ITEM 1 - BUSINESS
Overview
We are an energy company. We mine coal, which is used to produce electric power, and we own power-generating plants. We own five mines which supply baseload power plants. Several of these power plants are located adjacent to our mines, and we sell virtually all our coal under long-term contracts. Consequently, our mines enjoy relatively stable demand and pricing compared to competitors who sell more of their production on the spot market.
We own the Roanoke Valley, or ROVA, independent power project. ROVA consists of two coal-fired units with a total generating capacity of 230 megawatts, or MW. ROVA is baseloaded and supplies power pursuant to long-term contracts. We also operate and maintain ROVA and four power projects owned by others. We acquired the 50% interest in ROVA that we did not previously own, and the contracts to operate and maintain the four other power projects, on June 29, 2006.
We own a 4.49% interest in the gas-fired Ft. Lupton project, which has a generating capacity of 290 MW and provides peaking power.
We also sell coal produced by others.
Coal Operations
We produced 29.4 million tons of coal in 2006, about 3% of all the coal produced in the United States. We were the 8th largest coal producer in the United States, ranked by tons of coal mined in 2005.
Mines
We own five mines; all except the Jewett Mine are located in the northern tier, a coal market extending from Washington through Minnesota and other upper Midwestern states. The mines are:
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the Absaloka Mine,
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the Rosebud Mine,
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the Jewett Mine,
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the Beulah Mine, and
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the Savage Mine.
The Absaloka Mine is owned by our subsidiary, Westmoreland Resources, Inc. (“WRI”). The Beulah, Jewett, Rosebud, and Savage Mines are owned by our separate subsidiary, Westmoreland Mining LLC.
All of these mines are surface mines. At large surface mines like ours, coal is frequently mined from more than one area or pit at any given time. Surface mining involves extracting coal that lies close to the surface. Where the surface layer contains rock, overburden drills are used to drill holes in the rock, explosives are inserted, and the blast loosens the layer of rock. Earth-moving equipment removes the overburden - the layer of dirt and rock that lies between the surface and the coal. A machine called a dragline is typically used to remove a substantial portion of the overburden. Draglines are very large-our largest dragline weighs approximately 7,000 tons and has a bucket capacity of 128 cubic yards. Smaller pieces of equipment, including bulldozers, front-end loaders, scrapers, and dump trucks, move the remainder of the overburden. Once the coal has been exposed, front-end loaders, backhoes, or electric shovels load the coal in dump trucks. After the coal has been extracted, it is processed (typically by crushing), sampled (or “assayed”), and then shipped to customers.
The Absaloka Mine is located on approximately 15,000 acres in Big Horn County, Montana, near the town of Hardin. Coal was first extracted from the Absaloka Mine in 1974. WRI owns the Absaloka Mine. We own 80% of the stock of WRI. Washington Group International, Inc. owns the remaining 20% and will operate the mine through March 30, 2007, when WRI will assume operations. We own 100% of each of our other subsidiaries.
The Rosebud Mine is located on approximately 25,000 acres in Rosebud and Treasure Counties, Montana, near the town of Colstrip, about 130 miles east of Billings. Coal was first mined near Colstrip in 1924, and production from the existing mine complex began in 1968. Westmoreland Mining’s subsidiary, Western Energy Company, owns and operates the Rosebud Mine. Westmoreland Mining acquired the stock of Western Energy from Entech, Inc., a subsidiary of the Montana Power Company, in April 2001.
The Jewett Mine is located on approximately 35,000 acres in Freestone, Leon, and Limestone Counties, Texas, near the town of Jewett, about half way between Dallas and Houston. The Jewett Mine produces lignite, a type of coal with a lower Btu value per ton than sub-bituminous or bituminous coal. “Btu” is a measure of heat energy. The higher the Btu value, the more energy is produced when the coal is burned. Lignite was first extracted from the Jewett Mine in 1985. Westmoreland Mining’s subsidiary, Texas Westmoreland Coal Company (formerly Northwestern Resources Co.), owns and operates the Jewett Mine. Westmoreland Mining acquired the stock of Northwestern Resources from Entech, Inc. in April 2001.
The Beulah Mine is located on approximately 9,300 acres in Mercer and Oliver Counties, North Dakota, near the town of Beulah. The Beulah Mine also produces lignite. Lignite was first extracted from the Beulah Mine in 1963. Westmoreland Mining’s subsidiary, Dakota Westmoreland Corporation, owns and operates the Beulah Mine. Westmoreland Mining acquired the Beulah Mine in May 2001 from Knife River Corporation, a subsidiary of MDU Resources Group, Inc.
The Savage Mine is located on approximately 1,600 acres in Richland County, Montana, near the town of Sidney. The Savage Mine produces lignite. Production began at the Savage Mine in 1958. Westmoreland Mining’s subsidiary, Westmoreland Savage Corporation, owns and operates the Savage Mine.
Westmoreland Mining acquired the Savage Mine in May 2001 from Knife River Corporation.
The following table presents the sales from our mines in the last three years (in thousands of tons):
Coal and the Production of Electricity
Over the last fifty years, coal has played a significant role in generating electricity in the United States. The following table, derived from the U.S. Energy Information Administration (“EIA”), shows coal’s share in the production of all electricity in the United States:
(1)
All sources include all fossil fuels, nuclear electric power, hydroelectric pumped storage, renewable energy (including conventional hydroelectric power), and other.
The EIA projects that the output of coal-fired plants used to generate electricity will increase from 2,015 billion kilowatt hours in 2005 (50% of total generation) to 3,234 billion kilowatt hours in 2030 (56% of total generation). Although most of the growth is projected to occur from 2025 to 2030 as new coal fired plants come on line during that period, the average annual increase over the next 24 years is 2.6%.
Customers, Competition, and Coal Supply Agreements
We sell almost all of the coal that we produce to plants that generate electricity. In 2006, for example, we sold less than 1% of our coal to industrial and institutional users and the remainder to power-generating plants. These plants compete with all other producers of electricity to be “dispatched,” or called upon to generate power. We compete with many other suppliers of coal to provide fuel to these plants.
We believe that the competitive advantage of our mines derives from three facts:
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all of our mines are the most economic suppliers to each of their respective principal customers;
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nearly all of the power plants we supply were specifically designed to use our coal; and
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the plants we supply are among the lower cost producers of electric power in their respective regions and are among the cleaner producers of power from fossil fuels.
As a result, we believe that the power-generating plants that we supply are more likely to be dispatched, and that our mines will be supplying the coal that powers these generating units. All of the power-generating plants we supply are baseloaded. The baseload is the part of the total demand for energy that does not vary over a given period of time, and a baseload or baseloaded power plant is a plant that supplies this relatively consistent demand.
From the standpoint of a purchaser of coal, two of the principal costs of burning coal are the cost of the coal and the cost of transporting the coal from the point of extraction to the purchaser. The principal customers of the Rosebud, Jewett, and Beulah Mines are located adjacent to the mines, so that the coal for these customers can be delivered by conveyor belt or off road truck rather than by more expensive means such as on-road truck or rail. The customers of the Savage Mine are located approximately 20 to 25 miles from the mine, so that coal can be transported most economically by on-road truck. The Absaloka Mine enjoys about a 300 mile rail advantage over its principal competitors from the Southern Powder River Basin (“SPRB”). We believe that all of our mines are the most economic suppliers to each of their respective principal customers, a result of a transportation advantage they have compared to our competitors. We also believe that the next most economic suppliers to these customers could be other mines of ours.
The Absaloka Mine faces a different competitive situation than our other mines. The Absaloka Mine sells its coal in the rail market to utilities located in the northern tier of the United States that are served by the Burlington Northern Santa Fe Railway (“BNSF”). These utilities may purchase coal from us or from other producers, and we compete with other producers on the basis of price and quality, with the purchasers also taking into account the cost of transporting the coal to their plants. The Absaloka Mine was developed in part to supply the Sherburne County Station, a three unit power plant operated by Xcel Energy near Minneapolis, Minnesota, with a generating capacity of 2,292 MW. The Absaloka Mine has a transportation advantage to the Sherburne County Station because it is located about 300 rail miles closer to that power plant than other mines competing for that business. The Absaloka Mine has supplied the Sherburne County Station since 1976, when the station commenced commercial operations. The Absaloka Mine has three separate coal sales contracts to supply the Sherburne County Station.
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The Absaloka Mine supplies coal to Xcel Energy under two primary contracts, one covering 3.0 to 3.4 million tons per year that expires at the end of 2007 and one covering 1.3 million tons per year that was renewed effective January 1, 2007 and expires at the end of 2010. We receive prices under these contracts that are adjusted throughout their terms by specified inflation indices.
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The Absaloka Mine also supplies coal to Western Fuels Association, the fuel buyer for Southern Minnesota Municipal Power Agency or SMMPA, covering almost all of SMMPA’s fuel requirements for Unit 3 at the Sherburne County Station, or approximately 1.5 million tons per year. This contract expires at the end of 2009. The price we receive under this contract is adjusted throughout its term by specified inflation indices.
The Absaloka Mine also sold coal to Xcel Energy’s A.S. King Station, which is located in Bayport, Minnesota, until September 2006 and sells coal to Consumers Energy Company through Midwest Energy Resources Company for Consumers’ Cobb and Weadock stations, which are located in Muskegon and Essexville, Michigan, under contracts expiring at the end of 2007 but which may be extended to the end of 2009. The mine also sells coal to Rocky Mountain Power, a subsidiary of MDU Resources Group, under an agreement that expires at the end of 2008, but which may be extended to the end of 2010. This coal is delivered to the customer’s plant in Hardin, Montana, via highway truck. Absaloka also sold spot coal in 2006 to several other rail-served customers. The Absaloka Mine produces coal from land leased from the Crow Tribe of Indians. In February 2004, we reached agreement with the Crow Tribe for exploration of new coal reserves in order to continue serving customers beyond exhaustion of the reserves in our existing lease.
The Rosebud Mine’s primary customers are the owners of the four-unit Colstrip Station, which has a generating capacity of approximately 2,200 MW, and is located adjacent to the mine. The Rosebud Mine has supplied the Colstrip Station since 1975 and 1976, when Colstrip Units 1&2 commenced commercial operations. Western Energy sells this coal under long-term contracts expiring in 2009 for Colstrip Units 1&2 and in 2019 for Colstrip Units 3&4. A new agreement with Colstrip Units 1&2 was executed in March 2007 for a term commencing in 2010 and expiring at an indefinite date that we project will be no sooner than 2019. The current contract with Colstrip Units 1&2 specifies a base price per ton that is subject to adjustment for certain indices and changes in our costs, and we are also entitled to receive a reasonable profit. Western Energy’s coal supply agreement with the owners of Colstrip Units 3&4 is a cost-plus arrangement that provides a return on investment on mine assets as well as certain set fees. The new Colstrip Units 1&2 contract also provides for cost-plus pricing, but with different provisions for return on investment and fees. The owners of Colstrip Units 3&4 also compensate Western Energy under a separate contract for transporting the coal to them on a conveyor belt that Western Energy owns. With some exceptions, the contracts with the owners of the Colstrip Station are full requirements contracts; that is, the Colstrip Units are required to purchase all their coal requirements from or through the Rosebud Mine. The Rosebud Mine also supplies coal to Minnesota Power under a coal supply agreement that expires in 2008 and contains two one-year extensions at the customer’s option. Under this contract, Minnesota Power pays a base price per ton, which increases annually by a fixed percentage.
The Jewett Mine’s sole customer is the two-unit Limestone Electric Generating Station, which has a generating capacity of approximately 1,820 MW and is located adjacent to the mine. The Limestone Station is currently owned by NRG Texas, LLC (“NRGT”), a wholly owned subsidiary of NRG Energy, Inc. The Jewett Mine has supplied the Limestone Station since 1985, when it commenced commercial operations. The Jewett Mine sells lignite to NRGT pursuant to an Amended Lignite Supply Agreement (“ALSA”) that expires in 2015. The ALSA provides for the annual determination of volumes and pricing, with pricing based on an equivalent value of coal from Wyoming’s SPRB, as generally delivered to and used at the Limestone Station. Texas Westmoreland and Texas Genco, LLC, NRGT’s predecessor, have disputed the proper interpretation of some elements of the ALSA from time to time. In January of 2004, Texas Westmoreland and Texas Genco settled certain of the disputes between them. Among other things, Texas Genco, LLC committed to purchase approximately 6.7 million tons of lignite from the Jewett Mine per year during the years 2004 through 2007, and, for that same period, the parties agreed to the price for that lignite. A new interim agreement was reached in September 2005 that enhanced the economics of the Jewett Mine over previous interim pricing arrangements, provided capital to support mine development, improved the mechanics for determining equivalent market pricing pursuant to the parties’ underlying contract and provided Texas Westmoreland with a stable and satisfactory level of financial performance. Beginning in 2008, the price will again be determined based on an equivalent value of coal from Wyoming’s SPRB, as delivered to and used at the Limestone Station. The parties agreed to arbitrate the 2008 equivalent price as it would be determined by the ALSA. These expedited
arbitration proceedings were completed in late March 2007. The arbitration established a price of $1.2069 per million Btu for 2008. We received a price of $1.246 in 2006. Texas Westmoreland and NRG have been discussing various paths forward beginning in 2008, including modification or restructuring of the ALSA. The parties may or may not ultimately agree to terms that modify or restructure the ALSA including the 2008 price determined in arbitration.
The Beulah Mine supplies the Coyote Station, which has a generating capacity of approximately 420 MW and is located adjacent to the mine, and the Heskett Station, which has a generating capacity of approximately 100 MW and is located in Mandan, North Dakota, approximately 74 miles from the mine. Coal is shipped to the Heskett Station on the BNSF. The Beulah Mine has supplied the Coyote Station since 1981, when it commenced commercial operations, and the Heskett Station since 1963. The contract with the Coyote Station expires in 2016. The contract with the Heskett Station was renewed at a higher price in 2006 and expires in 2011. The price of the coal under these contracts is adjusted for certain indices and mine costs, and for the Coyote Station is supplemented by a provision setting forth guaranteed minimum and maximum net income levels. The Beulah Mine’s contracts with the Coyote Station and, with a minor exception, the Heskett Station, are each full requirements contracts.
The Savage Mine supplies lignite to the Lewis & Clark Station, which has a generating capacity of approximately 49 MW, and the American Crystal Sugar’s Sidney Sugars plant, which uses coal from the Savage Mine to heat its boilers and process sugar beets. These facilities are located approximately 20 and 25 miles from the mine, respectively, so that coal can be transported to them economically by on-road truck. The Savage Mine has supplied the Lewis & Clark Station since 1958, when it commenced commercial operations. The Savage Mine’s contracts with the Lewis & Clark Station and the Sidney Sugars plant run until December 2007 and August 2008, respectively. These contracts, which involve smaller volumes than our other coal supply contracts, are with minor exceptions each full requirements contracts.
We consider a contract that calls for deliveries to be made over a period longer than one year a long-term contract. The following table shows, for each of the past five years, our coal revenues, the tons sold from our mines, the percentage of our coal sales made under long-term contracts, and the weighted average price per ton that we received under these long-term contracts.
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In 2004, we concluded arbitration with the owners of Colstrip Units 1&2. The arbitration determined the price we received for coal that we delivered to Colstrip Units 1&2 from July 2001. Our coal revenues for 2004, and the weighted average price per ton received under long-term contracts in 2004, include the entire amount we received pursuant to this arbitration. Excluding the portion of the arbitration award that covered coal that we had delivered to Colstrip Units 1&2 in previous years, we earned coal revenues of $302,753,000 and received a weighted average price of $10.78 per ton under long-term contracts in 2004.
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The weighted average price per ton that we received declined from 2002 to 2003 principally because the Jewett Mine transitioned from cost-plus-fees pricing to a market-based pricing mechanism, effective July 1, 2002. That mechanism was, in turn, replaced by a fixed price agreement in January 2004 and then a modified cost and index-based agreement in September 2005.
