UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, DC  20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2009

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)

Registrant’s telephone number, including area code:

(719) 442-2600

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

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes ¨  No þ

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 þ

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

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).     Yes ¨  No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-T (§ 232.405) 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 10-K or any amendment to this Form 10-K.     ¨

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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).     Yes   ¨     No   þ

The aggregate market value of voting common stock held by non-affiliates as of June 30, 2009 was $69,181,468.

There were 10,541,556 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, 2010.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement to be used by the Company in connection with its 2010 Annual Meeting of Stockholders scheduled to be held on May 20, 2010 are incorporated by reference into Part III of this Annual Report on Form 10-K.

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

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Cautionary Note Regarding Forward-Looking Statements

This Annual Report on Form 10-K contains “forward-looking statements.”  Forward-looking statements can be identified by words such as “anticipates,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects” and similar references to future periods.  Examples of forward-looking statements include, but are not limited to, statements we make regarding our expected increase in tons of coal to be delivered, the amount of our coal that will be subject to purchase contracts through 2019, an expected decrease in heritage health benefit expenses, cash payments and administrative costs, a reduction in cash receipts and the impact on our revenues due to a change in the rate charged by our ROVA plant, an expected decrease in pension expenses, an expected increase in our required pension plan contributions, an expected increase in our depreciation expense, anticipated capital investments and how such investments will be funded, an expected increase in our restricted investments and bond collateral, an expected reduction in our repayment obligations, and our expectation that our cash from operations and available borrowing capacity will be sufficient to meet our working capital and bonding requirements, planned capital expenditures and debt payments for the foreseeable future.  

Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict.  Our actual results may differ materially from those contemplated by the forward-looking statements.  We caution you therefore against relying on any of these forward-looking statements.  They are neither statements of historical fact nor guarantees or assurances of future performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements include political, economic, business, competitive, market, weather and regulatory conditions and the following:

·

changes in our postretirement medical benefit and pension obligations;

·

inability to expand or continue current coal operations due to limitations in obtaining bonding capacity for new mining permits;

·

our ability to maintain compliance with debt covenant and waiver agreement requirements or obtain waivers from our lenders in cases of non-compliance with our debt covenants;

·

the inability of our subsidiaries to pay dividends to us due to restrictions in our debt arrangements or reductions in planned coal deliveries;

·

the structure of ROVA’s contracts with its lenders, coal suppliers and the power purchaser, which could dramatically affect the overall profitability of ROVA;

·

the effect of prolonged maintenance or unplanned outages at our operations or those of our major power generating customers;

·

future legislation and changes in regulations, governmental policies and taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases; and

·

the other factors that are described in “Risk Factors” herein.

Any forward-looking statements made by us in this Annual Report on Form 10-K speaks only as of the date on which it was made. Factors or events that could cause our actual results to differ may emerge from time-to-time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future developments or otherwise, except as may be required by law.

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

ITEM 1—BUSINESS.

Overview

Westmoreland Coal Company began mining in Westmoreland County, Pennsylvania in 1854 as a Pennsylvania corporation.  In 1910, we incorporated in Delaware and continued our focus on underground coal operations in Pennsylvania and the Appalachian Basin. We moved our headquarters from Philadelphia, Pennsylvania to Colorado Springs, Colorado in 1995 and fully divested ourselves of all Eastern coal operations.

Today, Westmoreland Coal Company is an energy company employing 1,109 employees whose operations include five surface coal mines in Montana, North Dakota and Texas and two coal-fired power generating units with a total capacity of 230 megawatts in North Carolina.  We sold 24.3 million tons of coal in 2009. Our two principal operating segments are our coal segment and our power segment.  Our two non-operating segments are heritage and corporate.  Our heritage segment primarily includes the costs of benefits we provide to former mining operation employees and our corporate segment consists primarily of corporate and business development expenses.  We incorporate by reference the information about the operating results of each of our segments for the years ended December 31, 2009, 2008 and 2007 contained in Note 18 — Segment Information to our consolidated financial statements.  The following chart provides an overview of the operating subsidiaries that make up our coal and power segments:

Coal Segment

General

Our coal segment is focused on niche coal markets where we take advantage of long-term coal contracts and rail transportation advantages.  Approximately, two-thirds of our coal production is mine mouth, governed by long-term coal contracts with the neighboring power plant, while approximately the other third of coal production is sold in the open market where we take advantage of being the closest coal producer to our core open market customers via rail transportation.  Currently, two-thirds of our produced coal is non-compliance sub-bituminous coal from the Northern Powder River Basin, while the remaining third is lignite.  We project that over 50% of our contracted tons in 2010 will still be under contract in 2019.  In addition, in 2010, we will be one of only three U.S. coal companies operating on Indian reservations, allowing us to enter into transactions to monetize Indian Coal Tax Credits.

In 2009, we sold 24.3 million tons of coal compared to 29.3 million in 2008.  Our decrease in tons sold resulted from reduced demand for coal due to the global economic downturn, reduced electricity demands principally caused by adverse weather conditions and unscheduled customer shutdowns at our Rosebud and Beulah Mines.

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The following table provides summary information regarding our principal mining operations as of December 31, 2009:

(1)   567 employees, or approximately 51% of our total employees, are represented by collective bargaining agreements.  The labor agreement at the Savage Mines expires during 2010.

Properties

We had an estimated 425.1 million tons of proven and probable coal reserves as of December 31, 2009.  Montana, Texas, and North Dakota each use a permitting process approved by the Office of Surface Mining.  Our mines have chosen to permit coal reserves on an incremental basis and currently have sufficient permitted coal to meet production, given the current rates of mining and demand, for the periods shown in the table below. We secure all of our final reclamation obligations by bonds as required by the respective state agencies.  We perform contemporaneous reclamation activities at each mine in the normal course of operations and coal production.

Our mines control coal reserves and deposits through long-term leases.  Coal reserves are that part of a mineral deposit that can be economically and legally extracted at the time of the reserve determination.  Coal deposits do not qualify as reserves until we conduct a final comprehensive economic evaluation and conclude it is legally and economically feasible to mine the coal. We base our estimate of the economic recoverability of our reserves upon a comparison of potential reserves to reserves currently in production in a similar geologic setting to determine an estimated mining cost.  We compare these estimated mining costs to existing market prices for the anticipated quality of coal.  We only include reserves expected to be economically mined in our reserve estimates.

Our engineers and geologists prepare our reserve estimates. We periodically engage independent mining and geological consultants to review the models and procedures we use in preparing our internal estimates of coal reserves according to standard classifications of reliability. Total recoverable reserve estimates change over time to reflect mining activity, analysis of new engineering and geological data, information obtained from our ongoing drilling program, changes in reserve holdings and other factors.  We compile data from individual drill holes in a database from which the depth, thickness and the quality of the coal are determined.  We classify reserves as either proven or probable based on the density result of the drill pattern.

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The following table provides information about our mines as of December 31, 2009:

(1)

Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:

Proven (Measured) Reserves — 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 close and the geographic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

Probable (Indicated) Reserves — Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) 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 (measured) reserves, is high enough to assume continuity between points of observation.

(2)

Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates.  Our Jewett Mine’s permit is expected to be renewed in 2010, but effectively covers all of the Mine’s reserves for the entire life of the mine.  The Absaloka Mine permits expire in 2013 and 2014.

(3)

Approximate heat content applies to the coal mined in 2009.

(4)

Approximate sulfur content applies to the tons mined in 2009.

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We lease all our coal properties except at the Jewett Mine, where we control some reserves through fee ownership. We are a party to coal leases with the federal government, state governments, and private parties at our Rosebud, Beulah, Savage and Jewett Mines.  Each of the federal and state government leases continue indefinitely provided there is diligent development of the property and continued operation of the related mines.  Federal statute generally sets production royalties on Federal leases at 12.5% of the gross proceeds of coal mined and sold for surface mines.  At the Beulah and Savage Mines, we have received reductions in the Federal royalty rate due to the quality of the lignite coal mined.  Our private leases run for an average term of twenty years and have options for renewal. We believe that we have satisfied all lease conditions in order to retain the properties and keep the leases in force.

We are a party to two leases with the Crow Tribe covering 18,406 acres of land at our Absaloka Mine.  In 2008, WRI entered into a series of transactions, including the formation of Absaloka Coal, LLC with an unaffiliated investor, in order to take advantage of certain available tax credits for the production of coal on the Crow Tribe leased land.  The tax credit is equal to $2.21 per ton in 2010 and increases annually to $2.30 per ton in 2012. We received a private letter ruling from the IRS providing that the Indian Coal Tax Credits are available to us.  As part of such transaction, WRI subleased its leases with the Crow Tribe to Absaloka Coal, LLC, granting it the right to mine specified quantities of coal through September 2013, with WRI as contract miner. We will pay to the Crow Tribe 33% of the expected payments we will receive from the investor.  WRI fully encumbered all of its property by a first lien under the revolving credit facility with First Interstate Bank and a second lien under the Note Purchase Agreement with Tontine Associates.  In addition, Westmoreland Mining LLC fully encumbered all of its property at our Rosebud, Beulah and Savage mines pursuant to our June 2008 fixed rate term debt and revolving debt.

Customers

We sell almost all of the coal that we produce (over 99% in 2009) to plants that generate electricity.  In 2009, approximately 60% of our total revenues were derived from coal sales to four power plants:   Limestone Generating Station (19% of our 2009 revenues), Colstrip Units 3&4 (18%), Colstrip Units 1&2 (12%) and Sherburne County Station (11%).  More than 80% of our tons are sold under contracts with remaining supply obligation terms of three years or more. We provide transportation for our mine-mouth customers, but sell coal plus lignite on a Free On Board, or FOB, basis to our other customers. Our coal revenues include amounts earned by our coal sales company from sales of coal produced by mines other than ours.  In 2009, 2008, and 2007, such amounts were $0.8 million, $1.2 million, and $4.1 million, respectively.

Rosebud.  The Rosebud Mine has two contracts with the adjacent Colstrip Station power generating facility.  Effective January 1, 2010, a new cost-plus agreement commenced with Colstrip Units 1&2 with a projected term through at least 2019 and expected tons of 3.0 million per year.  A second agreement at Units 3&4 covers approximately 7.0 million tons per year and is set to expire at the end of 2019.  This contract is also cost-plus, but with specific return on capital investment provisions.  The Rosebud Mine also has a 1.5 to 2.5 million ton per year fixed price contract with Minnesota Power’s Boswell Station that expires on December 31, 2010.  We do not expect to renew this contract at the Rosebud Mine at this time due to the poor economics of the contract.

Absaloka.  The Absaloka Mine operates primarily in the open market and has several contracts with various parties that totaled roughly 6.0 million tons in 2009 and decline to zero by the end of 2014.  More than 3.0 million tons expired at the end of 2009 under three separate agreements, which we successfully renegotiated during the year.  Approximately 80% of all tons sold were to the rail-served Sherburne County Station under several contracts.

Savage.  The Savage Mine supplies approximately 0.3 million tons per year to the local Lewis & Clark Station under an agreement that expires at the end of 2012.  Prices under this agreement are based upon certain actual mine costs and certain inflation indices for such items as diesel fuel.

Jewett.  The Jewett Mine has a cost-plus agreement with NRG Texas Power’s adjacent Limestone Generating Station, which commenced January 1, 2008, replacing various prior agreements in place since 1985.  NRG Texas Power is obligated to pay all mine costs of production plus a margin and the mine’s capital and reclamation expenditures.  The agreement has a term through 2018, which may be extended by NRG Texas Power for up to an additional ten years or until the mine’s reserves are exhausted.  NRG has the option to determine volumes to be delivered, which currently average approximately 4.5 million tons per year and to terminate the agreement at its discretion.

Beulah.  The Beulah Mine supplies approximately 2.5 million tons per year to the adjacent Coyote Station under an agreement that expires in May 2016.  It also supplies approximately 0.5 million tons per year to the rail-served Heskett Station under an agreement that expires during 2011.  Prices under these agreements are based upon certain actual mine costs and certain inflation indices for such items as diesel fuel.

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Competition

While the coal industry is intensely competitive, we focus on niche coal markets where we take advantage of long-term coal contracts with neighboring power plants and rail transportation advantages.  For our coal sold into the open market, we compete with many other suppliers of coal to provide fuel to power plants.  Additionally, coal competes for electrical power generation with other fuels such as nuclear energy, natural gas, hydropower, petroleum and wind.  Costs and other factors such as safety, environmental and regulatory considerations relating to these alternative fuels affect the overall demand for coal as a fuel.

