 expenses. 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 estimate the results of future operations that will generate taxable income to realize these deferred income tax assets. Based on this estimate, however, 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 will more likely than not expire before they can be realized in future periods. On an 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. We also make other adjustments in our net deferred tax assets related to on-going differences between book and taxable income. At December 31, 2005 the valuation allowance for Federal tax purposes was $8.5 million and relates primarily to NOLs that will expire if we are unable to generate sufficient taxable income.

  Related Information

               Under the federal tax laws, there are two types of taxable income and two types of net operating loss carryforwards, both of which generally differ from reported pretax income on our consolidated financial statements. Regular taxable income is generally less than our reported pre-tax income.

 

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 does not allow certain deductions, such as percentage depletion. We have significant percentage depletion because of our mining activities.


 

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.

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               We are subject to AMT at a 20% rate. As of December 31, 2005, we had AMT net operating loss carryforwards of approximately $14.9 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 by 2007 and would normally begin paying the full 20% AMT in 2008. However, AMT will be paid only after we use the Indian Coal Production Tax Credits generated from 2006 to 2009 discussed below and will continue until we fully utilize our regular NOLs after that. 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 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.

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Contractual Obligations and Commitments

               The following table presents information about our contractual obligations and commitments as of December 31, 2005. 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 2006 2007 2008 2009 2010 After 2010
Westmoreland Mining term debt (1) 102,900 11,300 12,000 44,600 11,500 11,500 12,000
Other debt 9,343 1,137 6,567 822 580 237 -     
Interest on debt (2) 28,320 9,097 8,002 6,512 2,393 1,573 743
Operating leases 8,538 3,235 2,250 1,854 1,014 185 -     
Workers' compensation 9,343 949 887 828 772 717 5,190
Combined Benefit Fund
(Multiemployer)
34,141 (3) 3,917 3,674 3,436 3,204 2,978 16,932
Postretirement medical 274,047 (4) 17,307 18,464 19,321 19,976 20,491 178,488
Qualified pension benefits 65,916 (5) 870 1,124 1,443 1,733 2,082 58,664
SERP benefits 2,409 (6) 76 74 72 69 248 1,870
Pneumoconiosis 16,879 (7) 2,178 1,589 1,553 1,510 1,460 8,589
Reclamation costs 396,096 (8) 17,890 9,479 5,523 7,260 7,056 348,888
Preferred dividends 17,232 (9) 1,744 (10) 1,744 (10) 1,744 (10) 1,744 (10) 1,744 (10) 1,744 (10) per year

(1)  

At December 31, 2005, Westmoreland Mining had deposited $22.2 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 from the December 31, 2005 rate.

(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 $141.9 million as of December 31, 2005.

(5)  

The fair value of plan assets at December 31, 2005 was $42.5 million. The expected pension benefit payments shown above will be made from these assets.


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(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 $2.4 million as of December 31, 2005. The plan was unfunded at December 31, 2005.

(7)  

The fair value of plan assets at December 31, 2005 was $24.3 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 $158.4 million as of December 31, 2005 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 $35.3 million. The table does not reflect $58.8 million, the amount held in escrow as of December 31, 2005 from contributions by customers for reclamation of the Rosebud Mine, or $1.1 million in restricted cash for other mines. In addition, the Absaloka contract mine operator is funding a separate reclamation escrow account that is approximately $4.8 million as of December 31, 2005. 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 $63.2 million at December 31, 2005.

(9)  

Represents quarterly dividends that are accumulated through and including January 1, 2006.

(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 accumulate, as provided in the Certificate of Designation.

               The ROVA Project’s debt is not listed in the table above because, at December 31, 2005, 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 in our financial statements with our debt and the debt of our subsidiaries. The ROVA Project had outstanding indebtedness of $184 million at December 31, 2005, and the principal of that debt is payable from 2006 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 suppliers and environmental leaders and that supply customers who share our orientation for low-cost supply 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 suppliers 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 relatively stable earnings.

Examples of our current development efforts include the following:

 

In August 2004, we signed a Purchase Agreement with LG&E to acquire LG&E’s 50% interest in the ROVA Project. While this acquisition has been delayed by litigation over the customer’s alleged right of first refusal, we are currently in discussion with the customer in the hope that we can resolve the dispute on mutually acceptable business terms.


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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. In May 2004, we and MDU filed an application for an air permit for a proposed 175 MW plant and a completeness determination was received in July 2004. The North Dakota Department of Health (Department of Health) issued a draft air permit on March 29, 2005. The Department of Health issued the final air permit in June 2005, after holding a 30-day public comment period and a public hearing.


 

We also continue to identify and evaluate other potential growth opportunities in the coal and independent power sections.


               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 $0.10 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 is expected to begin in mid-year 2007 and continue to 2015.

               In Note 2 to our Consolidated Financial Statements in this Form 10-K, we describe our possible acquisition of LG&E’s interest in the ROVA Project, including the current status. We describe the financial aspects of that transaction 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 in 2019. It also should enhance our ability to develop and implement strategies to restructure the project’s contracts with its principal customer, Dominion, 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.

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Liquidity and Capital Resources

               As discussed in the Overview section above, Westmoreland Mining’s add-on facility substantially improved our liquidity during 2004 and 2005. 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 provides liquidity to Westmoreland Coal Company.

               Cash provided by operating activities was $28.8 million in 2005, $9.5 million in 2004, and $24.8 million in 2003. Cash from operations in 2005 compared to 2004 increased because of several factors which include:

 

We sold more coal at higher prices at the Jewett Mine due to restructuring of the contract with its customer, where in 2004, unusually high rainfall disrupted production and costs of commodities increased to a greater extent than customer revenue.


 

We had significantly higher distributions from the ROVA Project in 2005 compared to 2004, because in 2004 the project’s lenders withheld $8.3 million (of which our share was $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.


 

Mandatory contributions to our defined benefit pension plans declined to $1.6 million in 2005 compared to $3.4 million in contributions in 2004.


 

We received a payment at the Jewett Mine of $2.4 million in 2005 that was related to 2004 operations.


 

We also increased cash from working capital during 2005 primarily through higher levels of accounts payable, net of slightly higher receivables and inventory levels.


               We used $22.8 million of cash for investing activities in 2005, $28.5 million in 2004 and $17.3 million in 2003. In 2005, additions to property and equipment totaled $18.3 million reflecting continued investment in mine equipment and development and over $3 million for implementation of a corporate-wide computer system. We also deposited $5.1 million into our restricted cash accounts, pursuant to Westmoreland Mining’s term loan agreement and as collateral for our surety bonds. 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 restricted cash accounts. 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.

               Cash used in financing activities in 2005 primarily represented repayment of long-term debt of $12.2 million partially offset by $5.5 million borrowings of revolving lines of credit. We generated cash from 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 for 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. Dividends paid to Westmoreland Resources’ 20% shareholder in 2005, 2004 and 2003 were $1.1 million, $1.2 million and $1.0 million, respectively.

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               At December 31, 2005 cash and cash equivalents totaled $11.2 million, including $3.0 million at Westmoreland Mining, $4.2 million at Westmoreland Resources, and $3.4 million at our captive insurance subsidiary. 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. 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 $34.6 million at December 31, 2005 and $32.7 million at December 31, 2004. The restricted cash at December 31, 2005 included $22.2 million in Westmoreland Mining’s debt service reserve and long-term prepayment accounts. The restricted cash at December 31, 2004 included $21.9 million in Westmoreland Mining’s debt service and long-term prepayment accounts. At December 31, 2005, our reclamation, workers’ compensation and postretirement medical cost obligation bonds were collateralized by interest-bearing cash deposits of $11.0 million, which amounts we have classified as non-current assets. In addition, we had reclamation deposits of $58.8 million at December 31, 2005 and $55.6 million at December 31, 2004, 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, 2005. This cash is restricted as to its use and is classified as part of our investment in independent power projects.

               In 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 $9.1 million in 2005 and $19.3 million in 2004 to Westmoreland Coal Company and expects to distribute the balance in 2006. 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. In 2004 when 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. In December 2005, Westmoreland Mining amended the revolving facility to increase the borrowing base to $20 million and to extend its maturity to April 2008 to better align with our operating needs. The increase includes the ability to issue letters of credit up to $10 million which the Company expects to use for reclamation bond collateral needs. As of December 31, 2005, Westmoreland Mining had the entire $20 million revolving facility available to borrow.

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               As of December 31, 2005, Westmoreland Coal Company had $8.5 million of its $14.0 million revolving line of credit available to borrow.

Liquidity Outlook

               We describe certain liquidity comparisons in the Liquidity Outlook section below. In addition, the following items are important.

               Reclamation

               Our asset retirement obligations, as previously described under “Critical Accounting Estimates” above, increased $17.6 million during 2005. Two of the more significant reasons for that increase were changes we made about the timing of required reclamation activities and the amount of work necessary. These and other factors are disclosed in more detail in Note 3 to the Consolidated Financial Statements.