Our coal revenues include amounts earned by our coal sales company from sales of coal produced by mines other than ours. In 2006, 2005 and 2004, such amounts were $5.6 million, $9.8 million and $5.8 million, respectively.
In 2006, our three largest contracts, with the owners of Colstrip Units 1&2, Colstrip Units 3&4 and Limestone Generating Station, accounted for 11%, 23% and 29%, respectively, of our coal revenues. No other contract accounted for as much as 10% of our coal revenues in 2006.
As part of our strategy, we seek long-term coal sales contracts. These contracts typically contain price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised. The price may be adjusted in accordance with changes in broad economic indicators, such as the consumer price index; commodity-specific indices, such as the Producer Price Index-light fuel oils; and/or changes in our actual costs. Contracts may also contain periodic price reopeners, or renewal provisions, which give us the opportunity to adjust the price of our coal to reflect developments in the marketplace.
The following table presents our estimate of the sales under our existing long-term contracts for the next five years. The prices for all of these tons are subject to revision and adjustments based upon market prices, indices and/or cost recovery. We also expect to continue to supply customers whose contracts expire before the end of 2011 but have not included those tonnages in this projection.
This table reflects existing contracts only and takes into account the scheduled outages at our customers’ plants, where known. We anticipate replacing sales as contracts expire with extensions, new contracts, or spot sales over the life of our coal reserves. The above figures exclude the new agreement with Colstrip Units 1&2, pursuant to which we estimate that we will supply approximately 3 million tons per year commencing 2010, since the contract was signed in March 2007.
Protecting the Environment
We consider ourselves stewards of the environment. We reclaim the areas that we mine, and we believe that our activities have been in compliance with all federal, state, and local laws and regulations.
Our reclamation activities consist of filling the voids created during coal removal, replacing sub-soils and top-soils and then re-establishing the vegetative cover. At the conclusion of our reclamation activities the area disturbed by our mining will look similar to what it did before we mined. Before we are released from all liability under our permits, we will have restored the area where we removed coal to a productive state that meets or exceeds the non-mining use of the land before we mined.
We address the impacts our mining operations have on wildlife habitat and on sites with cultural significance. At the Jewett Mine, we preserve the nesting area of the Interior Least Tern, a bird threatened in the region. The Rosebud Mine has altered its mining plan to preserve Native American petroglyphs on rock formations. Similar culturally significant sites have been excavated by trained archeologists. Historic buildings on mine property have been moved to preserve them. We endeavor to operate as good environmental stewards, citizens, and neighbors.
Safety
Safety is our first priority. We maintain active safety programs involving all employees at all of our mines. Our mines focus on 100% compliance with safe practices, safety rules, and regulations.
In 2006, our mines performed better than the national average for surface mines. Based on data from the Mine Safety and Health Administration, an agency of the U.S. Department of Labor, our five mines had a lost-time incident rate of 1.36, compared to the national average of 1.53 for surface mines. Our value was
skewed higher due to disappointing performance at one mine. The Jewett and Savage mines completed the year without a lost time incident. Beulah and Absaloka had one incident each. The Rosebud Mine had 12 incidents during 2006. We have implemented a behavior-based safety program at the Rosebud Mine, to bring its safety record back to zero incidents, as we achieved in 2005 with all of our mines.
Independent Power Operations
Through Westmoreland Energy LLC and its direct and indirect subsidiaries, we own interests in three power-generating plants:
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100% of the interests in the 180 MW and 50 MW ROVA I and ROVA II coal-fired plants located in Weldon, North Carolina;
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a 4.49% interest in the Ft. Lupton Project, a 290 MW natural gas-fired plant located in Ft. Lupton, Colorado.
ROVA and the Ft. Lupton Project are each independent power projects. Independent power projects are power-generating plants that were not built by the regulated utility that purchases the plant’s output. We operate and maintain ROVA. We also operate and maintain four power projects that are owned by others.
ROVA purchases coal under a long-term contract with a fuel supplier. ROVA supplies steam under a long-term contract with a “steam host,” a business that uses the steam that is generated in the production of power. ROVA and Ft. Lupton supply power under long-term contracts with electric utilities, which purchase the power that the projects generate. The table below presents information about each of our projects.
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ROVA and Dominion Virginia Power can extend these contracts by mutual consent for five-year terms at mutually agreeable pricing.
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ROVA and Patch Rubber Company can extend these contracts for three successive five-year terms.
Like the power plants to which we sell coal, these projects compete with all other producers of electricity. ROVA is baseloaded. In 2006, ROVA I had a capacity factor of 90% and ROVA II had a capacity factor of
86%. A plant’s capacity factor is the ratio of the amount of electricity it produced to the amount of electricity it could produce if it operated at maximum output. ROVA I produced 1,303,000 MW hours in 2006; ROVA II produced 336,000 MW hours during the year. The Ft. Lupton Project is a “peaking” plant. It provides power only when the demand for electricity exceeds the output of baseloaded units. In 2006, Ft. Lupton produced 724,000 MW hours.
Other Activities
As part of our April 2001 acquisition of the coal business of Montana Power Company, we obtained the stock of North Central Energy Company (“North Central”). North Central owned property and mineral rights in southern Colorado. In 2003, North Central leased the rights to explore, drill, and produce coalbed methane gas to Petrogulf Corporation for $0.3 million and a royalty interest on production from wells drilled on North Central’s properties. Commercial production began in early 2004. In 2003, North Central sold certain surface and mineral property to local landowners for $1.4 million. North Central sold its undivided mineral interests including the royalty interest on coalbed methane production in 2006 for net proceeds of $5.1 million.
As part of the Montana Power transaction, we also acquired the stock of Horizon Coal Services, Inc. In February 2007, we sold Horizon’s only asset, a royalty interest in coal reserves located at the Caballo Mine in Wyoming, for $12.7 million.
Insurance Subsidiary
We have elected to retain some of the risks associated with operating our company. To do this, in 2002 we established a wholly-owned, consolidated insurance subsidiary, Westmoreland Risk Management Ltd., which provides our primary layer of property and casualty insurance. By using this insurance subsidiary, we have mitigated the effect of escalating property and casualty insurance premiums and retained some of the economic benefits of our excellent loss record, which has had minimal claims since we established the subsidiary. We have paid premiums at market rates into Westmoreland Risk Management, which as a result has cash reserves of $1.5 million after paying a $2.9 million dividend to the Company in 2006. We reduce our major exposure by insuring for losses in excess of our retained limits with a number of third party insurance companies. Westmoreland Risk Management is a Bermuda corporation. We have elected to report Westmoreland Risk Management as a taxable entity in the United States.
Except for the assets of Westmoreland Risk Management, all of our assets are located in the United States. We had no export sales and derived no revenues from outside the United States during the five-year period ended December 31, 2006, except for de minimis coal sales to a Canadian utility.
Seasonality
Our business is somewhat seasonal:
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The owners of the power plants to which we supply coal typically schedule maintenance for those plants in the spring and fall, when demand for electric power is typically less than it is during other seasons. For this reason, our coal revenues are usually higher in the winter and summer.
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ROVA also typically undergoes scheduled maintenance in the spring and fall, so our earnings from independent power are also lower in those seasons.
Government Regulation
Numerous federal, state and local governmental permits and approvals are required for mining and independent power operations. Both our coal mining business and our independent power operations are subject to extensive governmental regulation, particularly with regard to matters such as employee health and safety, and permitting and licensing requirements which cover all phases of environmental protection. The permitting process encompasses both federal and state laws, addressing reclamation and restoration of mined land and protection of hydrologic resources. Federal regulations also protect the benefits of current and retired coal miners.
We believe that our operations comply with all applicable laws and regulations, and it is our policy to operate in compliance with all applicable laws and regulations, including those involving environmental matters. However, because of extensive and comprehensive regulatory requirements, violations occur from time to time in the mining and independent power industries. None of the violations to date or the monetary penalties assessed upon us has been material.
Environmental Laws
We are subject to various federal, state and local environmental laws. Some of these laws, discussed below, place many requirements on our mines and the independent power plants in which we own interests.
Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act of 1977, or SMCRA, which is administered by the Office of Surface Mining Reclamation and Enforcement, or OSM, establishes mining, environmental protection and reclamation standards for all aspects of surface mining. OSM may delegate authority to state regulatory programs if they meet OSM standards. OSM has approved state regulatory programs in Montana, North Dakota and Texas, and these states’ regulatory agencies have assumed primacy in mine environmental protection and compliance. Mine operators must obtain permits issued by the state regulatory authority. OSM maintains oversight authority on the permitting and reclamation process. We endeavor to comply with approved state regulations and those of OSM through contemporaneous reclamation, maintenance and monitoring activities. Contemporaneous reclamation is reclamation conducted on a reasonably current basis following the mining of an area.
Each of our mining operations must obtain all required permits before any activity can occur. Under the states’ approved programs, an applicant for a permit must address requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation. While there may be some general differences between the states’ SMCRA-approved programs, they are all similar. A permit applicant must supply detailed information regarding its proposed operation including detailed studies of site-conditions before active mining begins, extensive mine plans that describe mining methods and impacts, and reclamation plans that provide for restoration of all disturbed areas. The state regulatory authority reviews the submission for compliance with SMCRA and generally engages in a process that involves critical comments designed to ensure regulatory compliance and successful reclamation. When the state is satisfied that the permit application satisfies the requirements of SMCRA, it will issue a permit. To ensure that the required final reclamation will be performed, the state requires the permit-applicant to post a bond that secures the reclamation obligation. The bond will remain in place until all reclamation has been completed.
SMCRA requires compliance with many other major environmental programs. These programs include the Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act or RCRA; and Comprehensive Environmental Response, Compensation, and Liability Act or CERCLA. Besides OSM, other Federal regulatory agencies are involved in monitoring or permitting specific aspects of mining operations. The Environmental Protection Agency, or EPA, is the lead agency for states or Indian Tribes with no authorized programs under the Clean Water Act, RCRA and CERCLA. The U.S. Bureau of Alcohol, Tobacco and Firearms, or ATF, regulates the storage, handling and use of explosives.
Clean Air Act. The Clean Air Act, the 1990 amendments to the Clean Air Act, which we call the Clean Air Act Amendments and the corresponding state laws that regulate air emissions affect our independent power interests and our mines both directly and indirectly. Direct impacts on coal mining and processing operations may occur through the Clean Air Act’s permitting requirements and/or emission control requirements. The Clean Air Act directly affects ROVA and indirectly affects our mines by extensively regulating the emissions from power plants into the air of particulates, fugitive dust, sulfur dioxide, nitrogen oxides and other compounds emitted by coal-fired generating plants.
Title IV of the Clean Air Act Amendments places limits on sulfur dioxide (“SO2”) emissions from power-generating plants and sets baseline emission standards for these facilities. The affected electricity generators have been able to meet these requirements by, among other ways, switching to lower sulfur fuels, installing
pollution control devices, such as flue gas desulphurization systems, which are known as “scrubbers,” reducing electricity generating levels or purchasing sulfur dioxide emission allowances. Power-generating plants receive sulfur dioxide emission allowances each year from the EPA, which the plants may use, trade or sell. ROVA is exempt from the Title IV SO2 program.
The Clean Air Act Amendments also require power plants that are major sources of nitrogen oxides in moderate or higher ozone non-attainment areas to install reasonably available control technology for nitrogen oxides, which are precursors of ozone. In addition, the EPA promulgated final rules that require coal-burning power plants in 19 Eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions beginning in May 2004. Installation of additional control measures required under the final rules will make it more costly to operate coal-fired generating plants. We discuss these rules below in more detail.
Clean Water Act. The Clean Water Act of 1972 affects coal mining operations by establishing the National Pollutant Discharge Elimination System, or NPDES, which sets standards for in-stream water quality and treatment for effluent and/or waste water discharges. Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water. States are also adopting anti-degradation regulations in which a state designates certain water bodies or streams as “high quality.” These regulations prohibit the diminution of water quality in these streams. Waters discharged from coal mines to high quality streams will be required to meet or exceed new high quality standards. The designation of high quality streams at our coal mines could require more costly water treatment and could aversely affect our coal production. We believe that all of our mines are in compliance with current discharge requirements.
Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, which was enacted in 1976, affects coal mining operations by establishing requirements for the treatment, storage and disposal of hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management. The EPA has also exempted coal combustion wastes from hazardous waste management under RCRA. Although coal combustion wastes disposed in surface impoundments and landfills or used as mine-fill are subject to regulation as non-hazardous wastes under RCRA, we do not anticipate that the regulation of coal combustion wastes will have any material effect on the amount of coal used by electricity generators so long as the EPA continues to exempt coal combustion wastes from hazardous waste management.
New Environmental Rules
Environmental laws and regulations are subject to change. In March 2005, the EPA adopted new rules that affect airborne emissions. Because different types of coal vary in their chemical composition and combustion characteristics, the new regulations could alter the relative competitiveness among coal suppliers and coal types.
Clean Air Interstate Rule. In the Clean Air Interstate Rule, or CAIR, the EPA required that 28 Eastern states and the District of Columbia reduce emissions of sulfur dioxide and nitrogen oxide. The EPA asserts that, when fully implemented, the CAIR will reduce SO2 emissions in these states by over 70% and nitrogen oxide emissions in those states by over 60% from 2003 levels. The CAIR covers the states in which ROVA; the principal customers of the Jewett and Absaloka mines, and one of the customers of the Rosebud Mine are located. According to the EPA, states will achieve the required emissions reductions using one of two options for compliance:
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A state may require power plants to participate in an EPA-administered interstate cap and trade system that caps emissions in two stages, or
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A state may meet an air emission budget specific to it through measures of the state’s choosing.
The EPA adopted the CAIR on March 10, 2005. The effect of the rule on the power industry is still uncertain, and at this time we are unable to determine how it might affect our business.
Mercury Rule. The EPA issued regulations pertaining to airborne emissions of mercury from power plants, known as the Clean Air Mercury Rule, on March 15, 2005. Each state must either adopt the EPA rule or adopt a rule as or more stringent than the EPA rule. Of the states in which we operate, Montana, North Dakota and North Carolina are considering or have adopted rules that are different from and, in some respects more stringent than, the EPA rule. Two states we serve, Minnesota and Virginia, have also adopted rules that differ from and may in practice be stricter than the EPA rule. Texas adopted the EPA rule. The EPA rule requires that emissions of mercury from power plants be reduced by 70% from 2000 levels by 2018. Stricter state rules may increase the reductions required, or advance the date by which reductions must occur, or both. Under the EPA program, each power plant will be required to hold mercury emissions allowances sufficient to cover the plant’s mercury emissions. EPA has established a two-phase nationwide cap on the total number of available allowances. The first phase cap applies each year from 2010-2017, and the second phase cap (which contains significantly fewer allowances) applies beginning in 2018. This “cap and trade” system, which allows the purchase of allowances to cover emissions, is the mechanism by which plants can obtain the necessary allowances to cover their annual emissions of mercury. New plants must also meet a strict new mercury emission standard in order to receive a permit to operate. We are unable at this time to determine how the federal or state regulations could affect the coal industry and our business.
Health and Benefits
Mine Safety and Health. Congress enacted the Coal Mine Health and Safety Act in 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. The states in which we operate have programs for mine safety and health regulation and enforcement. Our safety activities are discussed above.
Black Lung. Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees by payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973.
Coal Act. The Coal Industry Retiree Health Benefit Act of 1992 established three benefit plans:
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First, the statute merged the UMWA 1950 and 1974 Plans into the Combined Benefit Fund, or CBF. The CBF provides benefits to a closed pool of beneficiaries, retirees who were actually receiving benefits from either the 1950 or the 1974 Plan as of July 20, 1992. The Coal Act requires that the benefits provided to this group remain substantially the same as provided by the 1950 and 1974 Plans as of January 1, 1992.
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Second, the Coal Act requires companies, like our company, that had established individual employer plans, or IEPs, pursuant to prior collective bargaining agreements to maintain those IEPs and provide the beneficiaries a level of benefits substantially the same as they received as of January 1, 1992.