We believe that our mines have a competitive advantage based on three factors:

·

all of our mines are the most economic suppliers to each of their respective principal customers, a result of a transportation advantage over our competitors in that market;

·

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

·

the plants we supply are among the lowest cost producers of electric power in their respective regions and are among the cleaner producers of power from solid fossil fuels.

As a result of the foregoing, we believe that our current customers are more likely to be dispatched to produce power and to continue purchasing coal extracted from our mines.

The principal customers of the Rosebud, Jewett, and Beulah Mines are located adjacent to the mines; the coal for these customers can generally be delivered by conveyor belt instead of more expensive means such as 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 truck.

The Absaloka Mine faces a different competitive situation.  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 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 enjoys an approximately 300-mile rail advantage over its principal competitors from the Southern Powder River Basin in supplying customers located in the northern tier. Rail rates have increased over the last several years by 50 to 100%, which increases our competitive advantage. We also believe that the next most economic suppliers to Absaloka’s northern tier customers could be our other mines.

Material Effects of Regulation

We are subject to extensive regulation with respect to environmental and other matters by federal, state and local authorities.  Federal laws to which we are subject include the Surface Mining Control and Reclamation Act of 1977, or SMCRA, the Clean Air Act, the Clean Water Act, the Toxic Substances Control Act, the Endangered Species Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act and the Resource Conservation and Recovery Act.  These laws are administered and enforced by the United States Environmental Protection Agency, or EPA, and/or other authorized federal or state agencies. Any non-compliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, including suspension or termination of operations. In addition, we may be required to make large and unanticipated capital expenditures to comply with applicable laws. Our reclamation obligations under applicable environmental laws will be substantial. Our coal sales agreements contain government impositions provisions that allow the pass-through of compliance costs in some circumstances. The following summarizes certain legal and regulatory matters that we believe may significantly affect us.

Surface Mining Control and Reclamation Act.  SMCRA establishes minimum national operational, reclamation and closure standards for all surface coal mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of coal mining activities. Permits for all coal mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement, or OSM, or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards that are more stringent than the requirements of SMCRA and OSM’s regulations and in many instances have done so. Permitting under SMCRA has generally become more difficult in recent years, which adversely affect the cost and availability of coal purchased by ROVA, especially in light of significant permitting issues affecting the Central Appalachia region.

Clean Air Act and Related Regulations.  The federal Clean Air Act and similar state laws and regulations affect coal mining, coal handling and processing and energy production primarily through permitting and/or emissions control requirements. For example, regulations relating to fugitive dust and coal combustion emissions could restrict our ability to develop new mines or require us to modify our operations. The Clean Air Act also extensively regulates the air emissions of coal fired electric

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power generating plants such as ROVA and plants operated by our coal customers. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coal is burned. The Clean Air Act and similar legislation regulate these emissions and therefore affect demand for our coal.  In particular, our mines do not produce “compliance coal” for purposes of the Clean Air Act.  Compliance coal is coal containing 1.2 pounds or less of sulfur dioxide per million British thermal unit, or Btu.  This restricts our ability to sell coal to power plants that do not utilize sulfur dioxide emission controls and otherwise leads to a price discount based, in part, on the market price for sulfur dioxide emission allowances under the Clean Air Act.  Our coal also contains about twice the ash content of our primary competitors, which can translate into a cost disadvantage where post-combustion coal ash must be land filled.

While new regulations under the Clean Air Act or similar statutes could increase market prices for sulfur dioxide emission allowances and therefore the price discount applied to our coal, they could also cause power plants to retrofit sulfur dioxide emission controls, therefore expanding our market potential.  Higher costs for complying with coal ash regulations could also result in a higher price discount for our open market coal.

We are at particular risk of changes in applicable environmental laws with respect to the Jewett Mine, whose customer, the NRG Texas Power-Limestone Station, blends our lignite with compliance coal from Wyoming.  Tightened nitrogen oxide and new mercury emission standards could result in an increased blend of the Wyoming coal to reduce emissions.  Further, increased market prices for sulfur dioxide emissions and increased coal ash costs could also favor an increased blend of the lower ash Wyoming compliance coal.  In such a case, NRG Texas Power has the option to increase its purchases of other coal, reduce purchases of our coal and to terminate our contract.  If NRG terminates the contact, sales of lignite would end and the Jewett Mine would commence final reclamation activities.  NRG would pay for all reclamation work plus a margin.

Bonding Requirements.  Federal and state laws require mine operators to assure, usually through the use of surety bonds, payment of certain long-term obligations, including the costs of mine closure and the costs of reclaiming the mined land. The costs of these bonds have fluctuated in recent years, and the market terms of surety bonds have generally become more unfavorable to mine operators. Surety providers are requiring greater percentages of collateral to secure a bond, which has required us to provide increasing quantities of cash to collateralize bonds to allow us to continue mining. These changes in the terms of the bonds have been accompanied, at times, by a decrease in the number of companies willing to issue surety bonds.  As of December 31, 2009, we have posted an aggregate of $227.4 million in surety bonds for reclamation purposes.

Resource Conservation and Recovery Act.  We may generate wastes, including ‘‘solid’’ wastes and ‘‘hazardous’’ wastes that are subject to the federal Resource Conservation and Recovery Act, or  RCRA, and comparable state statutes, although certain mining and mineral beneficiation wastes and certain wastes derived from the combustion of coal currently are exempt from regulation as hazardous wastes under RCRA.  The EPA has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA.  Furthermore, it is possible that certain wastes generated by our operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly management, disposal and clean-up requirements.

Comprehensive Environmental Response, Compensation, and Liability Act.  Under the Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or Superfund, and similar state laws, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated ‘‘hazardous substances’’ at the site, regardless of the lawfulness of the original activities that led to the contamination.  CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the potentially responsible parties the costs of such action.  In the course of our operations we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances.  We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators.  We may be responsible under CERCLA for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages.  We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

Climate Change Legislation and Regulations.  Numerous proposals for federal and state legislation have been made relating to greenhouse gas, or GHG, emissions (including carbon dioxide) and such legislation could result in the creation of substantial additional costs in the form of taxes or required acquisition or trading of emission allowances. Many of the federal and state climate change legislative proposals use a “cap and trade” policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap would become more stringent with the passage of time. The proposals establish mechanisms for GHG sources such as power plants to obtain “allowances” or permits to emit GHGs during the course of a year.  The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions for their own operations.

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In addition, the EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has begun to implement GHG-related reporting and permitting rules.

The impact of GHG-related legislation and regulations, including a “cap and trade” structure, on us will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on coal prices. We may not recover the costs related to compliance with regulatory requirements imposed on us from our customer due to limitations in our agreements.

Passage of additional state or federal laws or regulations regarding GHG emissions or other actions to limit carbon dioxide emissions could result in fuel switching from coal to other fuel sources by electricity generators and thereby reduce demand for our coal.  In addition, political and regulatory uncertainty over future emissions controls have been cited as major factors in decisions by power companies to postpone new coal-fired power plants.  If these or similar measures, such as controls on methane emissions from coal mines, are ultimately imposed by federal or state governments or pursuant to international treaties, our operating costs may be materially and adversely affected.  Also, alternative sources of power, including wind, solar, nuclear and natural gas, could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues.  Similarly, some of our customers, in particular smaller, older power plants, could be at risk of significant reduction in coal burn or closure as a result of imposed carbon costs.  The imposition of a carbon tax or similar regulation could, in certain situations, lead to the shutdown of coal-fired power plants, which would materially and adversely affect our coal and power plant revenues.

Power Segment

General

We own two coal-fired power-generating units in Weldon, North Carolina with a total capacity of 230 megawatts, which we refer to collectively as ROVA.  ROVA, which commenced operations in 1994, was built as a Public Utility Regulatory Policies Act co-generation facility with long-term power purchase agreements with Dominion Virginia Power.  While we initially structured the project as a joint venture where we owned a 50% interest in the partnership that owned ROVA, we acquired the other 50 percent partnership interest in ROVA in June 2006, bringing our ownership interest in the ROVA project to 100 percent. ROVA has been reclassified as an Electric Wholesale Generator, a Federal Energy Regulatory Commission classification created by the Energy Policy Act of 1992.  Westmoreland Partners has fully encumbered all power plant property pursuant to the Second Amended and Restated Loan Agreement with Prudential Investment Management, Inc.

The following table shows megawatt hours produced and average annual capacity factors achieved at ROVA for the last three years:

Coal Supply

ROVA purchases coal under long-term contracts from coal suppliers with identified reserves located in Central Appalachia, which contracts expire in 2014 and 2015.

Customer

ROVA supplies power to Dominion Virginia Power under long-term contracts, which expire in 2019 and 2020.  We can extend, by mutual consent, the contracts with Dominion Virginia Power for five-year terms at mutually agreeable pricing.  In 2009, the sale of power to Dominion Virginia Power accounted for approximately 18% of our consolidated revenues.

Material Effects of Regulation

For a thorough discussion of the extensive regulation with respect to environmental and other matters by federal, state and local authorities affecting our power segment, see Item 1 under “Coal Segment -Material Effects of Regulation.”

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With respect to our power segment, ROVA is among the newer and cleaner coal-fired power plants in the United States.  It is exempted under Title IV of the Clean Air Act, but may opt-in to receive allocations of sulfur dioxide emission allowances.  The plant is among the lowest coal-fired emitters of mercury in the country.  We are evaluating whether ROVA could be a net consumer or seller of sulfur dioxide allowances, nitrogen oxide credits and mercury allowances under new and pending regulations.  However, we currently expect an increase in costs associated with nitrogen oxide allowances at ROVA.  With regard to coal ash regulations, ROVA both remarkets and landfills its combustion waste.  Landfills are lined and meet strict North Carolina Department of Solid Waste regulations.  Should ROVA incur additional costs of regulatory compliance, it is unlikely that we will be able to pass through these costs under our agreements with Dominion Virginia Electric.

An important factor relating to the impact of GHG-related legislation and regulations on our power segment will be our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not recover the costs related to compliance with regulatory requirements imposed on us due to limitations in our power purchase agreements. If we are unable to pass through such costs incurred by ROVA to Dominion Virginia Power or recoup them in another manner such as through allowances, it could have a material adverse effect on our results of operations at ROVA.

Heritage Segment

Our heritage segment costs consist primarily of payments for medical benefits to our retired workers, workers’ compensation benefits, black lung benefits and combined benefit fund premiums. These collective heritage obligations are funded by distributions from our operating subsidiaries.     

Management has been working over the past several years to reduce our heritage obligations. In 2009, we changed our health provider network for our retiree population, resulting in substantial savings and corresponding reduction in heritage liability. Additionally, in September 2009, we eliminated postretirement medical benefits for our non-represented retiree population.  Lastly, in December 2009, we entered into an agreement with the United Mine Workers of America to modernize the method by which prescription drugs are provided to retirees of our former operations. Under the agreement, we will utilize a new system of distribution and administration, along with drug formularies, to enable us to continue to provide prescription drug benefits to retirees, but at a lower cost. These modifications are expected to become effective around April 15, 2010.  Management’s collective efforts to reduce our heritage obligations have resulted, as of the end of fiscal year 2009, in substantial reductions in our postretirement medical benefit obligation.

  We will continue to explore ways to further reduce or eliminate other portions of our benefits costs incurred as a consequence of our former operations.

Corporate Segment

The corporate segment consists primarily of costs for our corporate and business development expenses.  In addition, the corporate segment contains our captive insurance company.  

We have elected to retain some of the risks associated with operating our company through a wholly owned, consolidated insurance subsidiary, Westmoreland Risk Management Ltd., or WRM.  WRM, a Bermuda corporation, provides our primary layer of property and casualty insurance.  By using this insurance subsidiary, we have reduced the cost of our property and casualty insurance premiums and retained some economic benefits due to our excellent loss record.  We reduce our major exposure by insuring for losses in excess of our retained limits with a number of third-party insurance companies.

Except for the assets of WRM, 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, 2009.

Available Information

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission.  You may access and read our filings without charge through the SEC’s website, at www.sec.gov.  You may also read and copy any document we file at the SEC’s Public Reference Room located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549.  Please call the SEC at 1-800-SEC-0330 for further information on the Public Reference Room.

We also make our public reports available through our website, www.westmoreland.com, as soon as practicable after we file or furnish them with the SEC.  You may also request copies of the documents, at no cost, by telephone at (719) 442-2600 or by mail at Westmoreland Coal Company, 2 North Cascade Avenue, 2nd Floor, Colorado Springs, Colorado, 80903.  The information on our website is not part of this Annual Report on Form 10-K.

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ITEM 1A—RISK FACTORS.