               Jewett Mine Supply Contract

               Texas Westmoreland and NRGT are party to a lignite supply agreement that expires in 2015 and that provides annual price redeterminations based on an equivalent cost of SPRB coal used at the Limestone Station.  In January 2004, the parties agreed to fix a price for the period 2004 through 2007, with pricing thereafter to be determined pursuant to the underlying contract.  Subsequent dramatic and unexpected increases in commodity costs, including costs for diesel fuel and steel, among other items, rendered the four-year fixed price agreement uneconomic.  At the same time, market prices for SPRB coal and associated rail rates also increased dramatically.  A new interim agreement was reached in September 2005 that enhanced the economics of the Jewett Mine over previous interim pricing arrangements, provides capital to support mine development, improves the mechanics for determining equivalent market pricing pursuant to the parties’ underlying contract after 2007, and has returned Texas Westmoreland to a stable and satisfactory level of financial performance through the end of 2007, when the price will be determined annually based on equivalent market value, or until the current long-term supply agreement is modified further or restructured. Payments of $4.9 million related to the first nine months of 2005 were recorded as revenue in the fourth quarter as related performance obligations were completed and payments were received from the customer.

               Combined Benefit Fund

               As previously reported in Item 3 “Legal Proceedings” and in Note 20 to the Consolidated Financial Statements, on August 12, 2005 the United States District Court for the District of Maryland ruled that the CBF has been charging an excessive premium to coal operators since 1992. In our case, the total of the overpayment is approximately $6 million.

               The CBF Trustees and the Commissioner of Social Security have appealed the District Court decision. However, we believe that the decision will be upheld on appeal. At that time, the Company would recognize the $6 million as income. In the interim, the Company accrued, but withheld, payment of its monthly premium for the fourth quarter, thereby benefiting cash flow in the amount of approximately $1 million. In early 2006, the CBF resumed invoicing and the Company paid the withheld payments. However, as provided for by the Court, the Company is paying at the lower, adjusted rate going forward.

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               Indian Coal Production Tax Credit

               In August 2005 the Energy Policy Act of 2005 was enacted. Among other provisions, it contains a tax credit for the production of coal owned by Indian tribes. The credit is $1.50 per ton beginning 2006 through 2009 and $2.00 per ton from 2010 through 2012, with both amounts escalating for inflation. The credit may be used against regular corporate income tax for all years and against Alternative Minimum Tax for the initial period. The Company’s 80%-owned Absaloka Mine, which produces coal under a lease with the Crow Tribe, produces about 7 million tons per year. The savings will be shared with the Crow Tribe when they are realized.

               Significant Anticipated Variances Between 2005 and 2006

               We anticipate that the following events and developments, which we expect will occur in 2006 but which did not occur in 2005, and the following events and developments, which we expect will not occur in 2006 but which did occur in 2005, will affect our liquidity and our net income.

 

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


 

Tons sold increased in 2005 but are likely to remain comparable in 2006. Coal revenues are expected to increase in 2006 due to contract renewals at higher prices. However, overall cost of sales are also increasing due to inflation of commodity costs although not as much as revenues.


 

We anticipate that capital expenditures related to our mining activities will be comparable in 2006 and 2005. However, if 2006 capital expenditures at the Jewett Mine are included which are mostly reimbursed by the customer, the overall level of capital projects will be higher in 2006 than in 2005.


 

We anticipate higher interest costs in 2006 because of increased use of our revolving credit lines and higher rates for the floating rate portion of Westmoreland Mining’s debt.


 

Our results for 2005 reflect a negative impact of increased prospective and retroactive personal property taxes at the ROVA Project. Our pre-tax income in 2005 was reduced by $2.7 million for the accrual of our portion of the estimated cost. In 2006 pre-tax income should not suffer the cost of retroactive payments. The lender to the ROVA Project withheld funds in an amount equal to the total amount claimed by Halifax County, which funds are normally available for distribution. In early 2006, most of the claim was resolved, and the county was paid from the withheld funds.


 

We expect higher depreciation, depletion and amortization expense in 2006 than in 2005 due to continued capital expenditures at our mines and an increase in the carrying value of our capitalized asset retirement costs.


 

In 2005, we did not pay, but did accrue about $1.0 million of the CBF’s 2005 assessment which amount was paid in early 2006 thereby increasing cash costs in 2006 compared to 2005. Our cash payments for this obligation are expected to decrease about $0.8 million in 2006 as compared to 2005, in part because we have now fully paid this assessment. See Notes 8 and 20 to the Consolidated Financial Statements for additional information.


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Our 2005 results reflect an $8.1 million benefit which resulted from a reduction in the valuation allowance related to our Federal NOLs.


 

During 2005 and 2006, we have continued implementation of a corporate-wide computer system to enhance our accounting, reporting and analysis capability. The total investment at year-end 2005 was approximately $6.4 million. We expect that the system will produce efficiencies and reduce costs associated with our current, separate systems.


 

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. There was a reduction of expense of $0.9 million for these awards in 2005 due to a reduction of the previous estimate of the obligations. We are not able to predict the variable expense for these awards in 2006.


 

New accounting rules require that we expense the value of stock options over their vesting periods, beginning in the first quarter of 2006. We have not determined the impact of this new requirement for new stock option awards. The cost of expensing existing stock option grants will be minimal. We accelerated vesting of all stock appreciation rights at the end of 2005, resulting in an additional expense of $0.2 million. This decision will reduce future expense.


               Significant Factors Affecting Our Liquidity

               The matters discussed above focus on anticipated differences between 2005 and 2006. A number of non-recurring events significantly influenced our 2005 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. For all of the foregoing reasons, and while we anticipate that we will be profitable in 2006, 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 to acquire the 50% interest in the ROVA project that we do not currently own. LG&E Energy LLC is now a subsidiary of E.ON U.S. In November 2004, Dominion, 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 Energy’s 50% interest. Dominion brought a legal action in Virginia State Court to assert their alleged right of first refusal. This legal action has delayed the acquisition and made the ultimate outcome uncertain. We are currently in negotiations with Dominion and LG&E in the hope that we can find a business solution that will resolve the pending dispute on terms that are acceptable to all parties.

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               The financial implications of the ROVA transaction depend significantly on when it is completed, how we choose to finance the transaction and the terms of any such financing.

               In evaluating the terms of any proposed financing or any proposed agreement with Dominion, 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, 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 and then gradually increase through 2019. The coal supply agreements expire in 2014 and given today’s market, the cost of coal is expected to increase.

               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. If the ROVA acquisition is completed, we will subsequently consolidate their financial results in our consolidated financial statements. 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.

Coal Markets and Rail Delivery Issues

               Significant events occurred during 2005 in the market for coal from the SPRB of Wyoming, the market benchmark for most of the Company’s sales. First, the BNSF and Union Pacific (“UP”) railroads experienced significant disruptions in their ability to carry coal out of the SPRB on the so-called Joint Line due to continued increases in demand for SPRB coal and due to a major rail bed ballast rehabilitation project that caused limited capacity on that route. The railroads’ rehabilitation work commenced in Summer 2005 and will continue into 2006. These rail issues, combined with increasing demand for SPRB coal, resulted in a marked increase in prices for SPRB coal during the second half of 2005 and into 2006. Prices for higher Btu, ultra-low sulfur SPRB coal made further gains due to the rise in market prices for sulfur dioxide emission allowances, which are required by most coal-fired power plants for compliance with regulations under the federal Clean Air Act.

               Two-thirds of the Company’s coal sales are delivered to its customers via conveyor belt, coal haulers, or highway trucks, while the remaining third is delivered via the BNSF. The Company’s BNSF-served mines, in Montana and North Dakota, are not directly affected by the Joint Line rehabilitation project. Rather, Company mines have been affected indirectly, and to a much lesser extent than the SPRB mines, because the BNSF has shifted some crews and locomotives to the SPRB from time-to-time to help to alleviate the issues there. Unlike the SPRB producers, the Company did not lose significant budgeted production or sales in 2005 as a result of the on-going rail issues.

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               Market prices for SPRB coal increased significantly from the first half of 2005. Eighteen percent of the Company’s total sales tonnage was scheduled for price re-determination on January 1, 2006, and most of these tons were generally benchmarked to SPRB market prices with certain contractual and other restrictions. These redeterminations resulted in a weighted average price increase for these tons of almost 30% effective January 1, 2006. Our ability to capture further market gains is restricted by the fact that almost all of our production is sold under long-term contracts. In addition, our mines are now producing at maximum in-place capacity. About 5% of total Company tons are currently scheduled to be open to market, via contract renewal, or market-benchmarked price re-determinations on January 1, 2007, 18% on January 1, 2008, and, if certain customers elect not to invoke extension options, 10% on January 1, 2009 (plus an additional 22% in 2008 and 2009 if the market-based pricing mechanism under the Jewett Mine’s contract with NRGT is preserved in the renegotiation of a long-term supply agreement).