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Third, the Coal Act established the 1992 UMWA Benefit Plan which serves three distinct populations: miners who were eligible to retire as of February 1, 1993 and actually retired before September 30, 1992 and whose employers are no longer in business; miners receiving benefits under an IEP but whose former employer went out of business; and new spouses or new dependants of retirees in the CBF.
Workers’ Compensation. We are subject to various state laws where we have or previously had employees to provide workers’ compensation benefits. We were self-insured prior to and through December 31, 1995. Beginning in 1996, we purchased third party insurance for new workers’ compensation claims.
Independent Power
Many of the environmental laws and regulations described above, including the Clean Air Act Amendments, the Clean Water Act and RCRA, apply to our independent power plants as well as to our coal mining operations. These laws and regulations require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies. Meeting the requirements of each jurisdiction
with authority over a project can delay or sometimes prevent the completion of a proposed project, as well as require extensive modifications to existing projects. At ROVA, we are responsible for obtaining the required permits and complying with the relevant environmental laws. The operator of the Ft. Lupton project bears this responsibility.
On December 17, 1999, the EPA issued regulations under Section 126 of the Clean Air Act, which we call the Section 126 rule. The Section 126 rule requires combined nitrogen oxide reductions of 510,000 tons during each annual ozone season (May 1-September 30) from specified power stations in the Eastern United States, including ROVA. Each source is assigned a nitrogen oxide emissions allocation, and sources can reduce emissions to meet the allocation or purchase allowances.
North Carolina adopted regulations that required compliance with the new nitrogen oxide limits beginning in June 2004. ROVA is in compliance with these regulations. In 2000, ROVA installed a neural network in its boilers. The neural network increases boiler efficiency and reduces nitrogen oxide and carbon monoxide emissions. While the neural network reduces the level of nitrogen oxide and carbon monoxide emissions from ROVA, we are evaluating additional strategies for compliance with the Section 126 rule, including installation of additional pollution control equipment and/or emissions trading.
Employees
Including our subsidiaries, we directly employed 1,176 people on December 31, 2006, compared with 960 people on December 31, 2005. We acquired 136 employees in connection with the June 29, 2006 acquisition of the 50% interest in ROVA that we did not previously own and the contracts to operate and maintain the four other power projects. Westmoreland Coal Company is not party to any agreement with the United Mine Workers of America (“UMWA”), and its last agreement with the UMWA expired on August 1, 1998. However, our Western Energy subsidiary is party to an agreement with Local 400 of the International Union of Operating Engineers (“IUOE”). In addition, our Dakota Westmoreland and Westmoreland Savage subsidiaries assumed agreements with Local 1101 of the UMWA and Local 400 of the IUOE, respectively, when we purchased Knife River’s assets.
On March 6, 2007, the Company, WRI and Washington Group International (“WGI”) signed a comprehensive agreement. Pursuant to that agreement, WRI will terminate the WGI mining contract and assume direct responsibility for mining operations at the Absaloka Mine, and on March 30, 2007 will assume 142 additional employees from WGI.
Information about Segments
Please refer to Note 19 of the Consolidated Financial Statements for additional information about the segments of our business.
Available Information
Our Internet address is www.westmoreland.com. We do not intend for the information on our website to constitute part of this report. We make available, free of charge on or through our Internet website, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (“Exchange Act”), as soon as reasonably practicable after we file those materials electronically with, or furnish them to, the Securities and Exchange Commission.
ITEM 1A
ITEM 1A - RISK FACTORS
In addition to the trends and uncertainties described in Management’s Discussion and Analysis of Financial Condition and Results of Operations, we are subject to the risks set forth below.
Our coal mining operations are inherently subject to conditions that could affect levels of production and production costs at particular mines for varying lengths of time and could reduce our profitability.
Our coal mining operations are all surface mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production and increase the cost of mining at particular mines for varying lengths of time and negatively affect our profitability. These conditions or events include:
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unplanned equipment failures, which could interrupt production and require us to expend significant sums to repair our capital equipment, including our draglines, the large machines we use to remove the soil that overlies coal deposits;
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geological conditions, such as variations in the quality of the coal produced from a particular seam, variations in the thickness of coal seams and variations in the amounts of rock and other natural materials that overlie the coal that we are mining; and
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weather conditions.
Examples of recent conditions or events of these types include the following:
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During the first quarter of 2006, the dragline at the Absaloka Mine was unable to operate for almost six weeks, while we were repairing a broken walking shoe and its electrical systems.
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In the second quarter of 2005, our Beulah Mine experienced unusually heavy rainfall including record rainfall in June that adversely impacted overburden stability and resulted in highwall and spoil sloughage, a condition in which the side of the pit partially collapses and must be stabilized before mining can continue. Unstable conditions in the pits impacted dragline operations at that mine for a period of time. This resulted in a reduction in coal production during the quarter which negatively affected our financial results for the third and fourth quarter of 2005.
Our revenues and profitability could suffer if our customers reduce or suspend their coal purchases.
In 2006, we sold approximately 98% of the coal we produced under long-term agreements, with approximately 2% on a spot basis to utilities and shorter-term industrial/institutional sales. Three of our contracts, with the owners of the Limestone Generating Station, Colstrip Units 3&4 and Colstrip Units 1&2, accounted for 29%, 23% and 11%, respectively, of our coal revenues for 2006. Interruption in the purchases by or operations of our principal customers could significantly affect our revenues and profitability. Unscheduled maintenance outages at our customers’ power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. Four of our five mines are dedicated to supplying customers located adjacent to or near the mines, and these mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.
Disputes relating to our coal supply agreements could harm our financial results.
From time to time, we may have disputes with customers under our coal supply agreements. These disputes could be associated with claims by our customers that may affect our revenue and profitability. Any dispute that resulted in litigation could cause us to pay significant legal fees, which could also affect our profitability.
We are a party to numerous legal proceedings, some of which, if determined unfavorably to us, could result in significant monetary damages.
We are a party to several legal proceedings which are described more fully in Note 18 (“Contingencies”) to our Consolidated Financial Statements. Adverse outcomes in some or all of the pending cases could result in substantial damages against us or harm our business.
We may not be able to manage our expanding operations effectively, which could impair our profitability.
At the end of 2000, we owned one mine and employed 31 people. In the spring of 2001, we acquired the Rosebud, Jewett, Beulah and Savage mines. In June 2006, we acquired the half of ROVA that we did not previously own, and we also acquired contracts to operate and maintain ROVA and four other independent power projects. At the end of 2006, we employed 1,176 people, including employees at our subsidiaries. This growth has placed significant demands on our management as well as our resources and systems. One of the principal challenges associated with our growth has been, and we believe will continue to be, our need to attract and retain highly skilled employees and managers. If we are unable to attract and retain the personnel we need to manage our increasingly large and complex operations, our ability to manage our operations effectively and to pursue our business strategy could be compromised.
The implementation of a new company-wide computer system could disrupt our internal operations.
We are in the process of implementing a new company-wide computer system to replace the various systems that have been in place at our corporate offices, at the operations we owned in 2001, and at the operations we acquired in 2001 and in 2006. Once implementation is fully complete, we expect this system to help establish standard, uniform, best practices and reporting in a number of areas, increase productivity and efficiency, and enhance management of our business. Certain aspects of our information technology infrastructure and operational activities have and may continue to experience difficulties in connection with this transition and implementation. Such difficulties can cause delay, be time consuming and more resource intensive than planned, and cost more than we anticipated. There can be no assurance that we will achieve the efficiencies and cost savings intended from this project.
Our growth and development strategy could require significant resources and may not be successful.
We regularly seek opportunities to make additional strategic acquisitions, to expand existing businesses, to develop new operations and to enter related businesses. We may not be able to identify suitable acquisition candidates or development opportunities, or complete any acquisition or project, on terms that are favorable to us. Acquisitions, investments and other growth projects involve risks that could harm our operating results, including difficulties in integrating acquired and new operations, diversions of management resources, debt incurred in financing such activities and unanticipated problems and liabilities. We anticipate that we would finance acquisitions and development activities by using our existing capital resources, borrowing under existing bank credit facilities, issuing equity securities or incurring additional indebtedness. We may not have sufficient available capital resources or access to additional capital to execute potential acquisitions or take advantage of development opportunities.
Our expenditures for postretirement medical benefits could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.
We provide various postretirement medical benefits to current and former employees and their dependents. We estimate the amounts of these obligations based on assumptions described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Estimates and Related Matters” herein. See Note 7 to the Consolidated Financial Statements for more detail. We accrue amounts for these obligations, which are unfunded, and we pay as costs are incurred. If our assumptions change, the amount of our obligations could increase, and if our assumptions are inaccurate, we could be required to expend greater amounts than we anticipate. We regularly revise our estimates, and the amount of our accrued obligations is subject to change.
We have a significant amount of debt, which imposes restrictions on us and may limit our flexibility, and a decline in our operating performance may materially affect our ability to meet our future financial commitments and liquidity needs.
As of December 31, 2006, our total gross indebtedness was approximately $306.0 million, the principal components of which are: $13.0 million of corporate revolving lines of credit, $95.1 million of Westmoreland Mining term debt, $162.9 million of ROVA term debt (which includes $4.9 million of debt premiums), and $35.0 million of ROVA acquisition debt. We may incur additional indebtedness in the future, including indebtedness under our two existing revolving credit facilities.
Westmoreland Mining’s term loan agreement restricts its ability to distribute cash to Westmoreland Coal Company through 2011 and limits the types of transactions that Westmoreland Mining and its subsidiaries can engage in with Westmoreland Coal Company and our other subsidiaries. Westmoreland Mining executed the term loan agreement, which we refer to as Westmoreland Mining’s acquisition debt, in 2001 and used the proceeds to finance its acquisition of the Rosebud, Jewett, Beulah and Savage mines. The final payment on this indebtedness, is $30.0 million and is due on December 31, 2008. Until December 31, 2008, 25% of Westmoreland Mining’s surplus cash flow is dedicated to an account to fund this final payment. In 2004, Westmoreland Mining incurred an additional $35.0 million of indebtedness, which we call the add-on facility. The add-on facility is scheduled to be paid-down from 2009 through 2011. Westmoreland Mining has pledged or mortgaged substantially all of its assets and the assets of the Rosebud, Jewett, Beulah and Savage mines, and we have pledged all of our interests in Westmoreland Mining as security for Westmoreland Mining’s indebtedness. In addition, Westmoreland Mining must comply with financial ratios and other covenants specified in the agreements with its lenders.
Substantial debt was incurred to finance ROVA’s development. At December 31, 2006, ROVA owed $158.0 million to its lenders. Substantially all of ROVA’s assets are pledged to secure the repayment of this debt. We incurred indebtedness of $35 million in June 2006, in connection with our acquisition of the 50% interest in ROVA that we did not previously own. To secure the repayment of this debt, we have pledged the semi-annual cash distributions from ROVA commencing in January 2007 and the interests in our subsidiaries that operate and maintain ROVA and four other independent power projects. ROVA’s debt agreements also contain various restrictive covenants primarily related to construction of the facilities, maintenance of the property, and required insurance. Additionally, the ROVA financial covenants include restrictions on incurring additional indebtedness and property liens, paying cash distributions to the partners, and incurring various commitments without lender approval.
Failure to comply with the ratios and covenants in Westmoreland Mining’s or ROVA’s debt agreements, or to make regular payments of principal and interest could result in an event of default.
A substantial portion of our cash flow must be used to pay principal and interest on our indebtedness and is not available to fund working capital, capital expenditures or other general corporate uses. In addition, the degree to which we are leveraged could have other important consequences, including:
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increasing our vulnerability to general adverse economic and industry conditions;
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limiting our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements; and
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limiting our flexibility in planning for, or reacting to, changes in our business and in the industry.
If our or Westmoreland Mining’s operating performance declines, or if we or Westmoreland Mining do not have sufficient cash flows and capital resources to meet our debt service obligations, we or Westmoreland Mining may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. If Westmoreland Mining were to default on its debt service obligations, a note holder may be able to foreclose on assets that are important to our business.
ROVA’s credit agreement restricts its ability to distribute cash, contains financial ratios and other covenants, and is secured by a pledge of the project and substantially all of the project’s assets. If ROVA fails to comply with these ratios and covenants or fails to make regular payments of principal and interest, an event
of default could occur. A substantial portion of ROVA’s cash flow must be used to pay principal and interest on its indebtedness and is not available to us. If ROVA were to default on its debt service obligations, a creditor may be able to foreclose on assets that are important to our business.
If the cost of obtaining new reclamation bonds and renewing existing reclamation bonds continues to increase or if we are unable to obtain additional bonding capacity, our profitability could be reduced.
Federal and state laws require that we provide bonds to secure our obligations to reclaim lands used for mining. We must post a bond before we obtain a permit to mine any new area. These bonds are typically renewable on a yearly basis and have become increasingly expensive. Bonding companies are requiring that applicants collateralize a portion of their obligations to the bonding company. In 2006, we paid approximately $2.6 million in premiums for reclamation bonds. We anticipate that, as we permit additional areas for our mines in 2007 and 2008, 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 companies is not available to support our other business activities. If the cost of our reclamation bonds continues to increase, our profitability could be reduced. Additionally, if we are unable to obtain additional bonding capacity, it could reduce our ability to begin mining operations in newly permitted areas, or continue in existing areas if increased bond demands cannot be met, and our profitability could be reduced.
Our financial position could be adversely affected if we fail to maintain our Coal Act bonds.
The Coal Act established the 1992 UMWA Benefit Plan, or 1992 Plan. We were required to secure approximately three years of our obligations to that plan by posting a surety bond or a letter of credit or collateralizing our obligations with cash. At December 31, 2006, we secured these obligations with two bonds, one in an amount of approximately $21.3 million with XL Specialty Insurance Company (“XL”) and affiliates, and another in the amount of approximately $4.0 million.
As a result of amendments to the Coal Act that were signed into law on December 20, 2006, we are now required to secure only one year of our obligations to the 1992 Plan. This reduced the amount of security we are required to post from approximately $25.3 million to approximately $8.8 million. In response to this reduction, in early 2007 we reduced our $4.0 million bond to $0.3 million and reduced the bond provided by XL from approximately $21.3 million to $9.0 million, which exceeds the requirement of $8.5 million.
In December 2003, XL indicated a desire to exit the business of bonding Coal Act obligations. Although we believe that XL must continue to renew our bond so long as we do not default on our obligations to the 1992 Plan, XL filed a Complaint for Declaratory Judgment on May 11, 2005 to force our payment of $21.3 million (now $9.0 million) and to cancel the bond. If XL were to cancel or fail to renew our bond, we may be required to post another bond or secure our obligations with a letter of credit or cash. At this time, we are not aware of any other company that would provide a surety bond to secure obligations under the Coal Act, without cash collateral. If the Company were to collateralize a new bond or letter of credit with $9.0 million of cash, it would have a material effect on the Company’s liquidity.
We face competition for sales to new and existing customers, and the loss of sales or a reduction in the prices we receive under new or renewed contracts would lower our revenues and could reduce our profitability.
Approximately one-third of the coal tonnage that we will produce in 2007 will be sold under long-term contracts to power plants that take delivery of our coal from common carrier railroads. Most of the Absaloka Mine’s sales are delivered by rail and about 20% of the sales from each of the Rosebud Mine and Beulah Mine are delivered by rail. Contracts covering 60% of those rail tons are scheduled to expire between January 2007 and December 2008. As a general matter, plants that take coal by rail can buy their coal from many different suppliers. We will face significant competition, primarily from mines in the Southern Powder River Basin of Wyoming, to renew our long-term contracts with our rail-served customers, and for contracts with new rail-served customers. Many of our competitors are larger and better capitalized than we are and have coal with a lower sulfur and ash content than our coal. As a result, our competitors may be able to adopt more
aggressive pricing policies for their coal supply contracts than we can. If our existing customers fail to renew their contracts with us on terms that are at least equivalent to those in effect today, or if we are unable to replace our existing contracts with contracts of equal size and profitability from new customers, our revenues and profitability would be reduced.