This report, including Management’s Discussion and Analysis of Financial Condition and Results of Operation, contains forward-looking statements that may be materially affected by numerous risk factors, including those summarized below.

Risk Factors Relating to our Operations

We may not generate sufficient cash flow to pay our operating expenses, meet our debt service costs and pay our heritage and corporate costs, and we may not be able to obtain additional sources of liquidity to meet these needs.

We are a holding company that conducts our operations through our subsidiaries.  Certain costs that we incur are direct obligations of ours such as significant heritage health benefit costs, and we rely on dividends from our subsidiaries to meet these holding company obligations.  Our Westmoreland Mining LLC subsidiary, which owns the Rosebud, Jewett, Beulah and Savage Mines, and our Westmoreland Partners subsidiary, which owns ROVA, are subject to credit facilities that require the maintenance of reserve accounts and limit the ability of those subsidiaries to dividend funds to us based on changes in reserve account balances and the subsidiaries’ operating results.  Accordingly, these subsidiaries may not be able to pay dividends to us in the amounts and in the time required for us to pay our heritage health benefit costs and corporate expenses.  Ultimately, if our subsidiaries’ operating cash flows are insufficient to support their operations and provide dividends to us in the amounts and time required to pay our expenses, and we are unable to obtain external financing at sufficient levels to pay such obligations, we will be unable to meet our obligations as they come due.

As a result of Westmoreland Resources Inc., or WRI, which owns the Absaloka Mine, renewed revolving line of credit and an increase in its term debt, anticipated reductions in our heritage medical obligations and the conclusion of customer shutdowns, we anticipate that our cash from operations and available borrowing capacity will be sufficient to meet our working capital and bonding requirements, planned capital expenditures and debt payments for the foreseeable future, although by a small margin.  However, our expectations in this regard are subject to numerous risks and uncertainties, and may not be realized.  Because of the uncertainties surrounding the 2010 forecast assumptions and anticipated non-compliance with certain debt covenants, the report from our independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2009, includes an explanatory paragraph that summarizes the salient facts or conditions that raise substantial doubt about our ability to continue as a going concern.

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, 2009, our total gross indebtedness, excluding debt discounts, was approximately $259.9 million, the principal components of which are: $148.8 million of Westmoreland Mining LLC term and other debt; $55.6 million of ROVA term debt; $38.3 million under WRI’s revolving line of credit and term and other debt; and $17.2 million of convertible notes.  We may incur additional indebtedness in the future, including indebtedness under our three existing revolving credit facilities.

A substantial portion of our subsidiaries’ cash flows must be used to pay principal and interest on our indebtedness and is not available to fund working capital, capital expenditures, bonding requirements, heritage costs 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 equipment leases or other general corporate requirements; limiting our ability to grow our business; and limiting our flexibility in planning for, or reacting to, changes in our business and in the industry.

If our operating performance fails to improve as anticipated, or if we do not have sufficient cash flows and capital resources to meet our debt service obligations, we may be forced to seek additional capital or seek to restructure or refinance our indebtedness.  If we are unable to obtain new or restructured financing, we could be forced to sell our assets or those of our subsidiaries under unfavorable circumstances to make up for any shortfall in our payment obligations.  Our existing credit facilities limit our ability to sell assets and restrict the use of the proceeds from any such sale.  Therefore, even if forced to do so, we may not be able to sell assets quickly enough or for sufficient amounts to enable us to meet our debt obligations.  In addition, our liquidity could be adversely affected if one or more lenders under our subsidiaries’ revolving credit agreements become unwilling or unable to fund amounts under those facilities when requested.

If we fail to comply with certain covenants in our various debt arrangements, it could negatively affect our liquidity and ability to finance our operations.

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Our lending arrangements contain, among other conditions, events of default and various affirmative and negative covenants.  In 2009, WML did not comply with a leverage ratio covenant in its debt agreement and obtained a waiver from its lenders for defaults through March 31, 2010, subject to certain conditions.  At September 30, 2009, WRI was unable to comply with its net worth covenant contained in its business loan agreement.  WRI obtained a waiver from its lenders for the quarter ended September 30, 2009.  The agreement was subsequently amended to extend the net worth requirement from September 30, 2009 to April 30, 2010.  We currently anticipate that we will not be able to meet the WRI net worth covenant requirement by April 30, 2010.  Should we not meet the conditions of the waivers, the lenders may require the payment of additional fees, require prepayment of a portion of  indebtedness to them, accelerate the amortization schedule for the indebtedness and or increase the interest rates they charge on our outstanding indebtedness. Should we be unable to meet future debt-related covenants, we will be required to seek a waiver of such covenant to avoid an event of default.  Covenant waivers and modifications may be expensive to obtain, or, potentially, unavailable.  If we are unable to obtain covenant waivers and our lenders accelerate our debt, we could attempt to refinance or repay the debt with the proceeds from sales of assets. Sales of assets undertaken in response to such immediate needs may be made at potentially unfavorable prices, or asset sales may not be sufficient to refinance or repay the debt, and we may be unable to complete such transactions in a timely manner, on favorable terms, or at all.

Continuing unfavorable economic conditions could have a material adverse effect on our results of operations.

Economic conditions in the United States and throughout much of the world experienced a sudden, sharp economic downturn in 2008 and 2009.  While the markets have shown improvements in recent months, continuing turmoil in the financial markets could make it more difficult for us to access capital, sell assets, refinance our existing indebtedness, obtain waivers for covenant violations from our lenders if necessary, obtain future bonding capacity required to expand our operations, enter into agreements for new indebtedness, or obtain funding through the issuance of our securities.

Our dependence on a small group of customers could adversely affect our revenues if such customers reduce or suspend their coal purchases or if they become unable to pay for our coal.

In 2009, approximately 60% of our total revenues were derived from coal sales to four power plants:   Limestone Generating Station (19% of our 2009 revenues), Colstrip Units 3&4 (18%), Colstrip Units 1&2 (12%) and Sherburne County Station (11%).  Interruption in the purchases of coal by our operations of our principal customers could significantly affect our revenues.  During 2009, unscheduled power plant outages occurred after planned maintenance outages at power plants served by our Rosebud and Beulah Mines resulting in lost revenues of approximately $47.5 million.  Unscheduled maintenance outages at our customers' power plants, unseasonably moderate weather, or increases in the production of alternative clean-energy generation such as wind power could cause our customers to reduce their purchases.  In addition, new environmental regulations could compel our customer of the Jewett Mine to purchase more compliance coal, reducing or eliminating our sales to them.  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.  The reduction in the sale of our coal would adversely affect our operating results.  In addition, if any of our major customers became unable to pay for contracted amounts of coal, our results of operation and liquidity would be adversely affected.

If our assumptions regarding our future expenses related to employee benefit plans are incorrect, then expenditures for these benefits could be materially different than we have assumed.

We provide various postretirement medical benefits, black lung and worker’s compensation benefits to current and former employees and their dependents.  We calculate the total accumulated benefit obligations according to the guidance provided by Generally Accepted Accounting Principles, or GAAP.  We estimate the present value of our postretirement medical, black lung and worker’s compensation benefit obligations to be $190.2 million, $14.7 million and $11.2 million, respectively, at December 31, 2009.  We have estimated these unfunded obligations based on actuarial assumptions described in the notes to our consolidated financial statements.  If our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially different. 

Inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves.  Our reserve estimates are prepared by our engineers and geologists and are updated periodically.  There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control, including the following:

·

quality of the coal;

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·

geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;

·

the percentage of coal ultimately recoverable;

·

the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;

·

assumptions concerning the timing for the development of the reserves; and

·

assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.

As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties may vary materially due to changes in the above factors and assumptions.  Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues and/or higher than expected costs.

If the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, we could be required to expend greater amounts than anticipated.

The Surface Mining Control and Reclamation Act of 1977, or SMCRA, establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining.  We calculated the total estimated reclamation and mine-closing liabilities according to the guidance provided by GAAP and current industry practice.  Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements.  If our estimates are incorrect, we could be required in future periods to spend more or less on reclamation and mine-closing activities than we currently estimate.  Likewise, if our customers, some of whom are contractually obligated to pay certain reclamation costs, 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.

We estimate that our gross reclamation and mine-closing liabilities, which are based upon projected mine lives, current mine plans, permit requirements and our experience, were $244.6 million (on a present value basis) at December 31, 2009.  Of these December 31, 2009 liabilities, our customers have assumed $82.2 million by contract.  In addition, we held final reclamation deposits, received from customers, of approximately $73.1 million at December 31, 2009 to provide for these obligations.  We estimate that our obligation for final reclamation that was not the contractual responsibility of others or covered by offsetting reclamation deposits was $89.3 million at December 31, 2009.  This $89.3 million must be recovered in the price of coal sold.  Responsibility for the final reclamation amounts may change in certain circumstances.

In addition, we are currently in a dispute with our coal buyers that own the Colstrip Units 3&4 at Rosebud regarding reclamation costs.  The buyers assert that they were charged for base reclamation work in Area C of the Rosebud Mine when those charges were actually for final reclamation, which would be our responsibility under the terms of the coal supply agreement.  The refund of $21.0 million sought by the buyers includes $17.0 million in alleged overpayments for final reclamation work plus $4.0 million in interest.  If the buyers prevail and all of the challenged work is determined to be final reclamation rather than base reclamation, we could be required to refund in cash the overpayment with interest, which would materially affect our ability to use cash to obtain bonding for future mining, restrict cash dividends from the mine to the holding company and could cause a potential breach of a Westmoreland Mining loan covenant.

After discussions with the Colstrip Unit 3&4 buyers in the fourth quarter of 2009 and first quarter of 2010, we have determined that a settlement agreement would be reached.  As a result, we recorded $6.5 million to Other current liabilities and reduced Revenues by the same amount for this claim.  In addition, Cost of sales was reduced by $1.7 million and a corresponding $1.7 million recorded in Other current assets for prepaid production taxes and royalties.

If the cost of obtaining new reclamation bonds and renewing existing reclamation bonds continues to increase or if we are unable to obtain additional bonding capacity, our operating results could be negatively affected.

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 increasing portions of their obligations to the bonding company.  In 2009, we paid approximately $4.1 million in premiums for reclamation bonds and were required to use $3.2 million in cash to collateralize 21% of the face amount of the new bonds obtained in 2009.  We anticipate that, as we permit additional areas for our mines in 2010 and 2011, our bonding requirements will increase significantly and our collateral requirements will increase as well.  Any capital that we provide to collateralize our obligations to our bonding

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companies is not available to support our other business activities.  If the cost of our reclamation bonds continues to increase, our results of operations could be negatively affected.  Additionally, if we are unable to obtain additional bonding capacity due to cash flow constraints, we will be unable to begin mining operations in newly permitted areas.  Our inability to begin operations in new areas will hamper our ability to efficiently meet our current customer contract deliveries, expand operations, and increase revenues.

Our coal mining operations are subject to external conditions that could disrupt operations and negatively affect 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.  These conditions or events include: unplanned equipment failures, which could interrupt production and require us to expend significant sums to repair our equipment, which is integral to the mining of coal; 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.  For example, in our recent past, we have endured: a major blizzard at the Beulah Mine, which interrupted operations; a fire on the trestle at the Beulah Mine that interrupted rail shipment of our coal; and an unanticipated replacement of boom suspension ropes on one of our draglines that caused a multi-week interruption of mining.  Major disruptions in operations at any of our mines over a lengthy period could adversely affect the profitability of our mines.

Should our Private Letter Ruling pertaining to our Indian Coal Tax Credit, or ICTC, be audited by the IRS, the transaction may be cancelled and we may be required to return payments received from the third party.

Our mining subsidiary at our Absaloka Mine entered into a series of transactions, including the formation of a limited liability company with an unaffiliated investor, in order to take advantage of certain available tax credits for the production of coal on Indian lands.  We requested and have received a private letter ruling, or PLR, from the IRS providing that the ICTCs will be available under the specific scenario described in the PLR.  Even though we have received the PLR, there are certain issues that may be raised by the IRS in a subsequent audit of tax returns of the members of the limited liability company.  In the unlikely event that a subsequent audit disqualifies the tax credits as approved in the PLR or disallows the allocations of the tax credits, we could be required to either return to the investor previously received payments under the notes, and the transaction would effectively be cancelled or retain the previously received payments under the notes, but the transaction would effectively be cancelled from the date of the disallowance.  We will pay to the Crow Tribe 33% of the expected ICTC payments we will receive from the investor.  The Crow Tribe is only required to reimburse us under very limited circumstances.  As a result, in the unlikely event that the IRS disallows or disqualifies the tax credit, we would be unable to recoup payments already paid to the Crow Tribe.

Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable and to raise the capital necessary to fund our expansion.

Our recoverable reserves will decline as we produce coal.  We have not yet applied for the permits required or developed the mines necessary to use all of the coal deposits under our mineral rights. Furthermore, we may not be able to mine all of our coal deposits as efficiently as we do at our current operations.  Our future success depends upon our conducting successful exploration and development activities and acquiring properties containing economically recoverable coal deposits.  In addition, we must also generate enough capital, either through our operations or through outside financing, to mine these additional reserves and to acquire new reserves.  Our current strategy includes increasing our coal reserves through acquisitions of other mineral rights, leases, or producing properties and continuing to use our existing properties.  Our ability to further expand our operations may be dependent on our ability to obtain sufficient working capital, either through cash flows generated from operations, or financing activities, or both.  As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines.  These factors could have a material adverse affect on our mining operations and costs, and our customers’ ability to use the coal we mine.

Union represented labor creates an increased risk of work stoppages and higher labor costs.

At December 31, 2009, approximately 51% of our total workforce was represented by either the International Union of Operating Engineers Local 400 or the United Mine Workers of America.  Our unionized workforce is spread out amongst four of our surface mines. As a majority of our workforce is unionized, there may be an increased risk of strikes and other labor disputes, as well as higher labor costs.  In March 2009, during negotiation over a collective bargaining agreement, our employees at the Rosebud Mine imposed a sixteen-day work stoppage. On April 6, 2009, we entered into a new four-year agreement with the union, and the Rosebud Mine resumed full operation. The impact on our operations was minimal as we continued to make most of our scheduled coal deliveries. If our Jewett Mine operations were to become unionized, we could be subject to additional risk of work stoppages, other labor disputes and higher labor costs, which could adversely affect the stability of production and our results of operations.

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Legislation has been proposed to Congress to enact a law allowing workers to choose union representation solely by signing election cards (“Card Check”), which would eliminate the use of secret ballots to elect union representation.  While the impact is uncertain, if Card Check legislation is enacted into law, it will be administratively easier for unions to unionize coal mines and may lead to more coal mines becoming unionized.

Our revenues could be affected by unscheduled outages at ROVA or if the scheduled maintenance outages at ROVA last longer than anticipated.

Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time-to-time and are an inherent risk of our business.  Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer megawatt hours.  While we maintain insurance, the proceeds of such insurance may not be adequate to cover our lost revenues, increased expenses or liquidated damages payments should we experience equipment breakdown.  As our facilities were brought online in the mid 1990s, they require periodic upgrading and improvement.  Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could result in reduced profitability.  In September 2009, we were forced to keep the larger ROVA plant offline for a significant period of time following a scheduled major turbine outage due to unanticipated mechanical issues that arose.  In 2010, we have a major scheduled turbine outage for our smaller ROVA plant, which could result in unscheduled maintenance issues.

The profitability of ROVA could be severely affected beginning in 2014 due to differences in the termination dates of our coal supply agreements and power purchase agreements.

We entered into a ROVA Coal Supply Agreement for our larger plant on June 21, 1993, and a ROVA Coal Supply Agreement for our smaller plant on December 1, 1993, which provide for ROVA’s coal needs for a twenty-year period, terminating on May 29, 2014 and June 1, 2015, respectively.  We also entered into power purchase agreements with Dominion Virginia Power that provide for the sale of power for a twenty-five year term through May 29, 2019, for our larger ROVA plant and June 1, 2020, for the smaller ROVA plant.  The coal supply agreements provide for coal at a price per ton that is less than today’s open market price for Central Appalachia coal.  Upon the termination of the coal supply agreements beginning in 2014, we will be required to renegotiate our current contract or find a substitute supply of coal, likely at a cost per ton far greater than the price we are paying today.  However, the power purchase agreements do not provide for a price increase related to an increase in the cost per ton of delivered coal and Dominion Virginia Power’s payment for power after 2014 will not escalate with our increased coal costs.  Due to the change in the economics of ROVA at such time, it is projected that ROVA will begin incurring losses in 2014 and may be unable to pay its debt and other obligations as they become due.  Should ROVA renegotiate its future coal supply contracts prior to 2014 in a manner that results in higher coal prices, the incurrence of losses and an inability to pay obligations could be accelerated.

Permitting issues in Central Appalachia could put ROVA’s coal supply at risk.

ROVA purchases coal under long-term contracts from coal suppliers with identified reserves located in Central Appalachia.  While our coal supply has been relatively stable since the inception of the contracts, potential permitting issues pertaining to the reserves identified as our source of coal in our coal contracts could prove problematic in the coming years.  Should regulatory/legal action prevent our coal supplier from continuing to mine the reserves identified as our source of coal or to mine other reserves that could be identified as potential sources of coal, we could be forced to find an alternative source of coal at higher prices.  While the cost of cover for substitute coal should be covered by our coal contracts, we would be forced to initially incur the higher costs to secure a coal supply to provide for the continued operations at ROVA.  In addition, should issues arise under our coal contracts relating to the cost of cover, the coal suppliers’ guarantee or any other issue, we could be forced to incur significant legal expenses and, potentially, may never recoup our incremental coal or related legal costs.

Risk Factors Relating to the Coal and Power Industries

The recent downturn in the domestic and international financial markets, and the risk of prolonged global recessionary conditions, could adversely affect our financial condition and results of operations.

Because we sell substantially all of our coal to electric utilities, our business and results of operations remain closely linked to demand for electricity.  The recent downturn in the domestic and international financial markets has created economic uncertainty and raised the risk of prolonged global recessionary conditions.  Historically, global demand for basic inputs, including electricity production, has decreased during periods of economic downturn.  If the recent downturn in the domestic and international financial markets decreases global demand for electricity production, our financial condition and results of operations could be adversely affected.

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Increased consolidation and competition in the U.S. coal industry may adversely affect our revenues and profitability.

During the last several years, the U.S. coal industry has experienced increased consolidation.  Consequently, many of our competitors in the domestic coal industry are major coal producers who have significantly greater financial resources than we do.  The intense competition among coal producers may impact our ability to retain or attract customers and may therefore adversely affect our future revenues and profitability.

Any change in consumption patterns by utilities away from the use of coal could affect our ability to sell the coal we produce or the prices that we receive.

Some power plants are fueled by natural gas because of the relatively cheaper construction costs of such plants compared to coal-fired plants and because natural gas is a cleaner burning fuel.  The domestic electric utility industry accounts for approximately 90% of domestic coal consumption.  The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as alternative sources of energy.  A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could negatively impact our results of operations and reduce our cash available for distribution.

Extensive government regulations impose significant costs on our mining operations, and future regulations could increase those costs or limit our ability to produce and sell coal.

The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to matters such as:

·

limitations on land use;

·

employee health and safety;

·

mandated benefits for retired coal miners;

·

mine permitting and licensing requirements;

·

reclamation and restoration of mining properties after mining is completed;

·

air quality standards;

·

water pollution;

·

construction and permitting of facilities required for mining operations, including valley fills and other structures, including those constructed in water bodies and wetlands;

·

protection of human health, plant life and wildlife;

·

discharge of materials into the environment; and

·

effects of mining on groundwater quality and availability.

The costs, liabilities and requirements associated with these and other regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production operations.  Failure to comply with these regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations.  We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations.  We must compensate employees for work-related injuries.  If we do not make adequate provision for our workers’ compensation liabilities, it could harm our future operating results.  If we are pursued for these sanctions, costs and liabilities, our mining operations and, as a result, our profitability could be adversely affected.

The possibility exists that new legislation and/or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal.  New legislation or administrative regulations (or new judicial interpretations or administrative enforcement of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs.  These regulations, if proposed and enacted in the future, could have a material adverse effect on our financial condition and results of operations.

Extensive environmental laws and regulations affect the end-users of coal and could reduce the demand for coal as a fuel source and cause the volume of our sales to decline.  These laws and regulations could also impose costs on ROVA that it would be unable to pass through to its customer.

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Coal contains impurities, including but not limited to sulfur, mercury, chlorine, carbon and other elements or compounds, many of which are released into the air when coal is burned.  The emission of these and other substances is regulated extensively regulated at the federal, state and local level, and these regulations significantly affect our customers’ ability to use the coal we produce and, therefore, the demand for that coal.  For example, the purchaser of coal produced from the Jewett Mine blends our lignite with compliance coal from Wyoming.  Tightened nitrogen oxide and new mercury emission standards could result in the customer purchasing an increased blend of the Wyoming coal in order to reduce emissions.  Further, increased market prices for sulfur dioxide emissions and increased coal ash costs could also favor an increased blend of the lower ash Wyoming compliance coal.  In such a case, the customer has the option to increase its purchases of other coal and reduce purchases of our coal or terminate our contract.  A termination of the contract or a significant reduction in the amount of our coal that is purchased by the customer could have a material adverse effect on our results of operation and financial condition.

In addition, greenhouse gas, or GHG, emissions have increasingly become the subject of a large amount of international, national, state and local attention.  Coal-fired power plants can generate large amounts of carbon emissions.  Accordingly, our coal and power operations will likely be affected by legislation or regulation intended to limit GHGs.  For example, the EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress is considering “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs.  In addition, coal-fired power plants have become subject to challenge, including the opposition to any new coal-fired power plants or capacity expansions of existing plants, by environmental groups seeking to curb the environmental effects of emissions of GHGs. 

These developments could have a variety of adverse effect on demand for the coal we produce.  For example, state or federal laws or regulations regarding GHGs could result in fuel switching from coal to other fuel sources by electricity generators, or require us or our customers to employ expensive technology to capture and sequester carbon dioxide.  Political opposition to the development of new coal-fired power plants, or regulatory uncertainty regarding future emissions controls, may result in fewer such plants being built, which would limit our ability to grow in the future.

With respect to ROVA, it may be unable to pass costs associated with GHG-related regulation on to Dominion Virginia Power under its power purchase agreement even though any imposed carbon tax would be passed through to ROVA from its coal suppliers under the terms of the applicable coal supply agreements.  Any legislation or regulation that has the effect of imposing costs on ROVA it is unable to pass through to Dominion Virginia Power would adversely affect our earnings and liquidity.

Risk Factors Relating to our Equity

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

Provisions in our certificate of incorporation, 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 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 and further amended in May 2007 and March 2008.  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.

Future sales of our common stock by our major stockholder may depress our share price and influence our management policies.

Mr. Jeffrey L. Gendell, directly and through various entities, beneficially owns approximately 27% of our common stock.  We have granted Mr. Gendell and its various affiliated entities registration rights with respect to our common stock it holds, which we registered on a selling stockholder registration statement in May 2009.  Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline.  In addition, if Mr. Gendell or his various affiliated entities were to sell their entire holdings to one person, that person could have significant influence over our management policies.

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ITEM 1B—UNRESOLVED STAFF COMMENTS.

None

ITEM 2—PROPERTIES.

See “Coal Segment-Properties” and “Power Segment-Properties” under Item 1 for information relating to our properties and reserves.

ITEM 3—LEGAL PROCEEDINGS.

From time-to-time, we are involved in legal proceedings arising in the ordinary course of business.  While the following discussion highlights our significant legal proceedings, we believe we have recorded adequate reserves for these liabilities and that there is no individual case pending that is likely to have a material adverse effect on our financial condition, results of operations or cash flows.

Customer Reclamation Claims

Western Energy Company, or WECO, received a claim dated October 16, 2008, from the six Colstrip Unit 3&4 buyers seeking a refund of approximately $9.9 million for alleged inappropriate charges.  In subsequent claim revisions, the customers increased the refund claim to $21.0 million.  The buyers assert that they were charged for base reclamation work in Area C of the Rosebud Mine when those charges were actually for final reclamation, which would be WECO’s responsibility under the terms of the coal supply agreement.  The refund sought by the buyers includes alleged overpayments for final reclamation work plus taxes, royalties and interest on that overpayment.

WECO believes that these charges to the buyers were proper because the challenged work was for base reclamation, which is the buyers’ responsibility under the coal supply agreement.  If the buyers prevail and all of the challenged work is determined to be final reclamation rather than base reclamation, WECO’s financial responsibility will be reduced by two factors.  First, a portion of any refund includes taxes and royalties that WECO should be able to offset against future taxes and royalties.  Second, one of the six buyers, Puget Sound Energy, Inc., has funded an account that WECO is authorized to use to pay approximately 17% of all final reclamation costs in Area C.