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.

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Results of Operations
2005 Compared to 2004

               Coal Operations. Coal revenues increased from 2004 primarily as a result of a 1.0 million increase in tons sold and because of higher prices, including a one-time “catch-up” payment of $2.4 million received in the first quarter of 2005 for past cost increases for commodities. As discussed in the Liquidity Outlook section of this Form 10-K under Jewett Mine Supply Contract, payments of $4.9 million related to the first nine months of 2005 were recorded as revenue in the fourth quarter as performance obligations were completed and payments were received from the customer. The increase in tons sold in 2005 came from new or extended sales contracts at the Rosebud mine as well as increases at the Jewett and Absaloka Mines. Cost of sales increased in 2005 compared to 2004 primarily as a result of increased tons produced, higher commodity prices (for diesel fuel, electricity and explosives) and higher stripping ratios. Very difficult mining conditions and unusually heavy rainfall increased costs at the Beulah Mine in 2005. The 2004 revenue includes the $16.3 million Colstrip 1&2 arbitration award for the price reopener with the owners of Colstrip Units 1&2 for coal shipped from July 30, 2001 to May 31, 2004. Production taxes and royalties on those revenues totaled $5.1 million. Costs at the Jewett Mine in 2004 included unplanned repairs to a primary dragline combined with significant weather related production interruptions.

               The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods for actual results as reported and on a pro forma basis (which excludes the impact of the Colstrip arbitration award in 2004):

Year Ended
Actual Pro forma









2005 2004 Change 2004 Change*









Revenues – thousands $ 361,963 $ 320,291 13%   $ 307,264 18%
           
Volumes – millions of equivalent coal tons 30.0 29.0   3%
           
Cost of sales – thousands $ 289,992 $ 249,300 16%   $ 245,117 18%

* Change represents change between 2005 Actual amounts and 2004 Pro forma amounts.

               Depreciation, depletion and amortization increased to $17.7 million in 2005 compared to $15.0 million in 2004. The increase is primarily related to increased coal production, increased capital expenditures at the mines for both continued mine development and the replacement of mining equipment, and increased amortization of capitalized asset retirement costs.

               Independent Power. Our equity in earnings from the independent power projects were $12.7 million in both 2005 and 2004. For 2005 and 2004, the ROVA Project produced 1,601,000 and 1,625,000 megawatt hours, respectively, and achieved capacity factors of 87% in 2005 and 88% in 2004. The slightly lower capacity factor in 2005 was the result of increased start-up hours after scheduled outages. In 2005 and 2004, equity in earnings was reduced by $2.7 and $2.0 million, respectively, for costs associated with higher Halifax County personal property tax assessments from prior years, which we unsuccessfully contested. Most of the contested claims were paid to Halifax County in early 2006. In 2005, the ROVA I and II units had more scheduled outages for planned repairs that decreased the capacity factor, and they experienced more unscheduled outages for repairs than in 2004. We recognized $455,000 in equity earnings in 2005, compared to $317,000 in 2004 from our 4.49% interest in the Fort Lupton project.

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               Costs and Expenses. Selling and administrative expenses were $35.1 million for 2005 compared to $30.9 million for 2004. In 2005, costs increased as a result of:

 

The $1.2 million Entech settlement plus related legal fees.

 

Legal fees associated with the Company’s legal contingencies.

 

Professional and consulting fees (largely related to Sarbanes-Oxley compliance activities).

 

Compensation costs due to an increase in the number of employees required to pursue our growth initiatives.

 

Higher costs at Westmoreland Energy LLC for outside consulting.


               However, as a result of the decline in the market price of the Company’s common stock in 2005, the projected cost of our long-term incentive performance unit plan declined and resulted in a benefit of $0.9 million compared to an expense of $2.3 million in 2004.

               Heritage health benefit expenses, exclusive of the cumulative effect of change in accounting principle associated with workers’ compensation, were $5.6 million lower in 2005 compared to 2004 due primarily to three factors as follows:

 

Costs for pneumoconiosis (black lung) benefits were $1.6 million in 2004, but primarily because of reduced actuarial projections a credit of $3.1 million was recorded in 2005.


 

Workers’ compensation expense was $0.9 million less than in 2004 with the conclusion of the case audits discussed below.


 

Costs for the CBF were $0.8 million less than in 2004 as a result of factors discussed more fully in Note 20 to the Consolidated Financial Statements.


               Accrued workers’ compensation expense was significantly higher in 2005 and 2004 relative to 2003 because we conducted and completed case audits of all active claims over the past two years, and because we are using more current mortality tables for those claims. Cash payments, however, have declined over the past three years because indemnity payments for a majority of the beneficiaries have been satisfied. We incurred cash costs of $1.3 million for workers’ compensation during 2005 compared to $1.9 million in 2004.

               We incurred cash costs of $16.9 million for postretirement medical costs during 2005 compared to $16.7 million in 2004. We expect to incur approximately $17.3 million for these costs in 2006.

               Interest expense was $10.9 million and $11.0 million for 2005 and 2004, respectively. Another $0.3 million was incurred and capitalized as acquisition costs in 2005. Interest associated with the increased debt outstanding from the Westmoreland Mining add-on facility and borrowing using the Company’s revolving credit facilities was offset by the lower interest expense on the acquisition financing obtained during 2001 as principal payments are made. Interest income decreased in 2005 in spite of larger balances in our restricted cash and surety bond collateral accounts because 2004 included $0.7 million in interest relating to the Colstrip Units 1 & 2 arbitration decision. Both years include amortization of debt financing costs.

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               When taxable income is generated, the deferred tax asset relating to the Company’s net operating loss carryforwards is reduced and a deferred tax expense (non-cash) is recognized although no regular Federal income taxes are paid. Current income tax expense in both 2005 and 2004 relate to obligations for State income taxes, including the $2.1 million expense recorded for tax assessments for prior years in North Carolina and Federal alternative minimum tax. During 2005, the deferred tax benefit of $12.4 million includes an $8.1 million benefit caused by a reduction in the valuation allowance resulting from an increase in the amount of Federal NOLs carryforwards we expect to utilize before their expiration.

                 Results of operations for the quarter ending December 31, 2005 were affected by several significant adjustments as follows:

 

A $4.0 million credit in Heritage Health Benefit Expenses for Black Lung Benefits.

 

Workers’ Compensation expense of $2.1 million as the result of actuarial changes and updated estimates.

 

Revenue totaling $4.9 million for coal shipped earlier in the year for which the related performance obligations weren’t completed until the fourth quarter.

 

A significant tax benefit as the result of adjusting the valuation allowance related to our Federal NOLs.


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.

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               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 $15.0 million in 2004 compared to $11.9 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 amortization 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 was attributable to a $2.0 million charge for Halifax County personal property tax assessments from prior years, 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 Fort 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, a 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 elected to pay a portion of the 2003 payments in shares of common stock. Future exercises of stock appreciation rights will be settled in common stock.

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

 

These expenses included a $6.3 million credit in 2003 for settlement of the UMWA 1974 pension plan, which was partially offset by a $4.7 million retroactive premium assessed by the Combined Fund.


 

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


               Interest expense was $11.0 million in 2004 and $10.8 million in 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.

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               New Accounting Pronouncements

               Please refer to the new accounting pronouncements discussed in Note 1 to the Consolidated Financial Statements.

ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

               The Company, through its subsidiaries WRI and WML, produces and sells coal to third parties from coal mining operations in Montana, Texas and North Dakota and through its subsidiary, WELLC, produces and sells electricity and steam to third parties from its independent power projects located in North Carolina and Colorado. Nearly all of the Company’s coal production and all of its electricity and steam production are sold through long-term contracts with customers. These long-term contracts serve to minimize the Company’s exposure to 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. During 2005, the Company was not party to any derivative contracts.

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, 2005. Based on the balances outstanding as of December 31, 2005, a one percent change in the prime interest rate or LIBOR would increase interest expense by approximately $200,000 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.