Approximately two-thirds of the coal tonnage that we will sell in 2007 will be delivered under long-term contracts to power plants located adjacent to our mines. We will face somewhat less competition to renew these contracts upon their expiration, both because of the transportation advantage we enjoy by being located adjacent to these customers and because most of these customers would be required to invest additional capital to obtain rail access to alternative sources of coal. Our Jewett Mine is an exception because our customer has already built rail unloading and associated facilities that are being used to receive coal from the Southern Powder River Basin as permitted under our contract with that customer.
Stricter environmental regulations, including regulations recently adopted by the EPA, could reduce the demand for coal as a fuel source and cause the volume of our sales to decline.
Coal contains impurities, including sulfur, mercury, nitrogen and other elements or compounds, many of which are released into the air when coal is burned. Stricter environmental regulation of emissions from coal-fired electric generating plants could increase the costs of using coal, thereby reducing demand for coal as a fuel source generally, and could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future. The U.S. Environmental Protection Agency, or EPA, adopted regulations in March 2005, that could increase the costs of operating coal-fired power plants, including ROVA. Congress has considered legislation that would have this same effect. At this time, we are unable to predict the impact of these new regulations on our business. However, we expect that the new regulations may alter the relative competitiveness among coal suppliers and coal types. The new regulations could also disadvantage some or all of our mines, and notwithstanding our coal supply contracts we could lose all or a portion of our sales volumes and face increased pressure to reduce the price for our coal, thereby reducing our revenues, our profitability and the value of our coal reserves.
In March 2005, the EPA issued the Clean Air Interstate Rule (“CAIR”) and Clean Air Mercury Rule (“CAMR”). The CAIR will reduce emissions of sulfur dioxide and nitrogen oxide in 28 Eastern States and the District of Columbia. Texas and Minnesota, in which customers of the Jewett and Absaloka mines are located, and North Carolina, where ROVA is located, are subject to the CAIR. The CAIR requires these States to achieve required reductions in emissions from electric generating units, or EGUs, in one of two ways: (1) through participation in an EPA-administered, interstate “cap and trade” system that caps emissions in two stages, or (2) through measures of the State’s choice. Under the cap and trade system, the EPA will allocate emission “allowances” for nitrogen oxide to each State. The 28 States will distribute those allowances to EGUs, which can trade them. To control sulfur dioxide, the EPA will reduce the existing allowance allocations for sulfur dioxide that are currently provided under the acid rain program established pursuant to Title IV of the Clean Air Act Amendments. EGUs may choose among compliance alternatives, including installing pollution control equipment, switching fuels, or buying excess allowances from other EGUs that have reduced their emissions. Aggregate sulfur dioxide emissions are to be reduced from 2003 levels in two stages, a 45% reduction by 2010 and a 57% reduction by 2015. Aggregate nitrogen oxide emissions are also to be reduced from 2003 levels in two stages, a 53% reduction by 2009 and a 61% reduction by 2015.
The CAMR applies to all States. The CAMR establishes a two-stage, nationwide cap on mercury emissions from coal-fired EGUs. Aggregate mercury emissions are to be reduced from 1999 levels in two stages, a 20% reduction by 2010 and a 70% reduction by 2018. The EPA expects that, in the first stage, emissions of mercury will be reduced in conjunction with the reductions of sulfur dioxide and nitrogen oxide under the CAIR. The EPA has assigned each State an emissions “budget” for mercury, and each state must submit a State Plan detailing how it will meet its budget for reducing mercury from coal-fired EGUs. Again, States may participate in an interstate “cap and trade” system or achieve reductions through measures of the States’ choice. The CAMR also establishes mercury emissions limits for new coal-fired EGUs (new EGUs are power plants for which construction, modification, or reconstruction commenced after January 30, 2004). Of the states in which we operate, Montana, North Dakota and North Carolina are considering or have adopted
rules that are different from and, in some respects more stringent than, the EPA rule. Two states we serve, Minnesota and Virginia, have also adopted rules that differ from and may in practice be stricter than the EPA rule. Texas adopted the EPA rule.
These new rules are likely to affect the market for coal for at least three reasons:
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Different types of coal vary in their chemical composition and combustion characteristics. For example, the lignite from our Jewett and Beulah mines is inherently higher in mercury than bituminous and sub-bituminous coal, and sub-bituminous coal from different seams can differ significantly.
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Different EGUs have different levels of emissions control technology. For example, ROVA has “state of the art” emissions control technology that reduces its emissions of sulfur dioxide, nitrogen oxide and, collaterally, mercury.
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The CAIR is likely to affect the existing national market for sulfur dioxide emissions allowances, thereby indirectly affecting coal producers and consumers that are not directly subject to the CAIR.
For all the foregoing reasons, and because it is unclear how states will allocate their emissions budgets, we are unable to predict at this time how these new rules will affect the Company.
The Company’s contracts protect our sales positions, including volumes and prices, to varying degrees. However, we could face disadvantages under the new regulations that could result in our inability to renew some or all of our contracts as they expire or reach scheduled price reopeners or that could result in relatively lower prices upon renewal, thereby reducing our relative revenue, profitability, and/or the value of our coal reserves.
New legislation or regulations in the United States aimed at limiting emissions of greenhouse gases could increase the cost of using coal or restrict the use of coal, which could reduce demand for our coal, cause our profitability to suffer and reduce the value of our assets.
A variety of international and domestic environmental initiatives are currently aimed at reducing emissions of greenhouse gases, such as carbon dioxide, which is emitted when coal is burned. If these initiatives were to be successful, the cost to our customers of using coal could increase, or the use of coal could be restricted. This could cause the demand for our coal to decrease or the price we receive for our coal to fall, and the demand for coal generally might diminish. Restrictions on the use of coal or increases in the cost of burning coal could cause us to lose sales and revenues, cause our profitability to decline or reduce the value of our coal reserves.
Demand for our coal could also be reduced by environmental regulations at the state level.
Environmental regulations by the states in which our mines are located, or in which the generating plants they supply operate, may negatively affect demand for coal in general or for our coal in particular. For example, Texas passed regulations requiring all fossil fuel-fired generating facilities in the state to reduce nitrogen oxide emissions beginning in May 2003. In January 2004, we entered into a supplemental settlement agreement with NRGT pursuant to which the Limestone Station must purchase a specified volume of lignite from the Jewett Mine. In order to burn this lignite without violating the Texas nitrogen oxide regulations, the Limestone Station is blending our lignite with coal produced by others in the Southern Powder River Basin, and using emissions credits. Considerations involving the Texas nitrogen oxide regulations might affect the demand for lignite from the Jewett Mine in the period after 2007, which is the last year covered by the four-year fixed price agreement. Notwithstanding our contractual right to deliver approximately 6.7 million tons per year, NRGT might claim that it is less expensive for the Limestone Station to comply with the Texas nitrogen oxide regulations by switching to a blend that contains relatively more coal from the Southern Powder River Basin and relatively less of our lignite. Other states are evaluating various legislative and regulatory strategies for improving air quality and reducing emissions from electric generating units. Passage of other state-specific environmental laws could reduce the demand for our coal.
We have significant reclamation and mine closure obligations. If the assumptions underlying our accruals are materially inaccurate, or if we are required to cover reclamation obligations that have been assumed by our customers or contractors, we could be required to expend greater amounts than we currently anticipate, which could affect our profitability in future periods.
As the permittee, we are responsible under federal and state regulations for the ultimate reclamation of the mines we operate. In some cases, our customers and contractors have assumed these liabilities by contract and have posted bonds or have funded escrows to secure their obligations. We estimate our future liabilities for reclamation and other mine-closing costs from time to time based on a variety of assumptions. If our assumptions are incorrect, we could be required in future periods to spend more on reclamation and mine-closing activities than we currently estimate, which could harm our profitability. Likewise, if our customers or contractors default on the unfunded portion of their contractual obligations to pay for reclamation, we could be forced to make these expenditures ourselves and the cost of reclamation could exceed any amount we might recover in litigation, which would also increase our costs and reduce our profitability.
We estimate that our reclamation and mine-closing liabilities, which are based upon projected mine lives, current mine plans, permit requirements and our experience, were $184.1 million (on a present value basis) at December 31, 2006. Of these December 31, 2006 liabilities, our customers have assumed $42.0 million by contract. Responsibility for the final reclamation amounts may change in certain circumstances. At the Jewett Mine, if there is a cessation of mining the customer assumes responsibility for all reclamation and they have provided a corporate guarantee to the Railroad Commission of Texas in support of their responsibility. At December 31, 2006, if there had been a cessation of mining at the Jewett Mine, for example, the customer would have assumed responsibility for approximately $37.1 million (on a present value basis) of the reclamation obligation that is currently reflected as the responsibility of the Company. We estimate that our obligation for final reclamation that is not the contractual responsibility of others was $142.1 million at December 31, 2006. We held funding reclamation escrow accounts of approximately $62.5 million at December 31, 2006 with respect to those obligations. The remainder of the $142.1 million estimated obligation must be recovered in the price of coal shipped or from other sources.
Our profitability could be affected by unscheduled outages at the power plants we supply or own or if the scheduled maintenance outages at the power plants we supply or own last longer than anticipated.
Scheduled and unscheduled outages at the power plants that we supply could reduce our coal sales and revenues, because any such plant would not use coal while it was undergoing maintenance. We cannot anticipate if or when unscheduled outages may occur.
Our profitability could be affected by unscheduled outages at ROVA or if scheduled outages at ROVA last longer than we anticipate.
Increases in the cost of the fuel, electricity and materials and the availability of tires we use in the operation of our mines could affect our profitability.
Under several of our existing coal supply agreements, our mines bear the cost of the diesel fuel, lubricants and other petroleum products, electricity, and other materials and supplies necessary to operate their draglines and other mobile equipment. The cost of tires for our heavy equipment at the mines increased drastically in 2005 and 2006 as the supply tightened due to world-wide demand, which impacts productivity and could even reduce production if replacement tires are not available. The prices of many other commodities we use have increased significantly in the last year, and continued escalation of these costs would hurt our profitability or threaten the financial condition of our operations in the absence of corresponding increases in revenue.
If we experience unanticipated increases in the capital expenditures we expect to make over the next several years, our liquidity and/or profitability could suffer.
Some of our contracts provide for our customers to reimburse us for our capital expenditures on a depreciation and amortization basis, plus in some instances, a stated return-on-investment. Other contracts provide reimbursement of capital expenditures in full as such expenditures are incurred. Other contracts feature
set prices that adjust only for changes in a general inflation index. When we spend capital at our operations, it affects our near term liquidity in most instances and if capital is spent where the customer is not specifically obligated to reimburse us, that capital could be at risk if market conditions and contract duration do not match up to the investment.
Our ability to operate effectively and achieve our strategic goals could be impaired if we lose key personnel.
Our future success is substantially dependent upon the continued service of our key senior management personnel, particularly Christopher K. Seglem, our Chairman of the Board, President and Chief Executive Officer. We do not have key-person life insurance policies on Mr. Seglem or any other employees. The loss of the services of any of our executive officers or other key employees could make it more difficult for us to pursue our business goals.
Provisions of our certificate of incorporation, bylaws and Delaware law, and our stockholder rights plan, may have anti-takeover effects that could prevent a change of control of our company that stockholders may consider favorable, and the market price of our common stock may be lower as a result.
Provisions in our certificate of incorporation and bylaws and Delaware law could make it more difficult for a third party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our bylaws impose various procedural and other requirements that could make it more difficult for stockholders to bring about some types of corporate actions. In addition, a change of control of our Company may be delayed or deterred as a result of our stockholder rights plan, which was initially adopted by our Board of Directors in early 1993 and amended and restated in February 2003. Our ability to issue preferred stock in the future may influence the willingness of an investor to seek to acquire our company. These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control of Westmoreland.
Our ability to operate effectively and achieve our strategic goals depends on maintaining satisfactory labor relations.
A significant portion of the workforce at each of the Company-operated mines, except Jewett, is represented by labor unions. While we believe that our relationships with our employees at the mines are satisfactory, the nature of collective bargaining is such that there is a risk of a disruption in operations when any collective bargaining agreement reaches its expiration date unless a renewal or extension has been accepted by the employees who are covered by the agreement. While labor strikes are generally a force majeure event in long-term coal supply agreements, thereby exempting the mine from its delivery obligations, the loss of revenue for even a short period of time could have a material adverse effect on the Company’s financial results.
We have had material weaknesses in internal control over financial reporting in the past and cannot assure that additional material weaknesses will not be identified in the future. Our failure to maintain effective internal control over financial reporting could result in material misstatements in our financial statements which could require us to restate financial statements, cause investors to lose confidence in our reported financial information and have a negative effect on our stock price.
During 2005, the Company identified five material weaknesses in internal controls over financial reporting as defined in the Public Company Accounting Oversight Board’s Auditing Standard No. 2. In 2006, we believe we remediated four of the five material weaknesses. The material weaknesses in our internal control over financial reporting are described in our Amendment No. 1 to Form 10-K for 2005 and in this 2006 Form 10-K under “Item 9A - Controls and Procedures”.
We cannot assure that additional significant deficiencies or material weaknesses in our internal control over financial reporting will not be identified in the future. Any failure to maintain or implement new or improved controls, or any difficulties we encounter in their implementation, could result in additional
significant deficiencies or material weaknesses, and cause us to fail to meet our periodic reporting obligations or result in material misstatements in our financial statements. Any such failure could also adversely affect the results of periodic management evaluations and annual auditor attestation reports regarding the effectiveness of our internal control over financial reporting required under Section 404 of the Sarbanes-Oxley Act of 2002 and the rules promulgated under Section 404. The existence of a material weakness could result in errors in our financial statements that could result in a restatement of financial statements, cause us to fail to meet our reporting obligations and cause investors to lose confidence in our reported financial information, leading to a decline in our stock price.
We may face risks related to an SEC investigation and securities litigation in connection with the restatement of our financial statements.
On March 6, 2007 we were informed that the Denver office of the Securities and Exchange Commission (“SEC”) has begun an informal inquiry in connection with accounting errors requiring restatement of 2005 and prior years’ financial statements, including 2004 and 2005 quarterly financial statements. We are not aware that any laws have been violated. If the SEC makes a determination that the Company has violated Federal securities laws, the Company may face sanctions, including, but not limited to, monetary penalties and injunctive relief, which could adversely affect our business. In addition, the Company or its officers and directors could be named defendants in civil proceedings arising from the restatement. We are unable to estimate what our liability in either event might be. However, we believe that the sanctions imposed by the SEC, if any, will not have a material effect on the Company because, in the judgment of management after due inquiry, there was no fraud, financial manipulation or other intentional misconduct relating to the restatement or otherwise.
ITEM 1B
ITEM 1B - UNRESOLVED STAFF COMMENTS
None
ITEM 2
ITEM 2 - PROPERTIES
We operate mines in Montana, Texas, and North Dakota. All of these mines are surface (open-pit) mines. These properties contain coal reserves and coal deposits. A “coal reserve” is that part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination. Coal does not qualify as a “coal reserve” until, among other things, we conduct a final comprehensive evaluation based upon unit cost per ton, recoverability, and other material factors and conclude that it is legally and economically feasible to mine the coal.
We include in “coal reserves” 216.5 million tons that are not fully permitted but that otherwise meet the definition of “coal reserves.” Montana, Texas, and North Dakota each use a permitting process approved by the Office of Surface Mining. We describe the permitting process above in Item 1, under “Governmental Regulation,” and we explain our assessment of that process as applied to these unpermitted tons below.
All of our final reclamation obligations are secured by bonds as required by the respective state agencies. Contemporaneous reclamation activities are performed at each mine in the normal course of operations and coal production.
The following table provides information about our mines as of December 31, 2006:
(1)
Proven coal reserves are reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling; and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. In addition, all coal reserves are “assigned” coal reserves: coal that we have committed to operating mining equipment and plant facilities.