After discussions with the Colstrip Unit 3&4 buyers in the fourth quarter of 2009 and first quarter of 2010, we determined that a settlement agreement would likely be reached.  As a result, we recorded a reduction in Revenues by $6.5 million and an offsetting $1.7 million reduction in Cost of sales for this claim.

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ITEM 5—MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Market Information

Our common stock is listed and traded on the NYSE AMEX under the symbol WLB.  As of March 1, 2010, there were 1,253 holders of record of our common stock.

The following table shows the range of sales prices for our common stock for the past two years, as reported by the American Stock Exchange through December 1, 2008 and by the NYSE AMEX from December 2, 2008, through the end of 2008 and 2009.

Dividend Policy

We issued Depositary Shares, each representing one quarter of a share of our Series A Convertible Exchangeable Preferred Stock, on July 19, 1992.  The quarterly dividends, which are accumulated through and including January 1, 2010, amount to $18.6 million in the aggregate ($116.03 per preferred share or $29.01 per Depositary Share).

There are statutory and contractual restrictions limiting the payment of preferred stock dividends under Delaware law, the state where we are incorporated.  Under Delaware law, we are permitted to pay dividends only to the extent that our shareholders’ equity exceeds the par value of our preferred stock ($160,129 at December 31, 2009).  As we are currently reporting a deficit in our shareholders’ equity, we are currently prohibited from paying preferred stock dividends and we suspended dividend payments on the Depositary Shares in July 2006.  In addition, we issued notes in March 2008, which prohibit the payment of the preferred dividends so long as the notes are outstanding.  We are prohibited from paying dividends on our common stock until we pay the accumulated preferred dividend in full.

Stock Performance Graph

This performance graph compares the cumulative total stockholder return on our Common stock for the five-year period December 31, 2004, through December 31, 2009, with the cumulative total return over the same period of the AMEX Market Index and a peer group index, which consists of Alliance Resource Partners, L.P., Alpha Natural Resources, James River Coal Company, Massey Energy Company and Patriot Coal Corporation.  The graph assumes that:

·

You invested $100 in Westmoreland Coal common stock and in each index at the closing price on December 31, 2004;

·

All dividends were reinvested;

·

Annual reweighting of the peer groups; and

·

You continued to hold your investment through December 31, 2009.

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You are cautioned against drawing any conclusions from the data contained in this graph, as past results are not necessarily indicative of future performance.  The indices used are included for comparative purposes only and do not indicate an opinion of management that such indices are necessarily an appropriate measure of the relative performance of our common stock.

(1)

We developed a new peer group to better reflect comparable sized companies in our industry.

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ITEM 6—SELECTED FINANCIAL DATA.

Westmoreland Coal Company and Subsidiaries

Five-Year Review

(1)

Effective June 29, 2006, we acquired a 50% interest in a partnership, which owns the 230-megawatt ROVA power plants from a subsidiary of E.ON U.S. LLC.  The acquisition increased our ownership interest in the partnership to 100%.

(2)

Includes a non-cash tax benefit of $17.1 million and $9.1 million in 2009 and 2007, respectively.

(3)

Effective December 31, 2006, we recorded an increase in stockholders’ deficit of $129.8 million to reflect on our balance sheet the underfunded status of our pension and postretirement medical benefit plans.

No cash dividends were declared on common shares for the five years ended December 31, 2009.

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

The following discussion and analysis contains forward-looking statements and estimates that involve risks and uncertainties. Actual results could differ materially from these estimates. Factors that could cause or contribute to differences from estimates include those discussed under “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” contained in Item 1 above.

Overview

Westmoreland Coal Company is an energy company employing 1,109 employees whose operations include five surface coal mines in Montana, North Dakota and Texas and two coal-fired power-generating units with a total capacity of 230 megawatts in North Carolina.  We sold 24.3 million tons of coal in 2009. Our two principal operating segments are our coal segment and our power segment, in addition to two non-operating segments.

We are a holding company and conduct our operations through subsidiaries, which generally have obtained separate financing.  As a holding company, we have significant cash requirements to fund our ongoing heritage health benefit costs, pension contributions, and corporate overhead expenses.  The principal sources of cash flow to us are distributions from our principal operating subsidiaries.  Each of WML, ROVA and WRI has a credit agreement that contains covenants applicable to that subsidiary.  Only the WRI agreement permits dividends to be paid by WRI to us without restriction.

During 2009, our Rosebud and Beulah Mines customers had unscheduled outages following their planned maintenance outages.  The Beulah Mine customer ended its unscheduled outage and resumed coal deliveries in July 2009.  However, deliveries to our Rosebud Mine’s customer were significantly reduced until October 2009 when the customers acquired needed replacement equipment and they resumed operations.  The power plant outages at Beulah and Rosebud Mines customers are referred to herein as “the customer outages.”  Additionally, due to unfavorable current economic and energy market conditions, our Absaloka and Jewett Mine’s deliveries decreased.  These reductions reduced the dividends and cash flows available to us.

In October 2009, during a planned major maintenance outage at one of our ROVA power plants, which occurs every five years, we determined that an unexpected repair was needed on the generator rotor.  This repair extended the outage and decreased revenues and operating income in the fourth quarter of 2009.  The repair was made and operations resumed in November 2009.

In December 2009, we entered into an agreement with the United Mine Workers of America to modernize the method by which prescription drugs are provided to retirees of our former operations. Under the agreement, we will utilize a new system of distribution and administration, along with drug formularies, to enable us to continue to provide prescription drug benefits to retirees, but at a lower cost. These modifications are expected to become effective around April 15, 2010.  Additionally in 2009, we eliminated postretirement medical benefits for non-represented employees and retirees effective September 1, 2009 and transitioned our retiree population to a new health provider network.  The collective effect of these changes coupled with favorable claims experience, favorable interest rates, and reductions in administrative fees, has resulted in a $95.3 million reduction in our postretirement medical obligation with a corresponding decrease in Accumulated other comprehensive loss.

We froze our pension plan for non-represented employees effective July 1, 2009 and, as a result, future benefits will no longer accrue under this plan.  Related to the plan freeze, we recorded a curtailment loss of $0.2 million and a $10.7 million decrease in our pension liability with a corresponding decrease in Accumulated other comprehensive loss.

We have suffered recurring losses from operations, have a working capital deficit, a net capital deficiency, and expect to violate certain debt covenants in 2010.  These factors raise substantial doubt about our ability to continue as a going concern.  The accompanying consolidated financial statements are prepared on a going concern basis and do not include any adjustments that might result from uncertainty about our ability to continue as a going concern.  The report from our independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2009 includes an explanatory paragraph that summarizes the salient facts or conditions that raise substantial doubt about our ability to continue as a going concern.  

As a result of WRI’s renewed revolving line of credit and increase in its term debt discussed below and the factors discussed in “Significant Anticipated Variances Between 2009 and 2010 and Related Uncertainties”, we anticipate that our cash from operations and available borrowing capacity will be sufficient to meet our cash requirements for the foreseeable future thereafter, although by a small margin.  We do not currently expect to rely on proceeds from sales of assets or securities or other capital-raising transactions in order to satisfy our liquidity needs in 2010.

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Results of Operations

Items that Affect Comparability of Our Results

For 2009 and each of the prior two years, our results have included items that do not relate directly to ongoing operations.  The income (expense) components of these items were as follows:

Items recorded in 2009

-

We recorded an income tax benefit of $17.1 million related to a tax effect of other comprehensive income gains (see Note 15 to our consolidated financial statements).

-

We recorded income of $6.1 million resulting from the mark-to-market accounting of the conversion feature in our convertible notes and a decrease in the value of our warrant offset with $1.0 million of interest expense of a related debt discount (see Note 10 to our consolidated financial statements).

-

We recorded a gain of $0.8 million related to a settlement of past heritage claims, as a result of efforts to reduce our heritage costs (see Note 8 to our consolidated financial statements).

-

We recorded $4.8 million in net expense related to the anticipated settlement of the reclamation claim at our Rosebud Mine.  This included a $6.5 million reduction in revenue, offset with a $1.7 million reduction in cost of sales (see Note 17 to our consolidated financial statements).

Items recorded in 2008

-

We recorded $8.1 million of expense related to the beneficial conversion feature in the convertible notes we issued in March 2008, as the conversion price was lower than the fair market value of our common stock at the time of issuance.

-

We refinanced both our WML and ROVA debt during 2008 and as a result recorded losses of $3.8 million and $1.3 million, respectively, for the extinguishment of debt.

-

We recorded $2.6 million in net expense related to two coal royalty claims as we reached an agreement with the U.S. Minerals Management Service and the Montana Department of Revenue to settle two long-standing disputes.  This included $12.8 million of cost of sales, offset with $10.2 million of revenue.

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-

On July 2, 2008, we received $0.9 million for our royalty interest in the gas-fired Ft. Lupton project and recognized a gain of $0.9 million on the sale.

-

In 2007, we initiated a restructuring plan in order to reduce the overall cost structure of the Company.  As a result, in 2008 and 2007 we recorded restructuring charges of $2.0 million and $4.5 million, respectively.  Most of the restructuring charges related to termination benefits, outplacement costs, and lease costs related to the consolidation of corporate office space.

Items recorded in 2007

-

We recorded an income tax benefit of $9.1 million related to a tax effect of other comprehensive income gains.

-

During 2007, we reached a settlement with the Combined Benefit Fund, or CBF, for the reimbursement of $5.8 million, plus interest, in past overpayments to the CBF for retiree medical benefits. We recorded the settlement as a $5.8 million reduction in heritage health benefit expenses and $0.6 million in interest income.

-

In 2007, we sold a royalty interest in a Wyoming mine for $12.7 million. The sale of the royalty interest resulted in a gain of approximately $5.6 million.

-

In 2007, we sold our power operation and maintenance business to North American Energy Services, or NAES, for $0.8 million. The sale of the power operation and maintenance business resulted in a gain of $0.5 million during 2007.

-

In 2007, WRI reached an agreement to settle its contract disputes with Washington Group International, Inc., or WGI, who had been the contract operator and 20% owner of the mine.  As part of the settlement agreement, WRI assumed operation of the Absaloka Mine and recorded a contract termination fee of $0.8 million related to the buyout of the WGI operating contract.  Later in 2007, we purchased WGI’s 20% interest to become the sole owner of WRI.

-

Pursuant to our Jewett Mine’s new coal sale agreement with its customer entered into in 2007, we developed a new mine plan.  As a result of the new mine plan, we wrote off $1.1 million of inventory associated with equipment which is not utilized under the new mine plan.

2009 Compared to 2008

Summary

Our revenues for 2009 decreased to $443.4 million compared with $509.7 million in 2008.  This decrease was primarily driven by a $58.6 million decrease in our coal segment revenues, which includes approximately $41.9 million as a result of reduced tonnages sold due to the customer outages and unfavorable current energy market conditions, approximately $6.5 million of revenue reversed related to a reclamation claim,  and approximately $10.2 million of 2008 revenue recognized related to the settlement of coal royalty claims.  In addition, our power segment revenues decreased $7.7 million related to a decrease in megawatt hours sold.

Our net loss applicable to common shareholders for 2009 decreased to $28.7 million compared with a $49.9 million loss in 2008.  Excluding $18.1 million of income in 2009 and the $17.1 million of expenses in 2008 discussed in Items that Affect Comparability of Our Results, our net loss increased by $13.9 million.  The primary factors, in aggregate, driving this increase in net loss were:

-

A $12.7 million decrease in our coal segment operating income.  This decrease was primarily driven by reduced tonnages sold due to the customer outages and unfavorable current energy market conditions, and was partially offset by income from our Indian Coal Tax Credit monetization transaction.  In addition, our coal segment operating income includes losses from a partially owned consolidated subsidiary;

-

A $8.3 million decrease in our power segment operating income resulting primarily from reduced megawatt hours sold and increased maintenance expenses as a result of a planned major maintenance outage and a significant unplanned outage, which occurred in the fourth quarter of 2009;

-

A $2.9 million decrease in heritage costs primarily driven by the elimination of postretirement medical benefits for our non-represented employees’ costs during the third quarter of 2009 and reduced workers compensation expenses due to changes in interest rates and favorable claims experience.  These decreases were partially offset with an increase in cost containment efforts and unfavorable changes in the valuation of our Black Lung benefit’s trust assets and liabilities due to changes in interest rates;

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-

A $2.7 million decrease in our corporate expenses related to cost control efforts and a reduction in our stock compensation expense;

-

A $1.9 million decrease in interest income, which was partially offset with a $0.4 million decrease in interest expense as a result of debt refinancing and a $0.2 million increase in other income;

-

A $1.8 million favorable noncontrolling interest adjustment driven by losses from a partially owned consolidated subsidiary; and

-

A $1.0 million decrease in income taxes driven primarily by lower state taxable income due to the customer outages.