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ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements Page


   
Consolidated Balance Sheets 76
   
Consolidated Statements of Operations 78
   
Consolidated Statements of Shareholders' Equity and Comprehensive Income 80
   
Consolidated Statements of Cash Flows 81
   
Notes to Consolidated Financial Statements 82


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Westmoreland Coal Company and Subsidiaries
Consolidated Balance Sheets






December 31, 2005   2004






(in thousands)
Assets
Current assets:
   Cash and cash equivalents $ 11,216 $ 11,125
   Receivables:
      Trade 29,138 24,891
      Other 7,330 2,848






36,468 27,739
   Inventories 17,576 14,952
   Deferred overburden removal costs 14,090 12,034
   Restricted cash 10,018 9,761
   Deferred income taxes 17,407 13,501
   Other current assets 4,816 6,239






      Total current assets 111,591 95,351






 
Property, plant and equipment:
      Land and mineral rights 21,991 22,234
      Capitalized asset retirement costs 121,941 118,474
      Plant and equipment 127,063 110,196






270,995 250,904
      Less accumulated depreciation, depletion and amortization 97,955 82,276






   Net property, plant and equipment 173,040 168,628
 
Deferred income taxes 81,413 71,195
Investment in independent power projects 50,894 48,565
Excess of trust assets over pneumoconiosis benefit obligation 7,463 4,463
Restricted cash and bond collateral 24,545 22,921
Advance coal royalties 3,874 3,521
Deferred overburden removal costs 2,717 3,910
Reclamation deposits 58,823 55,561
Contractual third party reclamation obligations 31,615 24,998
Other assets 10,624 13,325






Total Assets $ 556,599 $ 512,438






 
See accompanying Notes to Consolidated Financial Statements.

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Westmoreland Coal Company and Subsidiaries
Consolidated Balance Sheets (Continued)






December 31, 2005   2004






(in thousands)
Liabilities and Shareholders' Equity
Current liabilities:
   Current installments of long-term debt $ 12,437 $ 11,819
   Accounts payable and accrued expenses:
      Trade 33,307 24,769
      Deferred revenue - current 583 -
      Income taxes 163 71
      Production taxes 19,609 18,316
      Workers' compensation 949 1,288
      Postretirement medical costs 17,160 16,437
      Asset retirement obligations 17,890 5,284






   Total current liabilities 102,098 77,984






 
Long-term debt, less current installments 94,306 105,440
Revolving lines of credit 5,500 -
Workers' compensation, less current portion 8,394 9,646
Postretirement medical costs, less current portion 124,746 117,792
Pension and SERP costs 16,171 10,637
Deferred revenue - less current portion 1,251 -
Asset retirement obligations, less current portion 140,517 135,509
Other liabilities 6,810 11,268
Minority interest 4,140 4,270
 
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, 2005 and 2004 205 205
   Common stock of $2.50 par value
      Authorized 20,000,000 shares;
      Issued and outstanding 8,413,312 shares at
        December 31, 2005 and 8,168,601 shares
        at December 31, 2004 21,033 20,421
   Other paid-in capital 77,966 75,366
   Accumulated other comprehensive loss (6,845) (5,117)
   Accumulated deficit (39,693) (50,983)






   Total shareholders' equity 52,666 39,892






   Total Liabilities and Shareholders' Equity $ 556,599 $ 512,438






See accompanying Notes to Consolidated Financial Statements.

77

Westmoreland Coal Company and Subsidiaries
Consolidated Statements of Operations









Years Ended December 31, 2005   2004   2003









(in thousands except per share data)
Revenues:    
   Coal $ 361,963   $ 320,291   $ 294,986
   Independent power projects - equity in earnings 12,727   12,741   15,824









   374,690   333,032   310,810









Cost and expenses:    
   Cost of sales - coal 289,992   249,300   228,433
   Depreciation, depletion and amortization 17,740   15,006   11,909
   Selling and administrative 35,103   30,852   33,386
   Heritage health benefit expenses 27,524   33,113   29,922
   Loss (gain) on sales of assets 67   (77)   (645)









   370,426   328,194   303,005









Operating income from continuing operations 4,264   4,838   7,805
     
Other income (expense):    
   Interest expense (10,948)   (10,966)   (10,804)
   Interest income 3,523   3,811   1,952
   Minority interest (950)   (1,154)   (773)
   Other income 1,727   997   1,169









   (6,648)   (7,312)   (8,456)









Loss from continuing operations before income taxes
  and cumulative effect of change in accounting principle
(2,384)   (2,474)   (651)
     
Income tax benefit from continuing operations 12,897   6,934   10,971









Net income from continuing operations before cumulative effect
  of change in accounting principle
10,513   4,460   10,320
     
Discontinued operations:    
      Loss from operations of discontinued terminal segment -   -   (988)
      Gain on sale of discontinued terminal segment -   -   4,509
      Income tax (expense) -   -   (1,408)









        Income from discontinued operations -   -   2,113









Net income before cumulative effect of change
  in accounting principle
10,513   4,460   12,433
     
Cumulative effect of change in accounting principle,
  net of income tax expense of $1,065 (2005)
  and $108 (2003)
1,597   -   161









Net income 12,110   4,460   12,594
     
Less preferred stock dividend requirements 1,744   1,744   1,752









Net income applicable to common shareholders $ 10,366   $ 2,716   $ 10,842










78

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









Years Ended December 31, 2005   2004   2003









            (in thousands except per share data)
Net income per share applicable to common
  shareholders before cumulative effect of
  change in accounting principle:
   
    Basic $ 1.06   $ 0.34   $ 1.37
    Diluted $ 0.99   $ 0.31   $ 1.28
Net income per share applicable to common
  shareholders from cumulative effect of
  change in accounting principle:
   
    Basic 0.19   -   0.02
    Diluted 0.18   -   0.02
     
Net income per share applicable to
  common shareholders:
   
    Basic $ 1.25   $ 0.34   $ 1.39
    Diluted $ 1.17   $ 0.31   $ 1.30









Pro forma amounts assuming the change in
  accounting principle is applied retroactively:
   
   Net income applicable to common shareholders $ 8,769   $ 3,540   $ 11,268
   Net income per share applicable to common
     shareholders:
   
    Basic $ 1.06   $ 0.44   $ 1.44
    Diluted $ 0.99   $ 0.41   $ 1.35









Weighted average number of common
  shares outstanding - basic
8,280   8,099   7,799
Weighted average number of common
  shares outstanding - diluted
8,868   8,662   8,338

See accompanying Notes to Consolidated Financial Statements.

79

Westmoreland Coal Company and Subsidiaries
Consolidated Statements of Shareholders' Equity and Comprehensive Income
Years Ended December 31, 2003, 2004, and 2005













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, 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
  Common stock issued as
    compensation (72,863 shares) - 183 1,536 - - 1,719
  Common stock options exercised
    (171,848 shares) - 429 665 - - 1,094
  Dividends declared - - - - (820) (820)
  Tax benefit of stock option
    exercises
- - 399 - - 399
  Net income - - - - 12,110 12,110
  Minimum pension liability, net of
    taxes of $1,355 - - - (2,033) - (2,033)
  Net unrealized change in interest
    rate swap agreement, net of
    taxes of $203 - - - 305 -     305
  Comprehensive income 10,382













Balance at December 31, 2005
(205,083 preferred and
8,413,312 common shares
outstanding)
$ 205 $ 21,033 $ 77,966 $ (6,845) $ (39,693) $ 52,666













See accompanying Notes to Consolidated Financial Statements.

80

Westmoreland Coal Company and Subsidiaries
Consolidated Statements of Cash Flows







Years Ended December 31, 2005 2004 2003







      (in thousands)
Cash flows from operating activities:
Net income $ 12,110 $ 4,460 $ 12,594
  Adjustments to reconcile net income to net cash
  provided by operating activities:
      Equity in earnings of independent power projects (12,727) (12,741) (15,824)
      Cash distributions from independent power projects 10,702 3,227 11,629
      Deferred income tax benefit (12,369) (7,830) (9,731)
      Depreciation, depletion and amortization 17,740 15,006 11,909
      Stock compensation expense 1,719 1,617 1,851
      Losses (gains) on sales of assets 67 (77) (5,154)
      Minority interest 950 1,154 773
      Cumulative effect of change in accounting principle (2,662) - (269)
      Changes in assets and liabilities:
        Receivables, net (7,178) (411) (668)
        Inventories (2,624) (663) (271)
        Excess of trust assets over pneumoconiosis
          benefit obligation
(3,000) 1,771 1,431
        Accounts payable and accrued expenses 11,748 561 1,343
        Income taxes payable 92 71 (594)
        Accrual for workers' compensation 1,071 1,456 (1,262)
        Accrual for postretirement medical costs 7,566 3,461 13,645
        1974 UMWA Pension Plan obligations - (250) (7,785)
        Other assets and liabilities 5,554 (1,322) 11,137







Net cash provided by operating activities 28,759 9,490 24,754







 
Cash flows from investing activities:
   Additions to property, plant and equipment (18,344) (18,324) (13,240)
   Change in restricted cash and bond collateral (5,143) (10,488) (10,984)
   Net proceeds from sales of assets 641 311 6,970







Net cash used in investing activities (22,846) (28,501) (17,254)







 
Cash flows from financing activities:
   Proceeds from long-term debt, net of debt issuance costs 1,712 34,104 9,373
   Repayment of long-term debt (12,228) (11,679) (14,561)
   Net borrowings (repayments) of revolving lines of credit 5,500 (500) (1,500)
   Repurchase of preferred shares - - (213)
   Dividends paid to minority shareholders of subsidiary (1,080) (1,180) (1,010)
   Exercise of stock options 1,094 862 408
   Dividends on preferred shares (820) (738) (575)







Net cash provided by (used in) financing activities (5,822) 20,869 (8,078)







 
Net increase (decrease) in cash and cash equivalents 91 1,858 (578)
Cash and cash equivalents, beginning of year 11,125 9,267 9,845







Cash and cash equivalents, end of year $ 11,216 $ 11,125 $ 9,267







 
Supplemental disclosures of cash flow information:
Cash paid during the year for:
   Interest $ 10,056 $ 9,629 $ 9,814
   Income taxes 446 552 737

See accompanying Notes to Consolidated Financial Statements.