(2)
Includes tons for each mine as described below that are not fully permitted but otherwise meet the definition of “proven” coal reserves.
(3)
Probable reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling, and measurement are farther
apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.
(4)
We have assigned all proven reserves to operating mining equipment and plant facilities.
(5)
Approximate heat content applies to the coal mined in 2006.
(6)
Approximate sulfur content applies to the tons mined in 2006.
(7)
Initial sales from the current mine complex began in 1968. Mining first occurred at the site in 1924.
We lease all our coal properties except at the Jewett Mine, where some reserves are controlled through fee ownership. We believe that we have satisfied all conditions that we must meet in order to retain the properties and keep the leases in force.
Absaloka Mine
Our WRI subsidiary began constructing the mine in late 1972. Construction was completed in early 1974. WRI has been the mine’s only owner.
The Absaloka Mine’s primary excavating machine (completed in 1979) is a dragline with a bucket capacity of 110 cubic yards. WRI owns the dragline. The Absaloka Mine’s facilities consist of a truck dump, primary and secondary crushers, conveyors, coal storage barn, train loadout, rail loop, shop, warehouse, boiler house, deep well and water treatment plant, and other support facilities. These facilities date from the construction of the mine. WRI’s mining contractor and minority stockholder owned most of the other equipment at the mine until March 30, 2007.
We believe that all the coal reserves shown in the table above for the Absaloka Mine are recoverable through the Absaloka Mine’s existing facilities with current technology and the existing infrastructure. These reserves were estimated to be 800 million tons as of January 1, 1980, based principally upon a report by IntraSearch, Inc., an independent firm of consulting geologists, prepared that year.
WRI leases all of its coal reserves from the Crow Tribe of Indians. The lease runs until exhaustion of the mineable and merchantable coal in the acreage subject to the lease. In February 2004, WRI reached an agreement with the Crow Tribe to explore and develop additional acreage located on the Crow reservation immediately adjacent to the Absaloka Mine. This agreement was approved by the U.S. Department of the Interior in September 2004 and the initial exploration core drilling was completed in 2004 in order to fully prove the coal reserves. Further core drilling was completed in the fall of 2005 for final mine plan development and permit submittal.
At December 31, 2006, Washington Group was contractually responsible for reclaiming the Absaloka Mine, whatever the cost, except for $2.6 million, which was the responsibility of WRI. WRI had reclamation bond collateral in place for its share of the reclamation obligations at December 31, 2006. Washington Group was also contractually obligated to fund a reclamation escrow account or post security for its reclamation obligation, and WRI was responsible for maintaining and monitoring the reclaimed property until the release of the reclamation bond. On March 6, 2007, the Company, WRI and Washington Group signed a comprehensive agreement. Pursuant to that agreement, WRI will terminate the WGI mining contract and assume direct responsibility for mining operations at the Absaloka Mine, purchase WGI’s equipment, undertake mining operations, and assume all liability for reclaiming the mine, effective March 30, 2007. In addition, pursuant to the agreement, Washington Group will transfer approximately $7.0 million in a reclamation escrow account to WRI, WRI will pay Washington Group approximately $4 million, and the parties will terminate all the litigation between them.
Of the 95.1 million tons shown for the Absaloka Mine in the table above as proven and probable coal reserves, 74.6 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” WRI has chosen to permit coal reserves on an incremental basis and currently has sufficient permitted coal to meet production, given the current rate of mining and demand, through 2009. In Montana, the Department of Environmental Quality (DEQ) regulates surface mining and issues mining permits under its OSM-approved program. In Montana, it typically takes two to four years from the time an initial application is filed to obtain
a new permit. WRI filed an application with DEQ covering an estimated 25 million tons of unpermitted reserves in June 2004, expanding the mine into Tract III South. The permit application for the first 14.4 million tons of the Tract III South reserve was approved in July 2006. Based upon the current status of the application for the remaining tons in the Tract III South reserve, and our knowledge of the permitting process in Montana and the Tract III South reserves, we expect approval for the remaining tons near the end of 2007, as required to meet production requirements.
The operator of the Absaloka Mine purchases electric power under a long-term contract with NorthWestern Energy, the local utility. The mine is accessed from Route 384 via County Road 42.
Rosebud Mine
The Northern Pacific Railroad began mining coal for its steam locomotives at Colstrip in 1924 and continued to do so until 1958. In 1959, the Montana Power Company purchased the property. Montana Power formed Western Energy Company in 1966 and began selling coal to customers in 1968. Colstrip Station Units 1&2 entered commercial operation in 1975 and 1976. The long-term contracts required for this plant provided the foundation for a major expansion of the Rosebud Mine. We acquired the stock of Western Energy in 2001.
The Rosebud Mine’s primary excavating machines are four draglines, three with bucket-capacities of 60 cubic yards, purchased in 1975, 1976, and 1980, and one with a bucket-capacity of 80 cubic yards, purchased in 1983. The Rosebud Mine’s facilities consist of truck dumps, crushing, storage, and conveying systems, a rail loadout, rail loop, shops, warehouses, and other support facilities. These facilities date from 1974.
We estimate that the Rosebud Mine had coal reserves of 230.1 million tons as of December 31, 2006. This estimate is based on a study of the Rosebud Mine’s reserves dated October 1, 2005 conducted by Western Energy and adjusted for tons mined since that date. We believe that all of these reserves are recoverable through the Rosebud Mine’s existing facilities with current technology and the existing infrastructure.
We are responsible for performing reclamation activities at the Rosebud Mine. The owners of the Colstrip Station are responsible for paying the costs of reclamation relating to mine areas where their coal supply is produced. Several of the owners have satisfied these obligations by prefunding their respective portions of those costs.
Of the 230.1 million tons shown for the Rosebud Mine in the table above as proven coal reserves, 74.3 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” Western Energy has chosen not to permit all of the coal reserves in its mine plan because it already has sufficient coal in its current permitted mine plan, given the current rate of mining and demand for its production, through 2019. Based upon our current knowledge of the nature of the remaining reserves and the permitting process in Montana, we believe that there are no matters that would hinder Western Energy’s ability to obtain additional mining permits in the future.
The Rosebud Mine purchases electric power from NorthWestern Energy under regulated default supply pricing. Access to the mine is from Highway 39 via Castle Rock Road.
Jewett Mine
Development of the Jewett Mine began in 1979, when Northwestern Resources Co. and Utility Fuels, Inc. signed an agreement calling for production of “the most economic 240 million tons” from the project area to supply the planned Limestone Station. The coal reserves were evaluated through a series of exploration programs, including physical and chemical analysis, according to predetermined criteria. The Jewett Mine has been in continuous operation since 1985 and consists of five active areas with as many as four lignite seams within each area. Since 1979, ownership of the Limestone Station has been transferred several times, most recently to NRGT. We acquired the stock of Northwestern Resources in 2001 and renamed the company Texas Westmoreland Coal Company in 2004.
The Jewett Mine’s primary excavating machines consist of three walking draglines, each with a bucket-capacity of 84 cubic yards, one walking dragline with a bucket-capacity of 128 cubic yards, and one
bucketwheel excavator. The Jewett Mine’s facilities consist of a truck dump, crusher, conveyors, coal storage, shop/warehouse complex, administrative support buildings, and water treatment facilities. These facilities date from the construction of the mine. NRGT owns the draglines, the bucketwheel and a majority of the other mobile equipment used to extract lignite and provides this equipment to Texas Westmoreland without charge. Texas Westmoreland is obligated to maintain the draglines and all other plant and equipment so that they continue to be serviceable and support production comparable to the original specifications.
Exploration work for the mine commenced in the late 1970s, and Texas Westmoreland’s geologists and engineers prepared the initial estimates of the mine’s reserves at a time when Montana Power owned the Jewett Mine. To further define the coal reserve, exploration drilling was utilized to delineate that part of the reserve that could economically be mined. Through 2004, additional drilling was conducted from time to time to further define the limits of the coal seams. We believe that all the Jewett Mine’s coal reserves are recoverable through its existing facilities with current technology and the existing infrastructure.
Final reclamation of the Jewett Mine, at the end of its useful life, is the financial responsibility of its customer.
The Railroad Commission of Texas, or RCT, regulates surface mining in Texas and issues mining permits under its OSM-approved program. In Texas, it typically takes eighteen months to two years from the time an initial application is filed to obtain a new permit. A permit term encompasses five years of mining. The Jewett Mine currently holds two mining permits, 32F and 47. Permit 32F is a renewal of the original mining permit that has been in place and actively mined since the mine opened in 1985. This permit is valid through July 2008. A renewal of Permit 32 will be submitted in mid-2007 to extend Permit 32F until mid-2013. Permit 47 was issued in December 2001 and has a term that runs through December 2006. We filed a revision for Permit 47 in 2006. We sought to revise the permit and renew it for another five years. Upon approval of the revision and renewal, the permit will allow mining to continue through December 2011. We are allowed to continue mining under the existing Permit 47 while the permit approval process is in process.
The Jewett Mine purchases electric power from the Brazos Electric Power Cooperative, Inc. and Navasota Valley Electric Cooperative. The mine may be accessed on Farm to Market Road 39.
Beulah Mine
Knife River Corporation began producing lignite at the Beulah Mine in 1963. The mine has two working areas, the West Brush Creek area and the East Beulah area. We purchased the assets of the Beulah Mine from Knife River in 2001.
On July 11, 2005, we executed an option and acquired additional reserves in the South Beulah area. Initial drilling and mine plans have been completed. The South Beulah reserves have improved quality, lower sodium and lower strip ratios than the existing mine areas. (The strip ratio is a measure of the overburden that must be removed to allow the extraction of coal; a strip ratio of 10:1 means that 10 cubic yards of overburden must be removed to permit the extraction of one ton of coal.) The owners of the Coyote Station have agreed to include the acquisition costs and development capital in the cost base under the Coyote contract.
The Beulah Mine’s primary excavating machines are a dragline with a bucket-capacity of 17 cubic yards, constructed in 1963, which operates in the West Brush Creek area, and a dragline with a bucket-capacity of 84 cubic yards, constructed in 1980, which removes overburden at East Beulah. The Beulah Mine’s facilities consist of a truck dump hopper, primary and secondary crushers, conveyors, train loadout, railroad spur, coal storage bin, and coal stockpile. The support facilities include several maintenance shops, equipment storage buildings, warehouse, employee change houses, and mine office and trailers. These facilities date from 1963 and have been replaced or maintained consistent with normal industry practices.
The Beulah Mine’s engineering staff has estimated the mine’s reserves and updated the reserves annually, adjusted for tons mined. We estimate that the total owned and leased coal reserves at the Beulah Mine were approximately 81.2 million tons at December 31, 2006. We believe that all of these reserves are recoverable through the Beulah Mine’s existing facilities with current technology and the existing infrastructure.
We are responsible for reclaiming the Beulah Mine and paying the cost of our reclamation obligations.
Of the 81.2 million tons shown for the Beulah Mine in the table above as proven and probable coal reserves, 61.7 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” Of the total reserves shown, approximately 4.6 million tons in the West Brush Creek area and 14.9 million tons at East Beulah are fully permitted at this time. Based on the current estimated production rates of 1.0 million and 2.0 million tons respectively, there are roughly five to seven years, respectively, remaining under the current permitted mine plans. North Dakota Public Service Commission regulates surface mining in North Dakota and issues mining permits under its OSM-approved program. In North Dakota, it typically takes one to two years from the time an initial application is filed to obtain a new permit. Based on our current knowledge of the permitting process in North Dakota and the environmental issues associated with these reserves, we believe that there are no matters that would hinder our ability to obtain any mining permits in the future.
The Beulah Mine purchases electric power from MDU. The mine is accessed from North Dakota Highway 49.
Savage Mine
Knife River began producing lignite at the Savage Mine in 1958. We purchased the assets of the Savage Mine from Knife River in 2001.
The Savage Mine’s primary excavating machine is a walking dragline with a bucket-capacity of 12 cubic yards. The Savage Mine’s facilities consist of a truck dump, near-pit crushing unit, conveyors, and coal stockpile; support facilities include a shop, warehouse, and mine office. These facilities date from 1958 and have been replaced or maintained consistent with normal industry practices. The processing facilities were constructed in 1996. The facilities were modified and upgraded in 2001.
We estimate that the total owned and leased coal reserves at the Savage Mine were approximately 8.0 million tons at December 31, 2006. These reserves were estimated as of January 1, 1999, based principally on a report prepared by Weir International Mining Consultants, an independent consulting firm, and updated by our engineering staff in 2005 based on drilling completed in 2004. We believe that all of these reserves are recoverable through the Savage Mine’s existing facilities with current technology and the existing infrastructure.
We are responsible for reclaiming the Savage Mine and paying the cost of our reclamation obligations.
Of the tons shown for the Savage Mine in the table above as coal reserves, approximately 2.2 million tons are fully permitted at this time and 5.8 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” We have chosen not to permit all of the coal reserves in the Savage Mine’s plan because the mine already has sufficient coal in its current permitted mine plan given the current rate of mining and demand for its production into 2013. Based upon our current knowledge of the nature of the remaining reserves and the permitting process in Montana, we believe that there are no matters that would hinder our ability to obtain additional mining permits at the Savage Mine in the future.
The Savage Mine purchases electric power from MDU. The mine is accessed from Montana Highway 16 via County Road 107.
Other
Refer to Note 4 to our Consolidated Financial Statements for a description of Westmoreland Energy’s properties.
ITEM 3
ITEM 3 - LEGAL PROCEEDINGS
We are involved in legal proceedings the outcome of which could be material to the Company. We have presented the proceedings below based on the Westmoreland entity that is party to the proceeding.
Legal proceedings involving Westmoreland Coal Company
Combined Benefit Fund Litigation
Under the Coal Act, the Company is required to provide postretirement medical benefits for certain UMWA miners and their dependents by making payments into certain benefit plans, one of which is the Combined Benefit Fund (“CBF”).
The Coal Act merged the UMWA 1950 and 1974 Benefit Plans into the CBF, and beneficiaries of the CBF were assigned to coal companies across the country. Congress authorized the Department of Health & Human Services (“HHS”) to calculate the amount of the premium to be paid by each coal company to whom beneficiaries were assigned. Under the statute, the premium was to be based on the aggregate amount of health care payments made by the 1950 and 1974 Plans in the plan year beginning July 1, 1991, less reimbursements from the Federal Government, divided by the number of individuals covered. That amount is increased each year by a cost of living factor.
Prior to the creation of the CBF, the UMWA 1950 and 1974 Plans had an arrangement with HHS pursuant to which they would pay the health care costs of retirees entitled to Medicare, and would then seek reimbursement for the Medicare-covered portion of the costs from HHS. The parties had lengthy disputes over the years concerning the amount to be reimbursed, which led them to enter into a capitation agreement in which they agreed that HHS would pay the Plans a specified per-capita reimbursement amount for each beneficiary each year, rather than trying to ascertain each year the actual amount to be reimbursed. The capitation agreement was in effect for the plan year beginning July 1, 1991, the year specified by the Coal Act as the baseline for the calculation of Coal Act premiums.
In assessing the annual premium of the coal operators under the CBF, the Trustees of the CBF used an interpretation by HHS that “reimbursements” in the base-line year were the amounts that would have been payable by the government if the actual Medicare regulations were applied, not the amounts actually received by the CBF under the capitation agreement. This method of calculating the CBF premium resulted in a higher amount than would have been the case if the government payments under the capitation agreement had been applied. The coal operators disagreed with the HHS interpretation and initiated litigation in the mid - 1990’s.
In 1995, the Court of Appeals for the Eleventh Circuit ruled, in a victory for the coal companies, that the meaning of the statute was clear, i.e., that “reimbursements” meant the actual amount by which the CBF was reimbursed, regardless of the amount of the Medicare-covered expenditures under government regulations. In 2002, the Court of Appeals for the District of Columbia Circuit ruled that the statute was ambiguous, and remanded the case to the Commissioner of Social Security, as successor to HHS, for an explanation of its interpretation so that the court could evaluate whether the interpretation was reasonable. The Commissioner of Social Security affirmed the previous interpretation and the coal companies then brought another legal challenge. On August 12, 2005, the United States District Court for the District of Maryland agreed with the Eleventh Circuit that the term “reimbursements” unambiguously means the actual amount by which the CBF was reimbursed, and the Court granted summary judgment to the coal operators. However, the judge ruled that until all appeals have been exhausted and the case is final, the CBF can retain the premium overpayments, although the judge applied the new premium calculation prospectively.