Coal Segment

The following table shows comparative coal revenues, operating income and sales volume, and percentage changes between periods:

Our coal revenues for 2009 decreased to $361.2 million, compared with $419.8 million in 2008.  This decrease occurred primarily from a decrease of 5.0 million tons sold as a result of the customer outages, the reclamation claim recorded in 2009 and settlement of coal royalty claims recorded in 2008.  Additionally, due to unfavorable current economic and energy market conditions, our Absaloka and Jewett Mine’s deliveries decreased in 2009.

Our coal segment’s operating income decreased to $0.5 million in 2009, compared to $15.2 million in 2008.  Excluding the $4.8 million related to the anticipated settlement of the reclamation claim, the $2.6 million coal royalty dispute settlement and $0.2 million of restructuring charges discussed in Items that Affect Comparability of Our Results, our coal segment operating income decreased by $12.7 million.  Of this decrease, approximately $20.3 million was due to reduced tonnages sold as a result of the customer outages and unfavorable current economic and energy market conditions.  This decrease was partially offset with approximately $7.6 million of earnings recognized from our Indian Coal Tax Credit monetization transaction.

Power Segment

The following table shows comparative power revenues, operating income and production and percentage changes between periods:

Our power segment revenues for 2009 decreased to $82.2 million compared to $89.9 million in 2008.  This decrease was primarily driven by decreased megawatt hours sold as a result of a planned major maintenance outage, which occurs every five years, and a significant unplanned outage, both of which occurred in the fourth quarter of 2009.

Our power segment’s operating income decreased to $7.7 million in 2009 compared to $16.9 million in 2008.  Excluding the 2008 gain on sale of interest in the Ft. Lupton power project of $0.9 million discussed in Items that Affect Comparability of Our Results, our power segment operating income decreased by $8.3 million.  This decrease was primarily from reduced megawatt hours sold and increased maintenance expenses as a result of a planned major maintenance outage, which occurs every five years, and a significant unplanned outage, both of which occurred in the fourth quarter of 2009.

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Heritage Segment

The following table shows comparative detail of the heritage segment’s expenses and percentage changes between periods:

Our heritage expenses for 2009 were $31.7 million compared to $35.5 million in 2008.  Excluding the heritage legal claim settlement of $0.8 million in the second quarter of 2009 discussed in Items that Affect Comparability of Our Results, our heritage segment expenses decreased by $2.9 million.  This decrease was primarily driven by a revaluation due to the elimination of postretirement medical benefits for our non-represented employees during the third quarter of 2009 and reduced workers compensation expenses due to changes in interest rates and favorable claims experience.  These decreases were partially offset with an increase in cost containment expenditures and unfavorable changes in the valuation of our Black Lung benefit’s trust assets and liabilities due to changes in interest rates.

Corporate Segment

Our corporate segment’s operating expenses totaled $8.1 million in 2009 compared to $12.7 million in 2008.  Excluding the restructuring charge of $1.9 million in 2008 discussed in Items that Affect Comparability of Our Results, our corporate segment operating expenses decreased by $2.7 million.  This decrease related to cost control efforts and a reduction in our stock compensation expense.

Other income (expense) and income tax expense

Our other expense for 2009 decreased to $14.5 million compared with $31.6 million of expense in 2008.  Excluding the $5.1 million impact of the fair value adjustment on derivative and related amortization of debt discount, $8.1 million of interest on the beneficial conversion feature associated with our convertible debt issued in 2008, the $3.8 million loss on the extinguishment of our WML debt, and the $1.3 million loss on the extinguishment of our power debt discussed in Items that Affect Comparability of Our Results, our other expense increased $1.3 million.  This increase was driven by a $1.9 million decrease in interest income, which was partially offset with a $0.4 million decrease in interest expense as a result of our debt refinancing and a $0.2 million increase in other income.

Our 2009 income tax benefit was $17.1 million compared with $0.9 million of expense in 2008.  Excluding the $17.1 million tax effect of other comprehensive income gains discussed in Items that Affect Comparability of our Results, the remaining $1.0 million decrease resulted primarily from lower state taxable income primarily driven by the customer outages.

2008 Compared to 2007

Summary

Our 2008 revenues increased to $509.7 million compared with $504.2 million in 2007.  This increase was primarily driven by a $4.7 million increase in our power segment revenues related to an increase in megawatt hours sold and favorable price increases.  Our 2008 coal segment revenues increased by $0.9 million, as a decrease in tons sold and the impact of decreased prices under our new coal sales contract at our Jewett Mine were offset by a 2% overall favorable price increase as well as pass-through revenues recognized upon the settlement of our coal royalty claims.

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Our 2008 net loss applicable to common shareholders increased to $49.9 million compared with a net loss in 2007 of $14.1 million.  Excluding the $17.1 million of 2008 expenses and the $15.1 million of 2007 income from restructuring and special items discussed in Items that Affect Comparability of Our Result, our net loss increased by $3.6 million.  The primary factors, in aggregate, driving this increase in net loss were:

-

A $3.4 million decrease in our coal segment operating income driven by:

▪

A $3.1 million increase in 2008 depreciation, depletion, and amortization expenses resulting from increased depletion expenses from asset retirement cost assets, which increased at the end of 2007 due to updated engineering studies, and capital expenditures at the mines;

▪

reduced tonnages sold; and

▪

increases in fuel and other commodity costs in 2008.

-

A $1.8 million decrease in our corporate expenses related to the execution of our restructuring plan and our cost control efforts.

-

A $1.7 million increase in power segment operating income resulting primarily from the execution of our restructuring plan and resulting cost savings.

-

A $1.7 million decrease in income from discontinued power operations and maintenance businesses sold in 2007.

-

A $1.1 million increase in our 2008 heritage costs largely driven by a $3.2 million increase in our 2008 workers compensation expenses due to a decrease in the discount rate used and unfavorable claims experience.

-

A $0.7 million increase in income tax expense resulting from increases in state income taxes and a provision for a state income tax claim.

Coal Segment

The following table shows comparative coal revenues, operating income and sales volume, and percentage changes between periods:

Our 2008 coal revenues increased to $419.8 million in 2008, compared with $418.9 million in 2007.  This increase occurred as a 0.7 million decrease in tons sold during 2008 was offset by a 2% overall increase in pricing due to increases in commodity based indices and contract renewals as well as pass-through revenues recognized upon the settlement of our coal royalty claims.

Our coal segment’s operating income decreased to $15.2 million in 2008, down from $18.7 million in 2007.  Excluding a $2.6 million charge for the 2008 settlement of a coal royalty dispute, a $0.8 million termination fee paid in 2007 for our Absaloka Mine operating contract, a $1.1 million dollar inventory impairment in 2007, and restructuring charges discussed in Items that Affect Comparability of Our Results, our coal segment’s operating income decreased by $3.4 million.  The decrease in operating income was driven by the following items:

-

A $3.1 million increase in 2008 depreciation, depletion, and amortization expenses resulting from increased depletion expenses from asset retirement cost assets, which increased at the end of 2007 due to updated engineering studies, and capital expenditures at the mines;

-

reduced tonnages sold; and

-

increases in fuel and other commodity costs in 2008.

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Power Segment

The following table shows comparative power revenues, operating income and production and percentage changes between periods:

Our 2008 power segment revenues increased to $89.6 million compared to $85.0 million in 2007.  These revenues increased due to an increase in megawatt hours sold as we had a large unexpected shutdown in 2007 and improved operating performance in 2008.  Additionally, we had a 5% favorable price increase, which was driven by increases in inflation indices.

Our power segment’s operating income was $16.9 million in 2008, compared with $14.1 million in 2007.  Excluding the a $0.9 million gain in 2008 on the sale of our royalty interest in Ft. Lupton, a $0.5 million gain on the sale of our power operations and maintenance businesses in 2007, and a $0.7 million restructuring charge in 2007 discussed in Items that Affect Comparability of Our Results, our power segment’s operating income increased by $1.7 million.  This increase was driven primarily by the execution of our restructuring plan we initiated in 2007 and the resulting cost savings.

Heritage Segment

The following table shows comparative detail of the heritage segment’s expenses and percentage changes between periods:

Our 2008 heritage expenses were $35.5 million compared to $28.6 million in 2007.  Excluding the $5.8 million combined benefit fund credit we recognized in 2007 discussed in Items that Affect Comparability of Our Results, our heritage expenses increased by $1.1 million.  This increase was driven primarily by a $3.2 million increase in our workers compensation expenses due to a decrease in our discount rate as well as unfavorable claims experience.  Favorable health care benefit experience was offset by increased administrative costs primarily due to the resolution of legal claims and consultant costs related to future cost containment efforts.

Corporate Segment

Our corporate segment’s operating expenses totaled $12.7 million in 2008 compared to $10.1 million in 2007.  Excluding the restructuring charges of $1.8 million and $3.1 million, respectively, in 2008 and 2007, and the $5.6 million gain on the 2007 sale of mineral rights discussed in Items that Affect Comparability of Our Results, our corporate segment operating expenses decreased by $1.8 million.  This decrease was driven primarily by the execution of our restructuring plan and the resulting cost savings.

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Other income (expense) and income tax expense

Our 2008 other expense increased to $31.6 million compared with $16.2 million of expense in 2007.  This increase was predominately driven by $8.1 million of interest on the beneficial conversion feature associated with our convertible debt issued in 2008 and the $3.8 million and $1.3 million losses on the extinguishment of our mining and power debt, respectively, as we refinanced them in 2008 (discussed in Items that Affect Comparability of Our Results).

Our 2008 income tax expense was $0.9 million compared with an $8.9 million income tax benefit in 2007.  Excluding the $9.1 million tax effect of other comprehensive income gains discussed in Items that Affect Comparability of Results, the remaining $0.7 million increase resulted primarily from increases in state income taxes and a provision for a state income tax claim.

Significant Anticipated Variances between 2009 and 2010 and Related Uncertainties

We expect a number of factors to result in differences in our results of operation, financial condition and liquidity in 2010 relative to 2009.  We do not expect the heritage legal claim settlement , the reclamation claim, or the tax effect of other comprehensive income gains occurring in 2009, as discussed in Items that Affect Comparability of Our Results, to reoccur in 2010.  Fair value adjustments on derivatives may reoccur in 2010 but at levels not estimable.  Additional factors that we expect to result in variances between 2009 and 2010 include the following:

-

We expect our overall coal tons delivered to increase as we experienced significant decreases in coal deliveries during 2009 as a result of unplanned customer outages.  We anticipate an increase in our coal segment operating profits due to the increased coal deliveries as well as more favorable terms and prices on several of our coal sales contracts that become effective in 2010;

-

We expect decreased heritage health benefit expenses and cash payments to retirees due to the elimination of postretirement medical benefits for our non-represented employees and the agreement we entered into to modernize the method by which prescription drugs are provided to our retirees;

-

We expect a decrease in our heritage segment’s selling and administrative costs due to significant expenses in 2009 related to our cost containment efforts;

-

We expect an increase in our power segment operating profits resulting from the completion of a 2009 planned maintenance outage that occurs every five years and a significant unplanned maintenance outage, which occurred in the fourth quarter of 2009 at our larger ROVA plant.  We expect this increase to be partially offset with a planned maintenance shutdown that occurs every five years at our second, smaller ROVA plant;

-

In June 2010, the fixed capacity payment that we receive at our second, smaller ROVA plant for each megawatt-hour of electricity produced will step down to a lower rate which continues through the end of the power sales agreement in 2020.  This decrease will result in a reduction in cash receipts, but will have no impact on our revenues as we begin recognition of this plant’s previously deferred revenues.  A similar situation occurred in 2009 at our larger ROVA plant;

-

We expect decreased pension expenses due to the freezing of one of our pension plans, which we expect to be partially offset with increased company contributions to employees’ 401(k) plans;

-

We expect to have an increase in our required pension plan contributions resulting from the decline in the value of our pension investments and our loan covenants, which require us to maintain a 90% funding status.  We expect to make a portion of these contributions in company stock;

-

We expect an increase in our depreciation expense as a result of increased capital investments made during 2009 at our mining operations.  We expect to make additional capital investments during 2010 in the range of $30.0 to $40.0 million to improve our mining operations and increase productivity.  We expect these capital investments to be funded through our mine’s operating cash flows, capital leases, or, if necessary, the mine’s existing credit facilities;

-

We expect an increase in our restricted investments and bond collateral in the range of $3.0 to $7.0 million primarily as a result of securing reclamation bonding as we enter new mining areas in 2010; and

-

We expect a reduction in our repayments of long-term debt resulting from the refinancing in 2008 of our power debt.