81

Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements


1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

               The Company’s 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 18, the Company’s share of DTA’s activities has been classified as discontinued operations in the Consolidated Statements of Operations.

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 generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. This includes estimates related to the useful lives of property and equipment. Actual results could differ from those estimates.

               In particular, the Company has significant long-term liabilities relating to retiree health care, work-related injuries and illnesses and defined pension plans. Each of these liabilities is actuarially determined and the Company uses various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for these items. In addition, the Company has significant asset retirement obligations that involve estimations of costs to reclaim mining lands and the timing of cash payments for such costs. If these assumptions do not materialize as expected, actual cash expenditures and costs incurred could differ materially from current estimates. Moreover, regulatory changes could increase the obligation to satisfy these or additional obligations.

               Finally, in evaluating the valuation allowance related to the Company’s deferred tax assets, the Company takes into account various factors, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in the evaluation of our valuation allowance, we may record a change in valuation allowance through income tax expense in the period such determination is made.

82

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 and after any contingent performance obligations have been satisfied. Coal sales revenue is recognized based on the pricing contained in the coal contracts in place at the time that title passes and any retroactive pricing adjustments to those contracts are recognized as revised agreements are reached with the customers and any performance obligations included in the agreements are satisfied.

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.

Deferred Overburden Removal Costs

               During the development of the Company’s mines, before production commences, the costs of removing overburden (stripping costs), net of amounts reimbursed by customers, are capitalized as part of the depreciable cost of building and constructing the mine. Those costs are amortized on a units of production basis as the coal is produced, based on estimates of total reserves.

83

               Stripping costs incurred during the production phase have also been capitalized and deferred and have been expensed using methods and estimates consistent with those used to account for pre-production costs. However, this method will change effective January 1, 2006 as the result of EITF Issue No. 04-6 (See Note 1, “Recent Accounting Pronouncements”). All future stripping costs incurred during the production phase will be absorbed on a current basis in inventory and recognized as a component of cost of sales-coal in the same period as the related revenue. While the Company continues to analyze the impact that EITF 04-6 will have on their financial statements, it is anticipated that substantially all of the $16.8 million on the balance sheet as of December 31, 2005 will be adjusted during the first quarter of 2006 as described more fully below under “Recent Accounting Pronouncements.”

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.

Postretirement Health Care and Life Insurance Benefits

               The Company accounts for postretirement benefits other than pension in accordance with SFAS No. 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (“SFAS 106”) which requires the cost to provide the benefits to be accrued over the employees’ period of active service. These costs are determined on an actuarial basis.

               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.

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.

Pension Plans

               The Company sponsors non-contributory defined benefit pension plans which are accounted for in accordance with SFAS No. 87 “Employers’ Accounting for Pensions” (“SFAS 87”) which requires the cost to provide the benefits to be accrued over the employees’ period of active service. These costs are determined on an actuarial basis.

84

Workers’ Compensation

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

               The liabilities for workers’ compensation claims 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.

               Effective January 1, 2005, Westmoreland changed its method of accounting for workers' compensation. Under the new method, the liability is recorded on a discounted basis. The gross obligation is actuarially determined using various assumptions including a future health care trend rate of 10% declining to 5% in 2011. A risk-free interest rate (4.5% at December 31, 2005) is then used to present value the obligation. Westmoreland believes this change is preferable since it aligns the accounting of workers' compensation liabilities with the Company's other long-term employee benefit obligations, which are recorded on a discounted basis. In addition, these obligations have settled into a predictable payment pattern. The change decreased the workers' compensation liability by $2.7 million and decreased the related deferred tax asset by $1.1 million. If this change were applied retroactively proforma results for 2004 would have increased by $0.6 million (net of tax of $0.4 million) and 2003 results would have increased $0.8 million (net of tax of $0.6 million).

Asset Retirement Obligations

               SFAS No. 143, which was adopted by the Company on January 1, 2003, addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The Company’s asset retirement obligation (“ARO”) liabilities primarily consist of spending estimates related to reclaiming surface land and support facilities at our mines in accordance with federal and state reclamation laws as defined by each mining permit. See Note 3 below for specific information.

Reclamation, 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.

Reclassifications

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

85

Recent Accounting Pronouncements

               In June 2005, the Financial Accounting Standards Board (FASB) issued SFAS Statement No. 154, “Accounting Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statement No. 3” (“SFAS No. 154”). SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It established, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. SFAS No. 154 also provides guidance for determining whether retrospective application of a change in accounting principle is impracticable and for reporting a change when retrospective application is impracticable. The correction of an error in previously issued financial statements is not an accounting change. However, the reporting of an error correction involves adjustments to previously issued financial statements similar to those generally applicable to reporting an accounting change retrospectively. Therefore, the reporting of a correction of an error by restating previously issued financial statements is also addressed by SFAS No. 154. SFAS No. 154 shall be effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. We do not expect this guidance to have a significant impact on the Company.

               In June 2005, the FASB ratified a modification to the consensus reached by the Emerging Issues Task Force in EITF 04-06 “Accounting for Stripping Costs Incurred during Production in the Mining Industry.” The EITF clarified that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. The Task Force noted that the consensus does not address the accounting for stripping costs incurred during the pre-production phase of a mine. In addition, the consensus in this issue is effective for the first reporting period in fiscal years beginning after December 15, 2005. The effect of initially applying this consensus should be accounted for in a manner similar to a cumulative effect adjustment with any adjustment recognized in the opening balance of retained earnings in the year of adoption. When the Company adopts EITF 04-6 on January 1, 2006, it is anticipated that substantially all of the $16.8 million on the balance sheet at December 31, 2005 will be removed, net of taxes and reclassified as a cumulative effect adjustment reducing beginning retained earnings as required by this pronouncement. Adoption of EITF 04-6 will have no impact on the Company’s cash position.

               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 No. 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. In April 2005, the FASB changed the effective date of SFAS No. 123R to the first interim or annual period after December 15, 2005. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition.

86

               As a result the Company will adopt SFAS No. 123R on January 1, 2006, using the modified prospective application. Accordingly, compensation expense will be recognized for all newly granted awards and awards modified, repurchased, or cancelled after January 1, 2006. Compensation expense for the unvested portion of awards that are outstanding as of January 1, 2006, based on the fair value at date of grant as calculated for our pro forma disclosure under SFAS No. 123, will be recognized ratably over the remaining vesting period. Additionally, SFAS No. 123R requires that any tax benefits, arising from compensation deductions that are different than recognized compensation expense, to be reported as a financing cash flow, rather than as an operating cash flow as required under current rules. Compensation expense in the periods following adoption of SFAS No. 123R may differ from our pro forma disclosure under SFAS No. 123, based on changes in the fair value of our common stock, changes in the number of options granted or the terms of such options, the treatment of tax benefits and changes in interest rates or other factors.

               In November 2004, the FASB issued SFAS No. 151, “Inventory Costs: An Amendment of ARB 43, Chapter 4” (“SFAS No. 151”). This statement clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). It requires that amounts be recognized as current period charges. In addition, this statement requires that allocation of fixed production overheads to the costs of inventory be based on the normal capacity of the production facilities. The provisions of this statement are effective for fiscal years beginning after June 15, 2005. The Company does not expect this guidance to have a material impact on its consolidated results of operations and financial condition.

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, 2005, 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: Xcel Energy 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

87

               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, 2005 2004





              (in thousands)
Assets
   Current assets $ 46,458 $ 47,109
   Property, plant and equipment, net 228,323 237,343
   Other assets 25,872 26,297





   Total assets $ 300,653 $ 310,749





         
Liabilities and equity
   Current liabilities $ 45,481 $ 34,019
   Long-term debt and other liabilities 158,529 185,109
   Equity 96,643 91,621





   Total liabilities and equity $ 300,653 $ 310,749





 
WELLC's share of equity $ 50,894 $ 48,565






Income Statements
For years ended December 31, 2005 2004 2003







(in thousands)
 
Revenues $ 109,991 $ 112,669 $ 110,673
Operating income 38,716 40,768 45,918
Net income 24,396 25,063 30,446







WELLC's share of earnings $ 12,272 $ 12,424 $ 15,242







               WELLC performs asset management services for the partnerships and has recognized related revenues of $258,000 for each of the years ended December 31, 2005, 2004 and 2003. 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 to acquire the 50% interest in the ROVA project that we do not currently own. LG&E Energy LLC is now a subsidiary of E.ON U.S. In November 2004, Dominion, 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 Energy’s 50% interest. On March 24, 2005, Dominion filed a Petition for Declaratory Judgment in Virginia in the Circuit Court of the City of Richmond seeking an order validating its alleged right of first refusal under the power purchase agreement to acquire LG&E’s partnership interest in the ROVA Project. On April 29, 2005, the ROVA Project filed a demurrer in the Circuit Court of the City of Richmond requesting the Petition for Declaratory Judgment be denied.