On December 21, 2006, the United States Court of Appeals for the Fourth Circuit ruled in favor of the coal operators and affirmed the decision of the Maryland District Court that “reimbursements” in the Coal Act premium calculation refers to actual reimbursements received by the CBF.
The difference in premium payments for Westmoreland is substantial. Pursuant to the holdings of the Eleventh Circuit and the Federal District Court of Maryland, Westmoreland has overpaid and expensed premiums by more than $5.8 million for the period from 1993 through 2006.
In March 2007, the Trustees of the CBF and the coal companies reached agreement that during 2007, the CBF would refund the overpayments together with interest to the coal companies. Accordingly, during 2007 the Company expects to receive the $5.8 million plus interest, as full and final settlement for this litigation.
The Company paid premiums to the CBF of approximately $332,000 for each of the first nine months of 2006, compared to $396,000 per month prior to the Maryland District Court decision. The premiums were reduced to approximately $306,000 per month beginning in October, 2006.
1992 UMWA Benefit Plan Surety Bond
On May 11, 2005, XL Specialty Insurance Company and XL Reinsurance America, Inc. (together, “XL”), filed in the U.S. District Court, Southern District of New York, a Complaint for Declaratory Judgment against Westmoreland Coal Company and named Westmoreland Mining LLC as a co-defendant. The Complaint asked the court to confirm XL’s right to cancel a $21.3 million bond that secures Westmoreland’s obligation to pay premiums to the UMWA 1992 Plan, and also asked the court to direct Westmoreland to pay $21.3 million to XL to reimburse XL for the $21.3 million that would be drawn under the bond by the 1992 Plan Trustees upon cancellation of the bond.
At a hearing held on January 31, 2006, the judge advised the parties that the United States District Court for New Jersey would be a more appropriate venue. On March 1, 2006, the plaintiffs filed their complaint in the New Jersey District Court. On April 12, 2006, the defendants filed a motion to dismiss for lack of jurisdiction because there is no diversity of citizenship. The motion was granted on March 21, 2007 and the case was dismissed. The plaintiffs have the option of bringing the litigation in state court.
On February 7, 2007, Westmoreland Coal Company voluntarily reduced the amount of the XL bond, with the consent of XL, from approximately $21.3 million to $9.0 million. This reduction was permitted by amendments to the Coal Act that were signed into law on December 20, 2006.
The Company believes that it has no obligation to reimburse XL for draws under the bond unless the draw is the result of a default by the Company under its obligations to the UMWA 1992 Plan. No default has occurred. If XL prevails on its claim, the Company will be required to provide cash collateral of $9.0 million for its obligations to the 1992 Plan or, alternatively, provide a letter of credit.
Legal Proceedings involving Westmoreland Coal Company and/or Westmoreland Energy
Rensselaer Tax Assessment
Niagara Mohawk Power Corporation (“NIMO”) was party to power purchase agreements with independent power producers, including the Rensselaer project, in which the Company owned an interest. In 1997, the New York Public Service Commission approved NIMO’s plan to terminate or restructure 29 power purchase contracts. The Rensselaer project agreed to terminate its Power Purchase and Supply Agreement after NIMO threatened to seize the project under its power of eminent domain. NIMO and the Rensselaer project executed a settlement agreement in 1998 with a payment to the project. On February 11, 2003, the North Carolina Department of Revenue notified the Company that it had disallowed the exclusion of gain as non-business income from the settlement agreement between NIMO and the Rensselaer project. The State of North Carolina assessed a current tax of $3.5 million, interest of $1.3 million (through 2004), and a penalty of $0.9 million. The Company consequently filed a protest. The North Carolina Department of Revenue held a hearing on May 28, 2003. In November 2003, the Company submitted further documentation to the State to support its position. On January 14, 2005, the North Carolina Department of Revenue concluded that the additional assessment is statutorily correct. On July 27, 2005, the Company responded to the North Carolina Department of Revenue providing additional information.
As a result of discussions between counsel for the Company and counsel for the Department of Revenue in February 2007, the department indicated that it will revise its assessment to $4.2 million, inclusive of interest but without a penalty, if the Company would agree to pay the revised assessment and waive any right to appeal. Accordingly, in 2006 the Company increased its accrued reserve from $2.1 million to $4.2 million at December 31, 2006, which is the minimum amount the Company believes it will be required to pay.
Legal Proceedings involving Westmoreland Coal Company, Westmoreland Resources, and/or Western Energy
Royalty Claims by Minerals Management Service and Related Tax Claims by Montana Department of Revenue
The Company acquired Western Energy Company (“WECO”) from Montana Power Company in 2001. WECO produces coal from the Rosebud Mine, which includes federal leases, a state lease and some privately owned leases near Colstrip, Montana. The Rosebud Mine supplies coal to the four units of the adjacent Colstrip Power Plant. In the late 1970’s, a consortium of six utilities, including Montana Power, entered into negotiations with WECO for the long-term supply of coal to Units 3&4 of the Colstrip Plant, which would not be operational until 1984 and 1985, respectively. The parties could not reach agreement on all the relevant terms of the coal price and arbitration was commenced. The arbitration panel issued its opinion in 1980. As a result of the arbitration order, WECO and the Colstrip owners entered into a Coal Supply Agreement and a separate Coal Transportation Agreement. Under the Coal Supply Agreement, the Colstrip Units 3&4 owners pay a price for the coal F.O.B. mine. Under the Coal Transportation Agreement, the Colstrip Units 3&4 owners pay a separate fee for the transportation of the coal from the mine to Colstrip Units 3&4 on a conveyor belt that was designed and constructed by WECO and has been continuously operated and maintained by WECO.
In 2002 and 2006, the State of Montana, as agent for the Minerals Management Service (“MMS”) of the U.S. Department of the Interior, conducted audits of the royalty payments made by WECO on the production of coal from the federal leases. The audits covered three periods: October 1991 through December 1995, January 1996 through December 2001, and January 2002 through December 2004. Based on these audits, the Office of Minerals Revenue Management (“MRM”) of the Department of the Interior issued orders directing WECO to pay royalties in the amount of $8.6 million on the proceeds received from the Colstrip owners under the Coal Transportation Agreement during the three audit periods. The orders held that the payments for transportation were payments for the production of coal. The Company believes that only the costs paid for coal production are subject to the federal royalty, not payments for transportation.
WECO appealed the orders of the MRM to the Director of the MMS. On March 28, 2005, the MMS issued a decision stating that payments to WECO for transportation across the conveyor belt were part of the purchase price of the coal and therefore subject to the royalty charged by the federal government under the federal leases. However, the MMS dismissed the royalty claims for periods more than seven years before the date of the order on the basis that the statute of limitations had expired, which reduced the total demand from $8.6 million to $5.0 million.
On June 17, 2005, WECO appealed the decision of the MMS on the transportation charges to the United States Department of the Interior, Office of Hearings and Appeals, Interior Board of Land Appeals (“IBLA”). On September 6, 2005, the MMS filed its answer to WECO’s appeal. This matter is still pending before the IBLA.
The total amount of the MMS royalty claims including interest through the end of 2003 was approximately $5.0 million. This amount, if payable, is subject to interest through the date of payment, and as discussed above, the audit only covered the period through 2001.
By decision dated September 26, 2006, the MMS issued a demand to WECO assessing a royalty underpayment charge of $1.6 million, which the MMS asserts is attributable to coal production from Federal Coal Lease No. M18-080697-0. This assessment is based on the same MMS analysis as the assessments previously asserted by the MMS pursuant to its decisions dated September 23, 2002 but applies to a later period. The amount of the potential liability is $1.6 million, plus interest.
In 2003, the State of Montana Department of Revenue (“DOR”) assessed state taxes for years 1997 and 1998 on the transportation charges collected by WECO from the Colstrip Units 3&4 owners. The taxes are payable only if the transportation charges are considered payments for the production of coal. The DOR is relying upon the same arguments used by the MMS in its royalty claims. WECO has disputed the state tax claims.
In 2006, DOR issued additional assessments for certain of these taxes for years 1998-2001. WECO appealed and DOR elected to proceed to hearing on these objections using its internal administrative hearing process. This is the first stage of the eventual adjudication which could ultimately conclude with the Montana Supreme Court. It is likely that the IBLA will rule on the MMS issue before this DOR process reaches the Montana state court system, and it is likely that the federal court will have ruled on any appeal from the IBLA before the DOR issue reaches the Montana Supreme Court. The total of the state tax claims through the end of 2001, including interest through the end of 2006, was approximately $20.4 million. If this amount is payable it is subject to interest from the time the tax payment was due until it is paid.
The MMS has asserted two other royalty claims against WECO. In 2002, the MMS held that “take or pay” payments received by WECO during the period from October 1, 1991 to December 31, 1995 from two Colstrip Units 3&4 owners were subject to the federal royalty. The MMS is claiming that these “take or pay” payments are payments for the production of coal, notwithstanding that no coal was produced. WECO filed a notice of appeal with MMS on October 22, 2002, disputing this royalty demand. No ruling has yet been issued by MMS. The total amount of the royalty demand, including interest through August 2003, is approximately $2.7 million.
In 2004, the MMS issued a demand for a royalty payment in connection with a settlement agreement dated February 21, 1997 between WECO and one of the Colstrip owners, Puget Sound Energy. This settlement agreement reduced the coal price payable by Puget Sound as a result of certain “inequities” caused by the fact that the mine owner at the time, Montana Power, was also one of the Colstrip customers. The MMS has claimed that the coal price reduction is subject to the federal royalty. WECO has appealed this demand to the MMS, which has not yet ruled on the appeal. The amount of the royalty demand, with interest through mid-2003, is approximately $1.3 million.
Finally, in May 2005 the State of Montana asserted a demand for unpaid royalties on the state lease for the period from January 1, 1996 through December 31, 2001. This demand, which was for $0.8 million, is based on the same arguments as those used by the MMS in its claim for payment of royalties on transportation charges and the 1997 retroactive “inequities” adjustment of the coal price payable by Puget Sound.
Neither the MMS nor the DOR has made royalty or tax demands for all periods during which WECO has received payments for transportation of coal. Presumably, the royalty and tax demands for periods after the years in dispute-generally, 1997 to 2004-and future years will be determined by the outcome of the pending proceedings. However, if the MMS and DOR were to make demands for all periods through the present, including interest, the total amount claimed against WECO, including the pending claims and interest thereon through December 31, 2006, could exceed $33 million.
The Company believes that WECO has meritorious defenses against the royalty and tax demands made by the MMS and the DOR. The Company expects a favorable ruling from the IBLA, although it could be a year or more before the IBLA issues its decision. If the outcome is not favorable to WECO, the Company plans to seek relief in Federal district court.
Moreover, in the event of a final adverse outcome with DOR and MMS, the Company believes that the owners of Colstrip Units 3&4 are contractually obligated to reimburse the Company for any royalties and taxes imposed on the Company for the production of coal sold to the Colstrip owners, plus the Company’s legal expenses. Consequently, the Company has not recorded any provisions for these matters. Legal expenses associated with these matters are expensed as incurred. WECO is recovering these expenses from the Colstrip Units 3&4 owners.
Litigation with Washington Group International, Inc.
On February 17, 2006, the Company was served with a complaint filed by Washington Group International, Inc., or WGI, in Colorado District Court, City and County of Denver. The defendants in this action were Westmoreland Coal Company, Westmoreland Coal Sales Company, or WCSC, WRI, and certain directors and officers of WRI. WGI owns a 20% interest in WRI and the Company owns the remaining 80%. This litigation related to a coal sales agency agreement between WRI and WCSC, a wholly owned subsidiary
of the Company, which was entered into in January of 2002. Under this coal sales agency agreement, WCSC acted as agent for WRI in marketing and selling WRI coal in exchange for an agency fee. WGI objected to this fee and claimed in its complaint that the directors of WRI and its President breached their fiduciary duty by granting an over-market agency fee to an affiliated company. WGI’s share of the amount in dispute, if the fee was to be rescinded retroactively to 2002 and the fee then in effect applied, was approximately $0.6 million. The Company believed that the sales agency fee reflected a fair rate for marketing and selling coal and further believed that WCSC provided service to WRI for which it should be compensated at a fair rate. At December 31, 2006, the Company had not reserved any amount in its financial statements for this claim.
On October 16, 2006, WRI filed suit against WGI in the U.S. District Court for the District of Montana. WGI conducted all mining at the Absaloka Mine under a long-term contract with WRI. The complaint alleged that WGI failed to meet its obligations under the mining contract and asked the court to affirm WRI right to terminate the mining contract. The complaint also sought unspecified damages from WGI.
On March 6, 2007, the Company, WRI and WGI signed a comprehensive agreement. Pursuant to that agreement, WRI will terminate the WGI mining contract and assume direct responsibility for mining operations at the Absaloka Mine, and assume all liability for reclaiming the mine, effective March 30, 2007. In addition, pursuant to the agreement, Washington Group will transfer $7.0 million in a reclamation escrow account to WRI, WRI will pay Washington Group $4.0 million, and the parties will terminate all the litigation between them.
McGreevey Litigation
In late 2002, the Company was served with a complaint in a case styled McGreevey et al. v. Montana Power Company et al. in a Montana State court. The plaintiffs are former stockholders of Montana Power who filed their first complaint on August 16, 2001. This was the Plaintiffs’ Fourth Amended Complaint; it added Westmoreland as a defendant to a suit against Montana Power Company, various officers of Montana Power Company, the Board of Directors of Montana Power Company, financial advisors and lawyers representing Montana Power Company and the purchasers of some of the businesses formerly owned by Montana Power Company and Entech, Inc., a subsidiary of Montana Power Company. The plaintiffs seek to rescind the sale by Montana Power of its generating, oil and gas, and transmission businesses, and the sale by Entech of its coal business, or to compel the purchasers to hold these businesses in trust for the shareholders. The Plaintiffs contend that they were entitled to vote to approve the sale by Entech to the Company even though they were not shareholders of Entech. Westmoreland has filed an answer, various affirmative defenses and a counterclaim against the plaintiffs. Shortly after the Company was named as a defendant, the litigation was transferred from Montana State Court to the U.S. District Court in Billings, Montana.
There has been no significant activity in the case involving Westmoreland for the past four years. Settlement discussions between the plaintiffs and other defendants appear to have been unsuccessful. We have never participated in settlement discussions with the plaintiffs because we believe that the case against the Company is totally without merit. Even if the plaintiffs could establish that shareholder consent was required for the sale of Montana Power’s coal business in 2001, there is virtually no legal support for the argument that such a sale to a buyer acting in good faith, purchasing from a wholly owned subsidiary, and relying on the seller’s representations can be rescinded. Indeed, the practical issues relating to such rescission would present a significant obstacle to such a result, particularly when the business has been operated by the buyer for six years, significant amounts of capital have been invested, reserves have been depleted, and the original seller is in bankruptcy and has no means to complete a repurchase or operate the business following a repurchase.
The Company has considered seeking a dismissal of the claims against it but is waiting for the outcome of a matter under review in the bankruptcy proceedings in Delaware involving Touch America (formerly Montana Power Company). In those proceedings, the unsecured creditors have asserted that the claims originally filed by McGreevey in Montana-the claims against the officers and directors which, if successful, would likely result in a payment by the insurance carrier that provided D&O insurance to Montana Power Company-belong to the creditors, not the shareholders who are the plaintiffs in the McGreevey action. If the Delaware Bankruptcy Court holds that those claims are “derivative” and thus belong to the corporation, then
the unsecured creditors may have a right to those claims. Although the Delaware Bankruptcy Court will not directly decide that issue with respect to the claims against the various asset purchasers, including the Company, such a decision would likely affect the analysis of the Montana District Court where our case is pending. No liability has been accrued by the Company relating to this matter.