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We believe the net effect of the foregoing factors will result in improvements in our results of operations and cash flows in 2010 relative to 2009.  Our outlook for 2010 is based on the information we currently have available and contains certain assumptions regarding future economic conditions.  Differences in actual economic conditions compared with our assumptions could have a material impact on our results in 2010 and in subsequent years.  Key operational uncertainties relating to our expectations are described in “Risk Factors” and Item 1 “Coal Segment-Material Effects of Regulation” and “Power Segment-Material Effects of Regulation.”

Liquidity and Capital Resources

We have suffered recurring losses from operations, have a working capital deficit, a net capital deficiency, and expect to violate certain debt covenants in 2010.  These factors raise substantial doubt about our ability to continue as a going concern.  The accompanying consolidated financial statements are prepared on a going concern basis and do not include any adjustments that might result from uncertainty about our ability to continue as a going concern.  The report from our independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2009 includes an explanatory paragraph that summarizes the salient facts or conditions that raise substantial doubt about our ability to continue as a going concern.  

As a result of WRI’s renewed revolving line of credit and increase in its term debt discussed below and the factors discussed in “Significant Anticipated Variances Between 2009 and 2010 and Related Uncertainties”, we anticipate that our cash from operations and available borrowing capacity will be sufficient to meet our cash requirements for the foreseeable future thereafter, although by a small margin.  We do not currently expect to rely on proceeds from sales of assets or securities or other capital-raising transactions in order to satisfy our liquidity needs in 2010.

Our primary sources of cash include sales of our coal and power production to customers and borrowings under our credit facilities or other financing arrangements.  We generally satisfy our working capital requirements and fund capital expenditures and debt-service obligations through cash generated from operations or borrowings under our credit facilities.

Consolidated cash and cash equivalents at December 31, 2009, included (in thousands):

Amounts outstanding, availability and average borrowings under the revolving lines of credit of our subsidiaries, at December 31, 2009, are as follows (in millions):

The cash at WML and ROVA are available to us through quarterly distributions.  However, the loan agreements of WML and ROVA require debt service accounts and impose timing and other restrictions on the ability of ROVA and WML to distribute funds to us.  Additionally, the WML and ROVA revolving lines of credit are only available to these operations.  WRI can distribute cash drawn from its revolving line of credit to us through dividends.  Because the WRI loan agreement imposes fewer restrictions on the ability of WRI to make distributions to us, WRI has been a significant source of liquidity for us.  The cash at Westmoreland Risk Management, our captive insurance subsidiary, is available to us through dividends, subject to maintaining a statutory minimum level of capital, which was $0.2 million at December 31, 2009.

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The primary factors impacting our liquidity in 2009 were as follows:

·

Our pension obligations are primarily funded through cash generated from our subsidiary’s operations.  These pension contributions by our subsidiaries reduce distributions available to us.  Under certain circumstances, we are able to make a portion of these contributions in company stock.

The following table summarizes expenditures and contributions for our heritage health benefit and pension obligations (in millions):

Our heritage health obligations are funded by distributions from our operating subsidiaries. Our heritage health benefit costs consist of payments for postretirement medical benefits, workers’ compensation benefits, black lung benefits and combined benefit fund premiums. We significantly reduced our heritage obligations in 2009 through plan amendments and entering into an agreement to modernize the method by which prescription drugs are provided to retirees. See Note 6 to our consolidated financial statements for additional information on these reductions.

(1)   Of the 2009 contribution, $4.2 million was made through the contribution of company stock.

·

Our significant level of debt, as described below, and limitations under current debt agreements limits the ability of our subsidiaries, WML and ROVA, to pay dividends to us. See below for our principal components and the maturities of our long-term debt and detail on our covenant defaults during the year.

·

We anticipate that, as we permit additional areas for our mines in 2010 to continue our operations, our bonding requirements will increase significantly and the cash collateral requirements will increase as well.

·

Unanticipated customer outages and an overall decrease in the demand for electricity had a significant impact our liquidity. During 2009, our Rosebud and Beulah Mines’ customers had unscheduled outages following their planned maintenance outages. The Beulah Mine customer ended its unscheduled outage and resumed coal deliveries in July 2009. However, deliveries to our Rosebud Mine’s customer were significantly reduced until October 2009 when the customer acquired needed replacement equipment and operations resumed. Additionally, due to current unfavorable economic conditions in the energy market, our Absaloka and Jewett Mine’s 2009 deliveries decreased. These reductions in planned 2009 deliveries reduced the dividends and cash flows available to us.

Long-Term Debt and Covenants

As of December 31, 2009, our total gross indebtedness was approximately $254.7 million, with approximately $57.5 million of that amount classified as current liabilities.  Included in the $57.5 million current portion of debt are:

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$9.6 million of WRI term debt and $11.2 million of convertible note debt, both of which have maturities after December 31, 2010 but are classified as current liabilities due to WRI’s anticipated loan covenant non-compliance and related cross default impact on the convertible note;

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$16.4 million of WRI revolving line of credit which we anticipate will be extended prior to its November 18, 2010 expiration date; and

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 $20.3 million in our subsidiaries’ term debt, which matures over the next twelve months and is expected to be funded by cash provided by the operations of those subsidiaries.

Convertible Notes

We have $17.3 million in senior secured convertible notes ($11.2 million net of unamortized discount), which bear interest at a rate of 9.0% per annum and are payable in full on March 4, 2013.

Our convertible notes are secured by a second lien on the assets of WRI.

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Our covenants for our convertible notes contain affirmative and negative covenants, which limit our ability to dispose of assets, make investments, purchase or redeem our common stock, pay preferred dividends and merge with another corporation.  As discussed above, WRI’s anticipated non-compliance with loan covenants could trigger a future cross default on our convertible notes. We have classified $11.2 million of its convertible note debt as a current liability due to the uncertainty of WRI’s future compliance with covenant requirements.

WML

WML has $125.0 million of fixed rate term debt outstanding at December 31, 2009, which bears interest at 8.02% per annum, payable quarterly.  The term debt is payable in full on March 31, 2018.  No principal payments are required for this debt until 2011.  WML also has a revolver with a borrowing limit of $25.0 million and maturity date of June 26, 2013.  The interest rate under this revolver at December 31, 2009, was 3.25% per annum.  At December 31, 2009, we had a letter of credit of $1.9 million supported by the revolver leaving us $23.1 million of unused borrowings.

The term debt and revolver are secured by substantially all assets of WML, our membership interest in WML; and primarily all of the stock of WML’s subsidiaries.

WML’s lending arrangements contain, among other conditions, events of default and various affirmative and negative covenants.  The financial ratios included in WML’s term debt and revolving line of credit include a debt service coverage ratio and a leverage ratio.  The debt service coverage ratio must remain within a specified range.  The leverage ratio requires that we not permit the ratio of total debt at the end of each quarter end to EBITDA (both as defined by the agreement) for the four quarters then ended to be greater than a specified amount.  The WML covenants also set limits for capital expenditures.

As a result of customer outages, WML did not comply with its original leverage ratio covenant as of June 30, 2009, September 30, 2009, and December 31, 2009, and believes it will not comply with the original leverage ratio requirements as of March 31, 2010.  On October 7, 2009, WML obtained a waiver from its lenders for the quarter ended June 30, 2009, and September 30, 2009.  WML also received waivers for future leverage ratio non-compliance for the quarters ended December 31, 2009, and March 31, 2010, provided WML meets certain conditions, including a revised leverage ratio covenant.  WML met the waiver requirements at December 31, 2009, and believes it will also meet the March 31, 2010, waiver requirements.  Accordingly, the debt has been classified as long term.  We believe we will be able to meet all WML covenant requirements during 2010.

WRI

WRI’s Business Loan Agreement was amended in 2009 and the $20.0 million revolving line of credit was extended to November 18, 2010.  Under the terms of the amended agreement, the limit of the term debt was increased to $12.0 million; as a result of this increase, we received $7.8 million in cash.  The amount of principal payments due in 2010 for the term debt is $2.4 million.  The term debt’s final payment is due January 29, 2015.  The interest rate for the term debt and the revolver are payable at the prime rate.  The term debt and revolver are both currently subject to a per annum 7% and 6% floor, respectively.  At December 31, 2009, we had $3.6 million of unused borrowings under the revolver.

The two debt instruments are collateralized by a first lien in WRI’s inventory, chattel paper, accounts and notes receivable, and equipment.  WCC is the guarantor of the debt under the Agreement and its guaranty is secured by a pledge of WCC’s interest in WRI.

WRI’s Business Loan Agreement requires it to comply with numerous covenants and minimum financial ratio requirements primarily related to debt coverage, tangible net worth, capital expenditures, and its operations.  The net worth covenant requires WRI to have a net worth of not less than a specific amount, defined by the agreement, by a specific date, defined by the agreement, and maintain this net worth value thereafter.  Covenants limit the amount of capital expenditures that can be made without prior consent of the lender.  The debt coverage covenant requires WRI to maintain a ratio of operating income, as defined by the agreement, to debt service, as defined by the agreement, of not less than specified range at each quarter end and year-end.

At September 30, 2009, primarily as a result of unfavorable market conditions driving decreases in tonnages sold, WRI was not in compliance with a net worth requirement contained in its business loan agreement.  On October 29, 2009, WRI obtained a waiver from its lenders for the quarter ended September 30, 2009.  The agreement was amended on November 9, 2009, to extend the net worth requirement from September 30, 2009 to April 30, 2010.  We believe we will not be able to meet the covenant requirement by April 30, 2010, and therefore have classified the entire outstanding balance of this term debt, $12.0 million, as a current liability.  We do not believe that we will be able to comply with the net worth requirement during 2010; however, we do believe we will meet all other covenants requirements contained in the agreement in 2010.

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As a result of our anticipated non-compliance with the net worth requirement, WRI’s lenders may impose additional operating and financial restrictions on us or modify the terms of our existing debt agreements. In addition, the lenders may require the payment of additional fees, require prepayment of our indebtedness to them, accelerate the amortization schedule for our indebtedness or increase the interest rates they charge us on our outstanding indebtedness.

ROVA

At December 31, 2009, ROVA has approximately $55.6 million of fixed rate term debt outstanding with interest rates varying from 6.0% to 11.42% (excluding $0.9 million of unamortized debt premiums).  The weighted average interest rate on the fixed rate term debt is 10.0% per annum.  The amount of principal amounts due in 2010 for this debt is $9.4 million.  Interest is payable quarterly and the term debt is to be fully repaid before the end of 2015.

ROVA has a $6.0 million revolving loan with a maturity of April 30, 2015.  Interest on the revolving loan is payable quarterly at the three-month LIBOR rate plus 1.375% (1.63% per annum at December 31, 2009.  At December 31, 2009, we had $6.0 million of unused borrowings under the revolver.

ROVA’s fixed rate term debt as well as the revolving loan are secured by a pledge of the quarterly cash distributions from ROVA.  ROVA is required to comply with certain loan covenants related to interest and fixed charge coverage.  As of December 31, 2009, ROVA was in compliance with such covenants.

Historical Sources and Uses of Cash

The following is a summary of cash provided by or used in each of the indicated types of activities:

Cash provided by operating activities decreased $25.8 million in 2009 compared to 2008 primarily as a result of the customer outages and cash outlays for our coal royalty disputes.  In addition, cash receipts decreased in 2009 due to a scheduled decrease in the payments ROVA collects from its customer.

Cash used in investing activities increased $32.0 million in 2009 compared to 2008 primarily as a result of the reduction in restricted investments and bond collateral in 2008 from the ROVA and WML debt refinancing.  In addition, our capital spending increased to $34.5 million in 2009 from $31.3 million in 2008.

Cash used in financing activities decreased by $8.2 million in 2009 compared to 2008 primarily as a result of the $5.3 million of debt issuance costs paid in 2008.

Our working capital deficit at December 31, 2009, increased by $50.8 million to approximately $75.0 million compared to a $24.2 million deficit at December 31, 2008. The increase in the working capital deficit resulted from reduced cash and cash equivalents and accounts receivables balances as a result of reduced tons from customer outages and unfavorable economic conditions.  Our current maturities of long-term debt increased as a result of the loan defaults at WRI and the expected cross default discussed in Note 5 to our consolidated financial statements and above.  The increases in our working capital deficit were offset by the decrease in our accounts payable balance primarily due to the payment of our coal royalty claims.