88

               On September 2, 2005, the Richmond Circuit Court granted the Partnership’s demurrer motion, effectively denying Dominion’s claim that it has a right of first refusal under the structure of the proposed acquisition. Dominion filed a motion for reconsideration of the court’s ruling and their motion was denied. Dominion can now file a new Motion for Summary Judgment based on amendments to the acquisition agreement or it can appeal the ruling on the Partnership’s demurrer motion.

               We are currently in discussion with Dominion and LG&E in the hope that this dispute can be resolved on business terms acceptable to all parties.

3.   ASSET RETIREMENT OBLIGATION, RECLAMATION, RECLAMATION DEPOSITS AND CONTRACTUAL THIRD PARTY RECLAMATION OBLIGATIONS

               Changes in the Company’s asset retirement obligations during 2005 and 2004 (in thousands) were:

2005 2004




Asset retirement obligation - beginning of year $ 140,793 $ 123,343
Accretion 8,945 8,351
Settlements (final reclamation performed) (2,944) (5,321)
Gains on settlements 732 (187)
Changes due to amount and timing of reclamation activities 10,880 14,607




Asset retirement obligation - end of year $ 158,407 $ 140,793




               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.

               The total reclamation deposits of $58.8 million at December 31, 2005 consist of $11.9 million of cash and cash equivalents and $46.9 million of Federal agency bonds (government backed securities). 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. The Company has evaluated the securities for an other than temporary impairment and determined that they are not impaired due to the nature of the investments being government backed securities held to maturity. In addition, the Company has recognized as an asset $31.6 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, 2005 are as follows (in thousands):

Amortized cost $ 46,858
Gross unrealized holding gains -
Gross unrealized holding losses (1,314)


Fair value $ 45,544



89

               Maturities of held-to-maturity securities are as follows at December 31, 2005 (in thousands):

Amortized Cost Fair Value




Due in five years or less $ 22,432 $ 21,789
Due after five years to ten years 9,917 9,603
Due in more than ten years 14,509 14,152




$ 46,858 $ 45,544





4.   LINES OF CREDIT AND LONG-TERM DEBT

               The amounts outstanding at December 31, 2005 and 2004 under the Company’s lines of credit and long-term debt consist of the following:

2005 2004




      (in thousands)
WML term debt $ 102,900 $ 113,200
WML revolving line of credit - -
Corporate revolving line of credit 5,500 -
Other term debt 3,843 4,059




112,243 117,259
Less current portion (12,437) (11,819)




$ 99,806 $ 105,440




               As of December 31, 2005, Westmoreland Mining LLC (“WML”) has a $20 million revolving credit facility (the “Facility”) with PNC Bank, National Association (“PNC”), which expires on April 27, 2008. The interest rate is either PNC’s Base Rate plus 1.00% 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, 2005, WML was in compliance with such covenants.

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               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, 2005, WML had funded $10.0 million in the debt service reserve account, which could be used for principal and interest payments, and $12.2 million in the long-term prepayment account, which account will be used to fund the $30.0 million payment due December 31, 2008 for the Series B Notes. 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. The Company is required to maintain certain financial ratios. The revolving credit agreement is collateralized by the Company’s stock in Westmoreland Resources, Inc. (“WRI”), 100% of the common stock of Horizon Coal Services, Inc., and the dragline located at WRI’s Absaloka Mine in Big Horn County, Montana. The expiration date is June 30, 2007.

               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 2010 and bear interest at a weighted-average rate of 5.31%.

               The maturities of all long-term debt and the revolving credit facilities outstanding at December 31, 2005 are (in thousands):

2006 $ 12,437
2007 18,567
2008 45,422
2009 12,080
2010 11,737
Thereafter 12,000


$ 112,243


5.   HERITAGE HEALTH BENEFIT EXPENSES

               The caption “Heritage health benefit expenses” used in our Consolidated Statements of Operations refers to costs of benefits the Company provides as the result of several different government regulations and programs as previously discussed, contractually agreed benefits, past and current, and standard benefits provided voluntarily to attract and retain employees. The components of these expenses are:

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2005 2004 2003
      (in thousands)
Health care benefits $ 23,542 $ 22,819 $ 24,117
Combined benefit fund 4,560 5,390 9,674
Workers' compensation 2,472 3,354 1,010
Black lung benefits (credit) (3,050) 1,550 1,431
UMWA 1974 pension plan - - (6,310)






            Total $ 27,524 $ 33,113 $ 29,922







               Health care benefit costs are the most significant component of “Heritage Health Benefit Expenses” and include net periodic health benefit costs for our former eastern mining operation employees as well as other administrative costs associated with providing those benefits.

6.   WORKERS’COMPENSATION BENEFITS

               The Company was self-insured for workers’ compensation benefits prior to and through December 31, 1995. Beginning in 1996, the Company purchased third party insurance for new workers’ compensation claims. Based on updated actuarial and claims data, $2.5 million, $3.4 million, and $1.0 million were charged to operations in 2005, 2004 and 2003, respectively. There was a $2.7 million pretax benefit ($1.6 million net) recorded in 2005 for a change in accounting principle as more fully described in Note 1 above. The cash payments for workers’ compensation benefits were $1.3 million, $1.9 million and $2.3 million in 2005, 2004 and 2003, 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, 2005 and 2004, $5.3 million and $5.0 million respectively, were held in the collateral accounts.

7.   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, 2005 2004





                (in thousands)
Actuarial present value of benefit obligation:
   Expected claims from terminated employees $ 1,556 $ 1,431
   Claimants 15,323 20,324





Total present value of benefit obligation 16,879 21,755
Plan assets at fair value, primarily government-backed
   securities 24,342 26,218





Excess of trust assets over pneumoconiosis benefit
   obligation $ 7,463 $ 4,463





               The discount rates used in determining the accumulated pneumoconiosis benefit obligation of December 31, 2005 and 2004 were 5.65% and 5.75%, respectively.

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8.   POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS

Single-Employer Plans

               The Company and its subsidiaries provide certain health care and life insurance benefits for retired employees and their dependents either voluntarily or as a result of the Coal Act. Substantially all of the Company’s current employees may also become eligible for these benefits if certain age and service requirements are met at the time of termination or retirement as specified in the plan 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, 2005 2004





               (in thousands)
Assumptions:
Discount rate 5.55% 5.75%
 
Change in benefit obligation:
Net benefit obligation at beginning of year $ 259,776 $ 237,554
Service cost 534 482
Interest cost 14,612 14,837
Plan amendments - (7,181)
Plan participant contributions 113 78
Actuarial losses 16,000 30,797
Gross benefits paid (16,988) (16,791)





Net benefit obligation at end of year 274,047 259,776
 
Change in plan assets:
Employer contributions 16,875 16,713
Plan participant contributions 113 78
Gross benefits paid (16,988) (16,791)





Fair value of plan assets at end of year - -
 
Funded status at end of year (274,047) (259,776)
Unrecognized net actuarial loss 110,365 92,745
Unrecognized prior service costs (1,896) -
Unrecognized net transition obligation 23,672 32,802





Net amount recognized at end of year $ (141,906) $ (134,229)






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               The present value of our actuarially determined liability for postretirement medical costs increased over $14.0 million between December 31, 2004 and 2005, principally because of the decrease in discount rate and use of updated mortality tables. Our discount rate is adjusted annually to reflect current settlement rates which are highly correlated with investment grade long-term bond yields.

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








Year ended December 31, 2005 2004 2003







Assumptions:
Discount rate 5.75% 6.25% 6.75%
 
Components of net periodic benefit
   cost (in thousands):
Service cost $ 534 $ 482 $ 446
Interest cost 14,612 14,837 15,693
Amortization of:
  Transition obligation 3,381 4,100 4,100
  Prior service cost (106) - -
  Actuarial loss 6,124 4,278 4,532







Total net periodic benefit cost $ 24,545 $ 23,697 $ 24,771







               Of the total net periodic benefit cost, $23.2 million, $22.3 million and $23.4 million, relates to the Company’s former eastern mining operations and is included in heritage health benefit costs in 2005, 2004 and 2003, respectively. The remainder of $1.3 million, $1.4 million and $1.4 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 $ 1,828
- - on postretirement benefit obligation $ 32,142
   
Effect of a one percentage point decrease in  
  assumed ultimate health care cost trend  
   
- - on total service and interest cost components $ (1,543)
- - on postretirement benefit obligation $ (27,121)

               The health care cost trend assumed on covered charges was 10.00%, 11.00% and 8.50% for 2005, 2004 and 2003, respectively, decreasing to an ultimate trend of 5.0% in 2011 and beyond.