Texas Westmoreland Price Arbitration
Under the coal supply agreement between Texas Westmoreland Coal Company and NRGT, the customer of the Texas Westmoreland’s Jewett Mine, the price for lignite delivered to NRGT in 2008 will be determined by negotiation or, failing agreement, by arbitration. While the parties are still in negotiations for a multi-year amendment to the coal supply agreement, they agreed to seek a price determination through arbitration under the auspices of the International Institute for Conflict Resolution and Prevention. This arbitration commenced on February 2, 2007 and a hearing was held on March 23, 2007. On March 26, 2007, the 2008 price was determined through arbitration to be $1.2069 per million Btu. In 2006, Texas Westmoreland delivered approximately 89 trillion Btu to NRGT at a price of $1.246 per million Btu. Based on the arbitration decision, Texas Westmoreland must now decide on the amount of lignite it is willing to sell to NRGT in 2008 at the price determined by the arbitrator. It is anticipated the negotiations between the parties will continue regardless of the arbitrator’s decision because there are advantages to both parties to have a multi-year agreement regarding coal supply.
Other
In the ordinary course of our business, we and our subsidiaries are party to other legal proceedings that are not material.
ITEM 4
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of the Company’s stockholders during the fourth quarter of 2006.
Executive Officers of the Company
The following table shows the executive officers of the Company, their ages as of March 1, 2007, positions held and year of election to their present offices. All of the officers are elected annually by the Board of Directors and serve at the pleasure of the Board of Directors. Mark K. Seglem is the brother of Christopher K. Seglem.
(1)
Mr. Christopher Seglem was elected President and Chief Operating Officer in June 1992, and a Director of the Company in December 1992. In June 1993, he was elected Chief Executive Officer, at which time he relinquished the position of Chief Operating Officer. In June 1996, he was elected Chairman of the Board. He is a member of the bar of Pennsylvania.
(2)
Mr. Blair joined Westmoreland in April 2005. He joined Westmoreland after seventeen years with Nalco Chemical Company where he was most recently acting Chief Financial Officer for Ondeo Nalco Company, a global specialty chemical company.
(3)
Mr. Wiegley joined Westmoreland in May 2005. Prior to joining Westmoreland he held legal positions with Credit Suisse Group from 1999 to 2005 and served as General Counsel for one of its affiliates. Mr. Wiegley served as outside counsel for Westmoreland from 1992 to 1994 while a partner with Sidley Austin LLP and from 1994 to 1997 with Pillsbury Winthrop Shaw Pittman LLP.
(4)
Mr. Holzwarth joined Westmoreland in November 2004. Prior to joining Westmoreland, he was Chief Executive Officer of United Energy, a publicly-traded utility in Australia. From 1993 to 2003 he was employed by Aquila, Inc. in various management positions, including from 1997 to 2000 as Vice President and General Manager of Power Services and Generation, in which capacity he managed power
plants capable of generating over 2,000 MW of electricity, and from 2002 to 2003 as Chief Executive Officer of United Energy, Australia, an electric distribution utility serving 600,000 customers.
(5)
Mr. O’Laughlin joined Westmoreland in February 2001 as Vice President, Mining, and was named President and General Manager of Dakota Westmoreland Corporation in March 2001. He later became President and General Manager of Western Energy Company and President of Texas Westmoreland Coal Company and was promoted to Vice President of Coal Operations for Westmoreland Coal Company in May 2005. Prior to joining Westmoreland, Mr. O’Laughlin was with Morrison Knudsen Corporation’s mining group for twenty-eight years, most recently as Vice President of Mine Operations which included responsibility for the contract mining services at the Absaloka Mine.
(6)
Mr. Myers rejoined Westmoreland in January 2000 as Vice President, Marketing and Business Development and in 2002 became Vice President, Sales and Marketing. He originally joined Westmoreland in 1989 as a Market Analyst and was promoted in 1991 to Manager of the Contract Administration Department. He left Westmoreland in 1994. Between 1994 and 2000, he was Senior Consultant and Manager of the environmental consulting group of a nationally recognized energy consulting firm, specializing in coal markets, independent power development, and environmental regulation.
(7)
Mr. Beck joined Westmoreland in July 2001 as Vice President, Finance and Treasurer. From September 2003 to April 2005, he also served as Acting Chief Financial Officer. He was appointed Assistant Secretary in April 2005. Prior to joining Westmoreland he was a financial officer at Columbus Energy Corp. from 1985 to 2000, lastly as Vice President and Chief Financial Officer.
(8)
Mr. Mark Seglem joined Westmoreland in July 2003 as Vice President, Business Operations of Texas Westmoreland Coal Company. In May 2006 he was promoted to President of Texas Westmoreland and elected Vice President, Strategic Planning and Administration of Westmoreland Coal Company. Mr. Seglem came to Westmoreland from the Secretary of Defense’s office where he had served as a division director since August of 2001. Prior to that he worked for two years as a manager of the defense consulting firm, Whitney, Bradley, and Brown of Vienna, Virginia. Mr. Seglem served in the United States Navy as a Surface Warfare Officer from 1979 to 1999 retiring at the grade of Captain (select).
(9)
Mr. Durham joined Westmoreland as Vice President, Coal Operations in April 2000 and was named Vice President, Planning and Engineering in May 2005. For the four years prior to joining Westmoreland, he was a Vice President of NorWest Mine Services, Inc. which provides worldwide mining consulting services on surface mining and other projects. Mr. Durham has over 30 years of surface mine management and operations experience. He became a registered professional engineer in 1976.
(10)
Mr. Kathol joined Westmorland in August 2003. Prior to joining Westmoreland, Mr. Kathol was Vice President and Controller of NorWest Mine Services, Inc. which provides worldwide mining consulting services. Mr. Kathol has over 27 years experience evaluating and developing energy related projects.
(11)
Ms. Dymond joined Westmoreland in June 2006, as Vice President, Human Resources and became Vice President, Human Resources and Risk Management in November 2006. From 2000 to June 2006, she was with Cenveo, Inc., a publicly-held printing and paper conversion company, where she served as Vice President of Human Resources. Ms. Dymond has held senior human resources and risk management positions with publicly-held companies in the energy and manufacturing sectors since 1987 including serving as Vice President of Human Resources of ACX Technologies, the publicly-held spin-off of the Adolph Coors Brewing Co. Ms. Dymond is a Certified Compensation Professional.
(12)
Mr. Woods joined Westmoreland in May 1973 and held various corporate accounting and management information systems positions while at Westmoreland’s Virginia and West Virginia coal mining operations. Mr. Woods has been with Westmoreland Energy LLC since 1990 and has held the positions of Controller, Asset Manager, and Vice President, Finance and Asset Management. Mr. Woods was elected to his current positions as Vice President, Eastern Operations of Westmoreland Coal Company in June 2000, as Executive Vice President of Westmoreland Energy LLC in February 1997, and as President of Westmoreland Technical Services, Inc. in April 2001.
(13)
Ms. Jones joined Westmoreland in March 1993 as Manager, Business Development of Westmoreland Energy LLC and became Manager of Business Development and Corporate Relations for Westmoreland Coal Company in 1995. She was named Vice President Corporate Business Development and Corporate
Relations in 2000 and then named Vice President Corporate Relations in August 2003. Prior to joining Westmoreland, Ms. Jones held engineering and business development positions in the utility industry. She became a registered professional engineer in 1985.
(14)
Ms. Turner joined Westmoreland in August 2003 as Director, Government and Community Relations and was named Vice President, Corporate Government and Community Relations in January 2006. Prior to joining Westmoreland she was a policy analyst for the Education Commission of the States and director of marketing and communications for Quark Inc. She has over 25 years experience in various positions in marketing, communications and public policy, including representing communities impacted by energy development.
(15)
Mr. Paprzycki joined Westmoreland as Controller and Principal Accounting Officer in June 2006. Prior to joining Westmoreland he held positions at Applied Films Corporation as Corporate Controller from November 2005 to June 2006. From June 2004 to November 2005 he was Chief Financial Officer at Evans and Sutherland Computer Corporation, and the company’s Director of Finance from June 2001 to June 2004. Mr. Paprzycki became a certified public accountant in 1994 and a certified financial manager and certified management accountant in 2004.
(16)
Mr. Kegley joined Westmoreland in October 2005. Prior to joining Westmoreland he held legal positions with Peabody Energy Company from February 2004 to October 2005, AngloGold North America from June 2001 to February 2004, Kennecott Energy Company from August 1998 to June 2001, and Amax Coal Company and Cyprus Amax Minerals Company from February 1981 to July 1998. He is a member of the bar of Indiana, Illinois, Wyoming and Colorado.
PART II
ITEM 5
ITEM 5 -
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information:
The following table shows the range of sales prices for our common stock, par value $2.50 per share (the “Common Stock”), and Depositary Shares, each representing one quarter of a share of the Company’s Series A Convertible Exchangeable Preferred Stock, $1.00 par value per preferred share (the “Depositary Shares”) for the past two years.
The Common Stock and Depositary Shares are listed for trading on the American Stock Exchange (“AMEX”) and the sales prices below were reported by the AMEX.
Approximate Number of Equity Security Holders of Record:
Stock Performance Graph
The following performance graph compares the cumulative total stockholder return on the Company’s Common Stock for the five-year period December 31, 2001 through December 31, 2006 with the cumulative total return over the same period of the AMEX Market Index, and a peer group index which consists of Arch Coal Inc., CONSOL Energy Inc., Massey Energy Co., Peabody Energy Corp. and Alliance Resources Partners. These comparisons assume an initial investment of $100 and reinvestment of dividends.
The information included under the heading “Stock Performance Graph” in Item 5 of this Annual Report on Form 10-K is “furnished” and not “filed” and shall not be deemed to be “soliciting material” or subject to Regulation 14A, shall not be deemed “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act.
Dividends
We issued the Depositary Shares on July 19, 1992. Each Depositary Share represents one-quarter of a share of our Series A Convertible Exchangeable Preferred Stock. We paid quarterly dividends on the Depositary Shares until the third quarter of 1995, when we suspended dividend payments pursuant to the requirements of Delaware law, described below. We resumed dividends to preferred shareholders on October 1, 2002 and suspended them on July 2, 2006. The quarterly dividends which are accumulated through and including January 1, 2007 amount to $14.5 million in the aggregate ($90.53 per preferred share or $22.63 per Depositary Share). We cannot pay dividends on our common stock until we pay the accumulated preferred dividends in full.
There are statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which we are incorporated. Under Delaware law, we are permitted to pay preferred stock dividends only: (1) out of surplus, surplus being the amount of shareholders’ equity in excess of the par value of our two classes of stock; or (2) in the event there is no surplus, out of net profits for the fiscal year in which a preferred stock dividend is declared (and/or out of net profits from the preceding fiscal year), but only to the
extent that shareholders’ equity exceeds the par value of the preferred stock (which par value was $160,000 at December 31, 2006). The par value of all outstanding shares of preferred stock and shares of common stock aggregated $22.7 million at December 31, 2006. We are currently reporting a deficit in shareholders’ equity of $126.2 million. As a result, we are now prohibited from paying preferred stock dividends.
Our Board regularly considers issues affecting our preferred shareholders, including current dividends and the accumulated amount. Our Board is committed to meeting its obligations to the preferred shareholders in a manner consistent with the best interests of all shareholders. Quarterly dividends of $0.15 per Depositary Share were paid beginning on October 1, 2002; we increased the dividend to $0.20 per Depositary Share beginning on October 1, 2003, and further increased the dividend to $0.25 per Depositary Share on October 1, 2004. The last quarterly dividend payment was on July 1, 2006.
During 2006, we exchanged 179,818 Depositary Shares at an exchange ratio of 1.8691 shares of Common Stock for each Depositary Share, compared to the conversion ratio of 1.708 provided for under the terms of the Certificate of Designation governing the preferred stock. As a result of these preferred stock exchanges, $0.8 million of premium on the exchange of preferred stock for common stock was recorded in 2006, as an increase in net loss applicable to common shareholders. This premium on the exchange of preferred stock for common stock represents the excess of the fair value of consideration transferred to the preferred stock holders over the value of consideration that would have been exchanged under the original conversion terms. While we can redeem preferred shares at any time for the redemption value of $25 plus accumulated dividends paid in cash, we agreed to the negotiated exchanges as a cash conservation measure and because they reduce the number of outstanding Depositary Shares, thereby eliminating $3.9 million of accumulated dividends and associated future dividend requirements.
Information regarding our equity compensation plans and the securities authorized for issuance thereunder is incorporated by reference in Item 12 below.
ITEM 6
ITEM 6 - SELECTED FINANCIAL DATA
Westmoreland Coal Company and Subsidiaries
Five-Year Review
(1)
Effective June 29, 2006, the Company acquired a 50% interest in a partnership which owns the 230 MW Roanoke Valley power plants from a subsidiary of E.ON U.S. LLC. The acquisition increased the Company’s ownership interest in the partnership to 100%.
(2)
Effective December 31, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 158 (“SFAS NO. 158”). Upon adoption of the Standard, the Company recorded an increase in stockholders’ deficit of $95.2 million to reflect on its balance sheet the underfunded status of its pension and postretirement benefit plans.
ITEM 7
ITEM 7 -
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Disclaimer
Please keep the Forward-Looking Disclaimer on page 4 in mind as you review the following discussion and analysis.
Overview
Competitive, economic and industry factors
We are an energy company. We mine coal, which is used to produce electric power, and we own power-generating plants. All of our five mines supply baseloaded power plants. Several of these power plants are located adjacent to our mines, and we sell virtually all our coal under long-term contracts. Consequently, our mines enjoy relatively stable demand and pricing compared to competitors who sell more of their production on the spot market.
We now own 100% of ROVA, which is also baseloaded and supplies power pursuant to long-term contracts. We operate and maintain ROVA and four power projects owned by others. In partnership with others, we developed eight independent power projects totaling 866 MW of generating capacity. We sold our interests in five of those projects and retain our interest in ROVA and a 4.49% interest in the gas-fired Ft. Lupton Project, which has a generating capacity of 290 MW and provides peaking power to the local utility.
According to the 2006 Annual Energy Outlook prepared by the EIA, approximately 50% of all electricity generated in the United States in 2005 was produced by coal-fired units. The EIA projects that the demand for coal used to generate electricity will increase approximately 2.6% per year from 2005 through 2030. Consequently, we believe that the demand for coal will grow, in part because coal is the lowest cost fossil-fuel used for generating baseload electric power.
Revenues and expenses
In 2006, we generated $10.7 million of operating income, of which $33.5 million came from coal operations, $12.3 million from independent power operations, offset by $28.0 million of expenses attributable to our heritage segment and $7.1 million of expenses from our corporate segment.
Meeting Our Commitment to Preferred Stockholders
We remain committed to meeting our obligation for accumulated dividends to our preferred stockholders. Due to legal and business constraints, no dividends were declared from the third quarter of 1995 until 2002. On October 1, 2002 and for the following three quarters, a partial dividend of $0.15 per Depositary Share was paid. In October 2003 and October 2004, the quarterly dividend was increased to $0.20 and $0.25, respectively. We paid quarterly dividends of $0.25 per Depositary Share from October 1, 2004 through July 1, 2006. We suspended the payment of preferred stock dividends following the recognition of the deficit in shareholders’ equity described below. The quarterly dividends which are accumulated through and including January 1, 2007 amount to $14.5 million in the aggregate ($90.53 per preferred share or $22.63 per Depositary Share).
We are currently reporting a deficit in shareholders’ equity. As a result, we are now prohibited from paying preferred stock dividends because of the statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which the Company is incorporated. Under Delaware law, the Company is permitted to pay preferred stock dividends only to the extent that shareholders’ equity exceeds the par value of the preferred stock ($160,000 at December 31, 2006).