Contractual Obligations and Commitments

The following table presents information about our contractual obligations and commitments as of December 31, 2009, and the effects such obligations are expected to have on liquidity and cash flow in future periods.  Some of the amounts below are estimates.  We discuss these obligations and commitments elsewhere in this filing.

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(1)  Our purchase obligations relate to coal supply agreements for our power plants.  See Note 16 to our consolidated financial statements for details.

(2)  Represents benefit payments for our postretirement medical benefits, black lung, workers’ compensation, and combined benefit fund plans, as well as contributions for our defined benefit pension plans and final reclamation costs.

Critical Accounting Policies

Going Concern

We have suffered recurring losses from operations, have a working capital deficit, a net capital deficiency, and expect to violate certain debt covenants in 2010.  These factors raise substantial doubt about our ability to continue as a going concern.  The accompanying consolidated financial statements are prepared on a going concern basis and do not include any adjustments that might result from uncertainty about our ability to continue as a going concern.  The report from our independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2009 includes an explanatory paragraph that summarizes the salient facts or conditions that raise substantial doubt about our ability to continue as a going concern.

Postretirement Medical Benefits

Our most significant long-term obligation is the obligation to provide postretirement medical benefits.  We provide these benefits to our former employees and their dependents.  Detailed information related to this liability is included in Note 6 to our consolidated financial statements.

Our liability for our employees’ postretirement medical benefit costs is recorded on our consolidated balance sheets in amounts equal to the actuarially determined liability, as this obligation is not funded.

Our postretirement medical benefit liability is actuarially determined and we use various assumptions including the discount rate and future cost trends, to estimate the cost and obligation for this item.  Our discount rate for postretirement medical benefit is determined by utilizing a hypothetical bond portfolio model, which approximates the future cash flows necessary to service our liability.  This model is calculated using a yield curve that is developed using the average yield for bonds in the tenth to ninetieth percentiles, which excludes bonds with outlier yields.

We make assumptions related to future trends for medical care costs in the estimates of retiree health care obligations.  Our medical trend assumption is developed by annually examining the historical trend of our cost per claim data and projecting forward the participant claims and our current benefit coverage.  These projections include cost savings from the modernization of the method by which prescription drugs are provided to retirees of our former operations.  If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates.  Moreover, regulatory changes could increase our obligation to satisfy these or additional obligations.

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Below we have provided a sensitivity analysis to demonstrate the significance of the health care cost trend rate assumptions in relation to reported amounts.

Asset Retirement Obligations, Final Reclamation Costs and Reserve Estimates

Our asset retirement obligations primarily consist of cost estimates for final reclamation of surface land and support facilities at both surface mines and power plants in accordance with federal and state reclamation laws.  Asset retirement obligations are determined for each mine using estimates and assumptions including estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage, the timing of these cash flows, and a credit-adjusted, risk-free rate.  As changes in estimates occur such as mine plan revisions, changes in estimated costs, or changes in timing of the final reclamation activities, the obligation and asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate.  If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different from currently estimated.  Moreover, regulatory changes could increase our obligation to perform final reclamation and mine closing activities.

Certain of our customers have either agreed to reimburse us for final 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 and directly reduce our reclamation expenses as we record a receivable for these future receipts.  See additional information regarding our asset retirement obligations in Note 9 to our consolidated financial statements.

Income Taxes and Deferred Income Taxes

As of December 31, 2009, we had significant deferred tax assets.  Our deferred tax assets include federal and state regular net operating losses, or NOLs, alternative minimum tax, or AMT, credit carryforwards, Indian Coal Tax Credits, or ICTC, carryforwards, and net deductible reversing temporary differences related to on-going differences between book and taxable income.

We believe we will be taxed under the AMT system for the foreseeable future due to the significant amount of statutory tax depletion in excess of book depletion expected to be generated by our mining operations.  As a result, we have determined that a valuation allowance is required for all of our regular federal net operating loss carryforwards and AMT credit carryforwards since they are not available to reduce AMT income in the future.

We have recorded a full valuation allowance for all but $2.3 million of our state NOLs since we believe they will not be realized.  No valuation allowance is being provided on $2.3 million of deferred tax assets because we believe that these NOLs will be used to offset our liabilities relating to our uncertain tax positions.

We have determined that a full valuation allowance is required for all of our ICTC carryforward.  The ICTC can generally be used to offset AMT liability.  We do not believe we have sufficient positive evidence of significant magnitude to substantiate that our deferred tax asset for the ICTC carryforward is realizable at a more-likely-than-not level of assurance.  As a result, we will continue to record a full valuation allowance on our ICTC carryforward; reversing valuation allowance only if utilized in a future year.

We have determined that since our net deductible temporary differences will not reverse for the foreseeable future, and we are unable to forecast when we will have regular taxable income when they do reverse, a full valuation allowance is required for these deferred tax assets, other than the deferred tax asset relating to our uncertain tax positions.

The tax effect of pretax income or loss from continuing operations is generally determined by a computation that does not consider the tax effects of items that are not included in continuing operations.  The exception to that incremental approach is that all items (for example, items recorded in other comprehensive income, extraordinary items, and discontinued operations) be considered in determining the amount of tax benefit that results from a loss from continuing operations and that shall be allocated to continuing operations.

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Recent Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board, or FASB, issued ASC 105, The FASB Accounting Standards Codification ^TM and the Hierarchy of Generally Accepted Accounting Principles.  This statement established the Accounting Standards Codification, or ASC, and was effective for interim and annual periods ending after September 15, 2009.  The adoption of ASC 105 is reflected throughout the Notes to the Consolidated Financial Statements.

In June 2009, we adopted ASC 855-10-05, Subsequent Events.  ASC 855-10-05 establishes general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued.  ASC 855-10-05 is effective for interim financial periods ending after June 15, 2009.  We have evaluated subsequent events, the effect of which had no impact on our financial position or results of operations.

On January 1, 2009, we adopted ASC 815-40, Determining Whether an Instrument (or Embedded Feature) is Indexed to an Entity’s Own Stock.  ASC 815-40 was issued in June 2008 by the FASB and clarifies how to determine whether certain instruments or features are indexed to an entity’s own stock.  ASC 815-40 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years.  We recorded a cumulative effect of change in accounting principle upon adoption of ASC 815-40.  See Note 10 to our consolidated financial statements for additional information.

On January 1, 2009, we adopted ASC 810-45, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB 51.  ASC 810-45 establishes accounting and reporting standards for (1) noncontrolling interests in partially owned consolidated subsidiaries and (2) the loss of control of subsidiaries.  ASC 810-45 requires noncontrolling interests (minority interests) to be reported as a separate component of equity.  The amount of net income or loss attributable to the noncontrolling interest will be included in consolidated net income or loss on the face of the income statement.  In addition, this statement requires that a parent recognize a gain or loss in net income or loss when a subsidiary is deconsolidated.  Such gain or loss will be measured using the fair value of the noncontrolling equity investment on the deconsolidation date.  ASC 810-45 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest.  We recorded $1.8 million of net loss attributable to noncontrolling interest for the year ended December 31, 2009, which is reflected in our consolidated financial statements.

In June 2008, the FASB released ASC 260-10-45, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.  ASC 260-10 requires that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities as defined in ASC 260-10-45, Participating Securities and the Two Class Method under ASC 260-10, and therefore, should be included in computing earnings per share using the two-class method.  ASC 260-10 was effective for us as of January 1, 2009, but had no impact on our earnings per share calculation as of December 31, 2009.

In December 2008, the FASB issued ASC 715-20-65-2 Employers’ Disclosures about Postretirement Benefit Plan Assets.  ASC 715-20-65-2 amends the requirements for employer’s disclosure of plan assets for defined benefit pensions and other postretirement plans.  The objective is to provide users of financial statements with an understanding of how investment allocation decisions are made, the major categories of plan assets held by the plans, the inputs and valuation techniques used to measure the fair value of plan assets, significant concentration of risk within the company’s plan assets, and for fair value measurements determined using significant unobservable inputs a reconciliation of changes between the beginning and ending balances.  ASC 715-20-65-2 is effective for fiscal years ending after December 15, 2009 (December 31, 2009, for us).  The required disclosures are included in Notes 6 and 7 to our consolidated financial statements.

In June 2009, FASB issued ASC 810-10-65-2, Amendments to FASB ASC 810-10-05-8A. This statement prescribes a qualitative model for identifying whether a company has a controlling financial interest in a variable interest entity or VIE and eliminates the quantitative model prescribed by ASC 810-10-05-8A. The new model identifies two primary characteristics of a controlling financial interest: (1) provides a company with the power to direct significant activities of the VIE, and (2) obligates a company to absorb losses of and/or provides rights to receive benefits from the VIE. ASC 810-10-65-2 requires a company to reassess on an ongoing basis whether it holds a controlling financial interest in a VIE. A company that holds a controlling financial interest is deemed to be the primary beneficiary of the VIE and is required to consolidate the VIE. This statement is effective for fiscal years beginning after November 15, 2009.  The adoption of ASC 810-10-65-2 is expected to have no impact on our financial position or results of operations.  

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements.  These arrangements include financial instruments with off-balance sheet risk such as bank letters of credit and performance or surety bonds.  Surety bonds and letters of credit are issued by financial institutions to third parties to assure the performance of our obligations relating to

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reclamation, workers’ compensation obligations, postretirement medical benefit obligations, and other obligations.  These arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

We use a combination of surety bonds and letters of credit to secure our financial obligations for reclamation, workers’ compensation, postretirement medical benefit and other obligations as follows as of December 31, 2009 (in thousands):

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ITEM 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to market risk, which includes adverse changes in commodity prices and interest rates.

Commodity Price Risk

We manage our price risk for coal sales, electricity and steam production through the use of long-term agreements, rather than through the use of derivatives.  We estimate that almost 100% of our coal and our electricity production are sold under long-term agreements.  These coal 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.

We have exposure to price risk for supplies that are used directly or indirectly in the normal course of production such as diesel fuel and explosives.  We manage these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivatives from time to time.  As of December 31, 2009, we had derivative instruments outstanding for explosives; however, we do not consider our market risk for these instruments to be material.  At December 31, 2009, we had fuel supply contracts outstanding with a minimum purchase requirement of 4.1 million gallons of diesel fuel per year.  These contracts qualify for the normal purchase normal sale exception under hedge accounting.

Interest Rate Risk

Our exposure to changes in interest rates results from our debt obligations shown in the table below that are indexed to either the prime rate or LIBOR.  Based on balances outstanding as of December 31, 2009, a change of one percentage point in the prime interest rate or LIBOR would increase or decrease interest expense on an annual basis by the amount shown below (in thousands):

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ITEM 8—FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Westmoreland Coal Company

We have audited the accompanying consolidated balance sheet of Westmoreland Coal Company and subsidiaries (the "Company") as of December 31, 2009, and the related consolidated statements of operations, shareholders’ deficit and comprehensive loss, and cash flows for the year then ended.  These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Westmoreland Coal Company and subsidiaries at December 31, 2009, and the consolidated results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As more fully discussed in Note 1 to the consolidated financial statements, the Company has suffered recurring losses from operations, expects to violate certain debt covenants in 2010, has a working capital deficit, and has a net capital deficiency. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regards to these matters are also described in Note 1 to the consolidated financial statements. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 1 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board Standard 160, Noncontrolling Interests in Consolidated Financial Statements (codified in FASB ASC Topic 810, Consolidation) effective as of January 1, 2009 and retrospectively adjusted its consolidated financial statement disclosures for the years ended December 31, 2008, and 2007 presented herein.

As discussed in Note 1 to the consolidated financial statements, the Company adopted Emerging Issues Task Force 07-5, Determining Whether an Instrument (or Embedded Feature) is Indexed to an Entity’s Own Stock (codified in FASB ASC Topic 815,) effective as of January 1, 2009 and adjusted its accounting for its consolidated financial statements for the year ended December 31, 2009 presented herein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 12, 2010 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Denver, Colorado

March  12, 2010

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Westmoreland Coal Company

We have audited the consolidated balance sheets of Westmoreland Coal Company and subsidiaries (the Company) as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders’ deficit and comprehensive loss, and cash flows for each of the years in the three-year period ended December 31, 2008. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

 In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Westmoreland Coal Company and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

 The consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has suffered recurring losses from operations, has a working capital deficit, and has a net capital deficiency that raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regards to these matters are also described in Note 1 to the consolidated financial statements. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

KPMG LLP

Denver, Colorado

March 13, 2009, except as to Note 15 as to which the date is March 12, 2010

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See accompanying Notes to Consolidated Financial Statements.

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See accompanying Notes to Consolidated Financial Statements.

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See accompanying Notes to Consolidated Financial Statements.

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