               Based on the same assumptions used in measuring the Company’s benefit obligation at December 31, 2005, the Company expects to pay benefits in each year from 2006 to 2010 of $17.3 million, $18.5 million, $19.3 million, $20.0 million and $20.5 million, respectively. The aggregate benefits expected to be paid in the five-years from 2011 to 2015 are $95.6 million.

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               The Company was required to obtain surety bonds in connection with certain health care and life insurance premium plans. The Company’s surety bond underwriters required collateral for such bonding. As of December 31, 2005 and 2004, $4.2 million and $4.1 million respectively, were held in the collateral accounts.

               One of the estimates we have made relates to the implementation of the Medicare Prescription Drug Improvement and Modernization Act of 2003 (“Medicare Reform Act”). As provided for under that Act, we recognized a benefit to our anticipated future prescription drug costs for retirees and their dependents in 2003 based on a coordinated implementation of the Medicare Reform Act and our existing benefit programs, including the UMWA 1992 Plan. In 2005, the government issued regulations which made the subsidy approach the only practical alternative given our existing programs. In October 2005, we adopted the subsidy approach for 2006. The subsidy approach will limit our annual benefit to 28% (to a maximum of $1,330/participant) of actual costs. A revised actuarial analysis reduced the projected net present value benefit to us from the Medicare Reform Act and caused a higher resultant future annual expense of approximately $1.3 million than we had anticipated with a coordinated benefits approach.

Multiemployer Plan (Combined Benefit Fund)

               The Company makes payments to the UMWA 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 $34.1 million at December 31, 2005. The nature of this legal obligation does not require a provision, so the Company expenses payments to the CBF when they are due. Payments are generally made on the due date. Payments in 2005, 2004 and 2003 were $3.6 million, $9.4 million and $5.3 million, respectively. As discussed elsewhere, the Company may recover excessive premium payments from past years. See Item 3 – Legal Proceedings and Note 20 to the Consolidated Financial Statements for additional information.

9.   RETIREMENT PLANS

Defined Benefit Pension Plans

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

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Supplemental Executive Retirement Plan

               The Company maintains a 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, 2005 and 2004 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, 2005 2004 2005 2004









    (in thousands)
Assumptions:
 
Discount rate 5.70% 6.00% 5.70% 6.00%
Expected return on plan assets 8.50% 8.50% N/A N/A
Rate of compensation increase 4.20% 4.50% 4.20% 5.00%
 
Change in benefit obligation:
 
Net benefit obligation at beginning of year $ 55,955 $ 47,777 $ 2,199 $ 1,963
Service cost 2,622 2,407 66 58
Interest cost 3,468 3,174 138 128
Actuarial loss 4,571 3,091 82 126
Gross benefits paid (700) (494) (76) (76)









Net benefit obligation at end of year 65,916 55,955 2,409 2,199
 
Change in plan assets:
 
Fair value of plan assets at beginning of year 39,103 32,848 - -
Actual return on plan assets 2,527 3,318 - -
Employer contributions 1,613 3,431 76 76
Gross benefits paid (700) (494) (76) (76)









Fair value of plan assets at end of year 42,543 39,103 - -
 
Funded status at end of year (23,373) (16,852) (2,409) (2,199)
Unrecognized net actuarial (gain) loss 20,868 16,355 (95) (177)
Unrecognized prior service cost 4 54 55 65
Accrued benefit cost (2,501) (443) (2,449) (2,311)
 
Amounts recognized in the accompanying balance sheet consist of:
 
   Accrued benefit cost (2,501) (443) (2,449) (2,311)
   Minimum pension liability (11,297) (7,959) - -









   Net amount recognized at end of year $ (13,798) $ (8,402) $ (2,449) $ (2,311)










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

Qualified Pension Benefits SERP Benefits













Year ended December 31, 2005 2004 2003 2005 2004 2003













(in thousands)
Assumptions:
 
Discount rate 6.00% 6.25% 6.75% 6.00% 6.25% 6.75%
Expected return on plan assets 8.50% 8.50% 8.50% 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 $ 2,622 $ 2,407 $ 2,139 $ 66 $ 58 $ 59
Interest cost 3,468 3,174 2,839 138 128 127
Expected return on assets (3,400) (2,774) (2,393) - - -
Amortization of:
   Transition asset 0 (4) (6) - - -
   Prior service cost 50 50 50 10 10 84
   Actuarial (gain) loss 930 851 803 0 (6) (16)













Total net periodic pension cost $ 3,670 $ 3,704 $ 3,432 $ 214 $ 190 $ 254













               The weighted-average asset allocation of the Company’s qualified pension trusts at December 31, 2005 and 2004 was as follows:

  Allocation of Plan Assets at
December 31
   


 
2005 2004   Target Allocation



 
Asset Category  
    Cash and equivalents 1% -%   0%-25%
    Equity securities 70% 70%   40%-75%
    Debt securities 27% 28%   0%-50%
    Other 2% 2%   0%-10%


 
Total 100% 100%    


 

               The Company’s investment goals are to maximize returns subject to specific risk management policies. We set the expected return on plan assets based on historical trends and forecasts provided by our third-party fund managers. 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 $1.4 million to its qualified pension plans and $76,000 to its SERP in 2006.

               The benefits expected to be paid in each year from 2006 to 2010 are $0.9 million, $1.2 million, $1.5 million, $1.8 million and $2.3 million, respectively. The aggregate benefits expected to be paid in the five years from 2011 to 2015 are $17.1 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.

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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 expense for 2003 by $6.3 million. No further contributions will be required.

10.   INCOME TAXES

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

2005 2004 2003







(in thousands)
Current:
   Federal $ (148) $ (295) $ (25)
   State (389) (601) (251)







(537) (896) (276)
Deferred:
   Federal 11,815 7,074 9,599
   State 554 756 132







12,369 7,830 9,731







 
Income tax benefit $ 11,832 $ 6,934 $ 9,455








               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:

2005 2004 2003







(in thousands)
 
Computed tax (expense) benefit at statutory rate $ (95) $ 841 $ (1,067)
Decrease (increase) in tax expense resulting from:
   Tax depletion in excess of book 3,907 3,184 2,865
   Minority interest adjustment (323) (406) (263)
   State income taxes, net (397) 102 (78)
   Change in valuation allowance
     relating to Federal income taxes 8,050 2,793 7,768
   Change in effective tax rate (342) - -
   Other, net 1,032 420 230







   Income tax benefit $ 11,832 $ 6,934 $ 9,455








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               The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2005 and 2004 are presented below:

2005 2004





Deferred tax assets: (in thousands)
 
Federal net operating loss carryforwards $ 62,981 $ 59,777
State net operating loss carryforwards 10,758 7,903
Alternative minimum tax credit carryforwards 3,030 2,902
Accruals for the following:
   Workers' compensation 3,709 4,373
   Postretirement benefit and pension obligations 59,767 54,518
   Asset retirement obligations 21,388 19,599
   Other accruals 5,796 5,759





Total gross deferred assets 167,429 154,831
Less valuation allowance (18,921) (24,137)





Net deferred tax assets 148,508 130,694





 
Deferred tax liabilities:
Investment in independent power projects (12,594) (13,023)
Plant and equipment, differences due to depreciation and amortization (34,157) (31,190)
Excess of trust assets over pneumoconiosis benefit obligation (2,937) (1,785)





Total gross deferred tax liabilities (49,688) (45,998)





Net deferred tax asset $ 98,820 $ 84,696





               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 will more likely than not expire before they can be realized in future periods. At December 31, 2005 the valuation allowance for Federal tax purposes was $8.5 million and relates primarily to NOLs that will expire if we are unable to generate sufficient taxable income.

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

2005 2004




(in thousands)
Deferred income tax assets - current $ 17,407 $ 13,501
Deferred income tax assets - long-term 81,413 71,195




$ 98,820 $ 84,696





               An income tax benefit of $399,000, $590,000 and $484,000 related to the exercise of stock options during 2005, 2004 and 2003, respectively, was added to other paid-in capital.

99

               As of December 31, 2005, a minimum of $185.2 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 $167.4 million. As of December 31, 2005, 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 $ 45,297
2011 36,479
2012 449
2018 28
2019 88,429
after 2019 14,556



Total $ 185,238



               Current tax expense results from Federal Alternative Minimum Tax and estimated state income taxes. The deferred income tax benefit recorded for 2005 included a benefit of $8.1 million due to a reduction in the deferred income tax asset valuation allowance because of an increase in the amount of Federal net operating loss carryforwards the Company expects to use prior to their expiration through 2025. This resulted from changes in future estimates of taxable income. The deferred income tax benefit recorded for 2004 and 2003 included a benefit of $2.8 million and $7.8 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 $3.0 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 $14.9 million as of December 31, 2005. As of December 31, 2005, the Company also has available an estimated $14.5 million in net operating loss carryforwards in Colorado to reduce future taxable income.

11.   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, 2006 amount to $17.2 million in the aggregate ($84.03 per preferred share or $21.01 per Depositary Share). Common stock dividends may not be declared until the preferred stock dividends that are accumulated but unpaid are made current.

100

               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, 2005). The Company had shareholders’ equity of $52.7 million and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $21.2 million at December 31, 2005.

               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.

101

12.   INCENTIVE STOCK OPTION AND STOCK APPRECIATION RIGHTS PLANS

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:

2005 2004 2003






(in thousands, except per share data)
Net income applicable to common shareholders:
    As reported $ 10,366 $ 2,716 $ 10,842
    Pro forma $ 10,189 $ 1,968 $ 10,067
 
Income per share applicable to common shareholders:
    As reported, basic $ 1.25 $ 0.34 $ 1.39
    Pro forma, basic $ 1.23 $ 0.24 $ 1.29
    As reported, diluted $ 1.17 $ 0.31 $ 1.30
    Pro forma, diluted $ 1.15 $ 0.23 $ 1.21







               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 2004 and 2003. No stock options were granted during 2005. The weighted average fair value of options granted in 2004 and 2003 was $11.41 and $8.81, 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

               As of December 31, 2005, the Company had options outstanding from three shareholder-approved Incentive Stock Option (“ISO”) 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 or three 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 1,150,000, and as of December 31, 2005, 212,568 shares are available for future issue or grant.

102

               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, 2005, 19,176 shares are available for future issue or grant.

               During 2005 and 2004, the Company granted 246,100 and 178,927 stock appreciation rights (SARs), respectively to selected officers and managers. 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 SARs have vested, the holders may exercise the SARs 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. On December 30, 2005 the Company accelerated the vesting of all unvested SARs, essentially all of which were in the money, resulting in additional expense of $0.2 million. This decision will reduce future expense. Based on the value of the Company’s common stock as of December 31, 2005, the value of the SARs was estimated to be $1.0 million, which would be equivalent to 44,321 shares.

               Information for 2005, 2004 and 2003 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, 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
Granted in 2005 - - -
Exercised in 2005 2.63-18.19 (171,848) 6.36
Expired or forfeited in 2005 12.86-18.19 (36,202) 16.54




Outstanding at December 31, 2005 $  2.81-22.86 717,950 $  10.20




               Information about stock options outstanding as of December 31, 2005 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   326,650 3.2 $   2.95 326,650 $   2.95
5.01-10.00     - -   -   -    -
10.01-15.00   101,435 6.3 12.35 91,435  11.94
15.01-22.86   289,865 6.8 17.61 215,892  17.62






$    2.63-22.86 717,950 5.1 $ 10.20 633,977 $   9.33







103

13.   BUSINESS SEGMENT INFORMATION

               The Company’s operations have been classified into two segments: coal and independent power operations. The coal segment includes the production and sale of coal from 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 expenses, heritage health benefit expenses and business development expenses. Corporate assets consist primarily of cash, bonds and deposits required for Heritage Health Benefits and deferred income taxes. Summarized financial information by segment for 2005, 2004 and 2003 is as follows:

Year ended December 31, 2005

Coal Independent Power Corporate Total








(in thousands)
Revenues:
  Coal $ 361,963 $ - $ - $ 361,963
  Equity in earnings - 12,727 - 12,727








361,963 12,727 - 374,690
Costs and expenses:
  Cost of sales – coal 289,992 - - 289,992
  Depreciation, depletion and amortization 17,453 24 263 17,740
  Selling and administrative 22,286 1,956 10,861 35,103
  Heritage health benefit expenses - - 27,524 27,524
  Loss on sales of assets 177 - (110) 67








Operating income (loss) from continuing operations $ 32,055 $ 10,747 $ (38,538) $ 4,264








Capital expenditures $ 18,214 $ 52 $ 78 $ 18,344








Total assets $ 379,208 $ 38,533 $ 138,858 $ 556,599









104

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 14,841 19 146 15,006
  Selling and administrative 19,021 981 10,850 30,852
  Heritage health benefit expenses - - 33,113 33,113
  Gain on sales of assets (77) - - (77)








Operating income (loss) from continuing operations $ 37,206 $ 11,741 $ (44,109) $ 4,838








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








Total assets $ 348,064 $ 35,531 $ 128,843 $ 512,438








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 11,761 22 126 11,909
  Selling and administrative 23,626 1,013 8,747 33,386
  Heritage health benefit expenses - - 29,922 29,922
  Gain on sales of assets (194) - (451) (645)








Operating income (loss) from continuing operations $ 31,360 $ 14,789 $ (38,344) $ 7,805








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








Total assets $ 313,999 $ 25,160 $ 118,678 $ 457,837









105

               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:

2005 2004 2003
    (in thousands)          
Customer A $ 111,224 $ 83,196 $ 99,688
Customer B 75,750 70,909 70,431
Customer C 39,146 50,951 28,681



Percentage of total revenue 60% 62% 64%



14.   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 2005, 2004 and 2003, the Company also 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, and totaled $2.0 million, $0.7 million and $0.7 million in 2005, 2004, and 2003 respectively.

15.   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.

106

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

2005 2004 2003



  (in thousands of shares)
Weighted average number of common shares outstanding:
   Basic 8,280 8,099 7,799
   Effect of dilutive instruments 588 563 539



   Diluted 8,868 8,662 8,338



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




16.   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, 2005, 2004 and 2003, WML paid dividends and management fees to Westmoreland of $2.3 million, $11.9 million and $14.7 million, respectively. In addition, WML paid Westmoreland $9.1 million in 2005 and $19.3 million in 2004 to reduce its intercompany payable.

107

               The following are the condensed consolidated financial statements of WML and its subsidiaries as of and for the years ended December 31, 2005 and 2004 (in thousands):

Condensed Consolidated Balance Sheets
   December 31,
2005 2004
Cash and cash equivalents $ 2,999 $ 4,627
Accounts receivable, net 31,954 22,400
Restricted cash 23,376 21,874
Deferred overburden removal costs 16,807 15,944
Other current assets 20,422 18,911
Property, plant and equipment, net 181,947 182,339
Reclamation deposits 58,823 55,561
Contractual third party reclamation obligations 24,811 18,278
Deferred income tax assets 1,674 2,633
Other assets 7,223 9,469




   Total Assets $ 370,036 $ 352,036




 
Accounts payable and accrued expenses $ 39,979 $ 33,181
Payable to parent 3,192 10,000
Long-term debt and line of credit 106,743 117,259
Asset retirement obligations 149,840 132,740
Other liabilities 14,069 11,735
Member's equity 56,213 47,121




   Total Liabilities and Member's Equity $ 370,036 $ 352,036





Condensed Consolidated Statements of Operations
 
     Year Ended December 31,
2005 2004
 



Coal revenues $ 302,460 $ 265,646
Cost of sales – coal (240,861) (204,738)
Depreciation and amortization expense (19,059) (16,313)
Selling and administrative expense (21,955) (19,061)
Management fees to parent (2,000) (2,000)




   Operating income 18,585 23,534
 
Interest expense (10,483) (10,545)
Interest and other income 3,080 3,087




   Income before income taxes and
     cumulative effect of change in
     accounting principle
11,182 16,076
 
Income tax expense (1,790) (5,027)




Net income $ 9,392 $ 11,049





108

Condensed Consolidated Statements of Cash Flows
 
     Year Ended December 31,
2005 2004
 



Net income $ 9,392 $ 11,049
Depreciation and amortization expense 19,059 16,313
Deferred income tax expense (benefit) 959 (2,747)
Changes in operating assets and liabilities (858) (13,568)




   Cash provided by operating activities 28,552 11,047
 
Fixed asset additions (15,026) (16,067)
Increase in restricted cash (4,764) (7,222)
Proceeds from asset sales 426 302




   Cash used in investing activities (19,364) (22,987)
 
Proceeds from borrowings of long-term debt, net 1,462 34,106
Repayment of long-term debt (11,978) (11,679)
Dividends to parent (300) (9,913)




   Cash used in financing activities (10,816) 12,514




Net increase in cash and cash equivalents (1,628) 574
Cash and cash equivalents, beginning of year 4,627 4,053




Cash and cash equivalents, end of year $ 2,999 $ 4,627