Challenges
We believe that our principal challenges today include the following:
•
obtaining adequate capital for our on-going operations and our growth initiatives;
•
continuing to fund high heritage health benefit expenses which continue to be adversely affected by inflation in medical costs, longer life expectancies for retirees and the failure of the UMWA retirement fund trustees to manage medical costs;
•
maintaining and collateralizing, where necessary, our Coal Act and reclamation bonds;
•
funding required contributions to pension plans that are underfunded;
•
complying with new environmental regulations, which have the potential to significantly reduce sales from our mines; and
•
defending against claims for potential taxes and royalties assessed by various governmental entities, some of which we believe are subject to reimbursement by our customers.
We discuss these issues, as well as the other challenges we face, elsewhere in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, and under “Risk Factors.”
Internal Control over Financial Reporting
We are committed to maintaining effective internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Our accounting personnel report regularly to our audit committee on all accounting and financial matters. In addition, our audit committee actively communicates with and oversees the engagement of our independent registered public accounting firm.
During 2006 we believe we have remediated four of the five material weaknesses that were identified in 2005 and 2006, in connection with the preparation of the 2005 Form 10-K and Amendment No. 1 to our 2005 Form 10-K. Subsequent to December 31, 2006, we plan to remediate the material weakness reported in Item 9A as of that date. We cannot assure you that additional material weaknesses in our internal control over financial reporting will not be identified in the future. Failure to implement and maintain effective internal control over financial reporting could result in material misstatements in our financial statements. See Item 1A, “Risk Factors.”
Critical Accounting Estimates and Related Matters
Our discussion and analysis of financial condition, results of operations, liquidity and capital resources is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require that we make estimates and judgments. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. Actual results may differ materially from these estimates.
We have made significant judgments and estimates in connection with the following accounting matters. Our senior management has discussed the development, selection and disclosure of the accounting estimates in the section below with the Audit Committee of our Board of Directors.
In connection with our discussion of these critical accounting matters, we also use this section to present information related to these judgments and estimates.
Postretirement Benefits and Pension Obligations
Our most significant long-term obligations are the obligations to provide postretirement medical benefits, pension benefits, workers’ compensation and pneumoconiosis (black lung) benefits. We provide these benefits to our current and former employees and their dependents. See Notes 7 and 8 of the Consolidated Financial Statements for more information about the assumptions and estimates associated with these obligations.
We estimate the total amount of these obligations with the help of third party actuaries using actuarial assumptions and information. Our estimates are sensitive to judgments we make about the discount rate, about the rate of inflation in medical costs, about mortality rates, and about the effect of the Medicare Prescription Drug Improvement and Modernization Act of 2003 or Medicare Reform Act on the benefits payable. We review these estimates and the obligations at least annually. Subsequent to the adoption of SFAS 158, the entire amount of underfunded status of our pension and postretirement benefits is reflected as a liability on our financial statements.
Actuarial valuations project that our heritage health benefit payments for retirees will increase annually until 2011 and then decline to zero over the next approximately sixty years as the number of eligible beneficiaries declines at a rate sufficient to overcome the rate of medical cost inflation for those remaining. Beginning in 2006, we began receiving Medicare Part D prescription drug reimbursements. We expect that these reimbursements will reduce our cash payments by approximately $1.8 million in 2007.
The effect of a one percent change on our health care cost trend rate on our postretirement medical periodic costs and benefit obligations is summarized in the table below:
In order to estimate the total cost of our obligation to provide medical benefits, we must make a judgment about the rate of inflation in medical costs. As our estimate of the rate of inflation of medical costs increases, our calculation of the total cost of providing these benefits increases. We have assumed that health care costs would increase by 10.0% in 2007 and that this rate of increase would decrease by 1% per year to 5.0% per year in 2012 and beyond. If the rate of inflation in medical costs were 1.0% higher per year, we estimate that our total obligation to provide postretirement medical benefits would increase by $24.9 million.
One of the estimates we have made relates to the implementation of the Medicare Reform Act. As provided for under that Act, we recognized a benefit to our anticipated future prescription drug costs for retirees and their dependents in 2003 based on a coordinated implementation of the Medicare Reform Act and our existing benefit programs, including the UMWA 1992 Plan. In 2005, the government issued regulations which made the subsidy approach the only practical alternative given our existing programs. In October 2005, we adopted the subsidy approach for 2006 and we will continue using the subsidy approach for 2007. The subsidy approach will limit our annual benefit to 28% (to a maximum of $1,330/participant) of actual costs.
We expect to incur lower cash payments for workers’ compensation benefits in 2007 than in 2006 and expect that amount to decline over time. We anticipate that these payments will decline because we are no longer self-insured for workers’ compensation benefits and have had no new claimants since 1995.
We do not pay pension or black lung benefits directly. These benefits are paid from trusts that we established and funded. As of December 31, 2006, our pension trusts were underfunded, and we expect to contribute approximately $4.2 million to these trusts in 2007. As of December 31, 2006, our Black Lung trust was overfunded by $7.8 million, and during 2007 we expect to withdraw approximately $5.6 million of this surplus from this trust.
Asset Retirement Obligations, Reclamation Costs and Reserve Estimates
Asset retirement obligations primarily relate to the closure of mines and the reclamation of land upon cessation of mining. We account for reclamation costs, along with other costs related to mine closure, in accordance with Statement of Financial Accounting Standards No. 143 - Asset Retirement Obligations or SFAS No. 143. This statement requires us to recognize the fair value of an asset retirement obligation in the period in which we incur that obligation. We capitalize the present value of our estimated asset retirement costs as part of the carrying amount of our long-lived assets.
Certain of the Company’s customers have either agreed to reimburse the Company for reclamation expenditures as they are incurred or have pre-funded a portion of the expected reclamation costs. These funds will serve as sources for use in final reclamation activities.
The liability “Asset retirement obligations” on our consolidated balance sheet represents our estimate of the present value of the cost of closing our mines and reclaiming land disturbed by mining. This liability increases as land is mined and decreases as reclamation work is performed and cash expended. The asset, “Property, plant and equipment - capitalized asset retirement costs,” remains constant until new liabilities are incurred or old liabilities are re-estimated. We estimate the future costs of reclamation using standards for mine reclamation that have been established by the government agencies that regulate our operations as well as our own experience in performing reclamation activities. These estimates can and do change. Developments in our mining program also affect this estimate by influencing the timing of reclamation expenditures.
We amortize our development costs, capitalized asset retirement costs, and some plant and equipment using the units-of-production method and estimates of recoverable proven and probable reserves. We review these estimates on a regular basis and adjust them to reflect our current mining plans. The rate at which we record depletion also depends on the estimates of our reserves. If the estimates of recoverable proven and probable reserves decline, the rate at which we record depletion increases. Such a decline in reserves may result from geological conditions, coal quality, effects of governmental, environmental and tax regulations, and assumptions about future prices and future operating costs.
See Note 10 to the Consolidated Financial Statements for current information about these obligations, costs and reserve estimates.
Deferred Income Taxes
As of December 31, 2006, we have significant deferred tax assets. Our deferred tax assets include federal and state regular net operating losses (“NOLs”), alternative minimum tax (“AMT”) credit carryforwards and net deductible reversing temporary differences related to on-going differences between book and taxable income. We have reduced our deferred income tax assets by a full valuation allowance. The valuation allowance is primarily an estimate of the deferred tax assets that will more likely than not expire before they can be realized in the future by our current operations existing as of December 31, 2006. These estimates and judgments are reviewed annually and also when new, material events, such as an acquisition, take place within the Company.
The Company believes it 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 its mining operations. As a result, the Company has determined that a valuation allowance is required for all of its regular federal net operating loss carryforwards, since they are not available to reduce AMT income in the future. The Company has also determined that a full valuation allowance is required for all its AMT credit carryforwards, since they are only available to offset future regular income taxes payable. In addition, the Company has determined that since its net deductible temporary differences will not reverse for the foreseeable future, and the Company is unable to forecast that it will have taxable income when they do reverse, a full valuation allowance is required for these deferred tax assets. The Company has also therefore recorded a full valuation allowance for its state net operating losses, since it believes that it is not more likely than not that they will be realized.
AMT NOLs reduce our current income tax expense each year until the AMT NOLs have been fully used. At December 31, 2006, we had fully used all of our AMT NOLs.
The AMT credits that we accumulate do not expire. However, their value has not been recognized, and will not be recognized, until we can forecast paying regular income taxes and are therefore able to use the credits. This will not occur until all of our regular NOLs are used or expire and our regular income tax exceeds our AMT.
In August 2005 the Energy Policy Act of 2005 was enacted. Among other provisions, it contains a tax credit for the production of coal owned by Indian tribes. The credit is $1.50 per ton beginning 2006 through
2009 and $2.00 per ton from 2010 through 2012, with both amounts escalating for inflation. The credit may be used against regular corporate income tax for all years and against AMT for the initial period.
The Company’s 80%-owned Absaloka Mine, which produces coal under a lease with the Crow Tribe, produces about 7 million tons per year. The savings are expected to be shared with the Crow Tribe when they are realized.
Contractual Obligations and Commitments
The following table presents information about our contractual obligations and commitments as of December 31, 2006. Some of the amounts below are estimates. We discuss these obligations and commitments elsewhere in this filing.
(1)
At December 31, 2006, Westmoreland Mining had deposited $25.4 million in two restricted accounts as collateral against these obligations.
(2)
At December 31, 2006, ROVA had deposited $28.1 million in a restricted debt account as collateral against these obligations.
(3)
In calculating the amount of interest on debt, we have assumed that the interest rates applicable to our floating rate debt would not increase or decrease from the rates in effect at December 31, 2006.
(4)
We have not accrued the present value of this obligation, because this plan is a multiemployer plan. We expense our premium payments when due.
(5)
The table presents our estimate of our discounted benefit obligation.
(6)
The fair value of plan assets at December 31, 2006 was $47 million. The obligations shown above are our expected contributions to the plan assets.
(7)
The table presents our estimate of our discounted benefit obligations.
(8)
The table presents our estimate of the undiscounted cost for final reclamation. The accrued liability of $184.1 million as of December 31, 2006 will increase in present value as mine closures draw nearer. The accrued liability does not consider the contractual obligations at December 31, 2006, of our customers and of Washington Group, the contract miner at the Absaloka Mine to perform reclamation. Effective March 30, 2007, WRI acquired the contract to mine the Absaloka Mine, and assumed the final reclamation obligation. We estimate that the present value of Washington Group’s receivable that we assumed is
$11.6 million, and the receivables of our other customers total $30.4 million. The accrued liability also does not reflect $62.5 million held in escrow as of December 31, 2006 from contributions by customers for reclamation of the Rosebud Mine, or $1.2 million in restricted cash for reclamation of other mines. In addition, the Absaloka contract mine operator is funding a separate reclamation escrow account which has a balance of approximately $6.5 million as of December 31, 2006. We estimate that the present value of our net obligation for final reclamation of our mines- that is, the costs of final reclamation that are not the contractual responsibilities of others - is $142.1 million at December 31, 2006. Responsibility for these amounts may change in certain circumstances. For example, at the Jewett Mine, if there is a cessation of mining the customer assumes responsibility for all reclamation. At December 31, 2006, if there had been a cessation of mining, the customer would have assumed responsibility for approximately $37.1 million (on a present value basis) of the reclamation obligation that is currently the responsibility of the Company.
(9)
ROVA has two coal supply agreements with TECO Coal Corporation. The amounts shown in this row assume that ROVA continues to purchase coal under these contracts at the current volume and does not extend these contracts and that the price per ton payable under these contracts does not increase.
Financial Implications of the ROVA Acquisition
In June 2006, we acquired the 50% interest in ROVA that we did not previously own. As part of that transaction, we also acquired five contracts from LG&E Power Services. Pursuant to these contracts two new subsidiaries of the Company, Westmoreland Power Operations and Westmoreland Utility Operations, will now operate ROVA and four other power plants.
ROVA sells electric power under two power sales agreements, one that expires in 2019 and one that expires in 2020. Capacity charges are calculated based on a rate for each MW-hour of electricity produced. The ROVA I per MW- hour capacity charge is fixed from 2006 through 2008 and then steps down to a new lower rate in May 2009 through the end of the power sales agreement in 2019. The ROVA II per MW-hour capacity charge is fixed from 2006 through 2009 and then steps down to a new lower rate in June 2010 through the end of the power sales agreement in 2020. ROVA’s indebtedness was structured so that ROVA’s principal and interest payments are relatively higher through 2009 and relatively lower thereafter. ROVA’s power sales agreements are structured to provide ROVA sufficient cash to repay its lenders and thus the capacity charges are relatively higher through 2009 and relatively lower thereafter.
ROVA’s historical accounting policy for revenue recognition of these capacity charges has been to record them as revenue as amounts were invoiced pursuant to the provisions of the power sales agreements. As discussed below, revenue recognition rules now require the Company to record these capacity charges ratably over the remaining term of the power sales agreements, irrespective of when the amounts are billed and collected. This change, while having no effect on cash flow or total revenue recognized over the remaining term of the power sales agreements, will have a significant impact on the timing of the recognition of revenue and income at ROVA.
These two power sales agreements were entered into prior to the effective date of Emerging Issues Task Force (“EITF”) 91-06, “Revenue Recognition of Long-Term Power Sales Contracts” and EITF 01-08, “Determining Whether an Arrangement Contains a Lease”. Accordingly, ROVA’s power sales agreements were not subject to the accounting requirements of these pronouncements. The completion of the ROVA acquisition triggered the two power sales agreements to be within the scope of EITF 01-08. Under EITF 01-08, each of the power sales agreements is considered to contain a lease within the scope of SFAS No. 13, “Accounting for Leases”. Each such lease is classified as an operating lease. As a result, we must recognize revenue for future capacity charges ratably over the remaining term of the power sales agreements.
In our historical financial statements, earnings from our original 50% interest in ROVA appeared as Independent power projects-equity in earnings because ROVA was an equity method affiliate. Because we now own 100% of ROVA, it is now fully consolidated in our financial statements. The pro forma impact of our ownership of 100% of ROVA is shown in our Form 8-K/A filed with the Securities and Exchange Commission on November 6, 2006. On a pro forma basis, if the ROVA transaction had occurred on January 1, 2005, the
net loss attributable to common stockholders for 2005 would have increased to approximately $26.7 million compared to the net loss reported in the historical financial statements of $7.7 million. If the ROVA transaction had occurred on January 1, 2006, the net loss applicable to common shareholders for 2006 would have been $18.4 million. The pro forma financial statements included in the Form 8-K/A include pro forma adjustments to reflect the recognition of capacity charges under the power sales agreements ratably over the term of the agreements, adjustments to reflect interest expense on debt incurred to finance the acquisition, and adjustments to reflect depreciation and amortization on the adjusted basis in the asset and liabilities acquired. For more information, please see our Form 8-K/A.
Substantial debt was incurred to finance ROVA’s development. Westmoreland Partners, which owns ROVA, is required to make principal payments on its indebtedness of $27.7 million in 2007, $32.3 million in 2008, $31.2 million in 2009, $15.3 million in 2010, and $51.5 million from 2011 through 2015, when ROVA’s project debt is completely repaid.
We incurred $35 million of indebtedness to fund the ROVA acquisition. For more information about this indebtedness, see Notes 2 and 6 to our Consolidated Financial Statements.
Our cash and cash equivalents, trade receivables and trade payables, plant and equipment, and intangible assets also increased significantly as a result of the ROVA acquisition.
Liquidity and Capital Resources
The report of our Independent Registered Public Accounting Firm on our consolidated financial statements includes a paragraph discussing uncertainty regarding the Company’s ability to continue as a going concern. Our consolidated financial statements do not include any adjustments that might reflect such uncertainty.
The major factors impacting our liquidity are: payments due on the term loan we entered into to acquire various operations and assets from Montana Power and Knife River in May, 2001; payments due on the acquisition debt associated with our purchase of the ROVA interest; payments due for the buyout of the Washington Group International mining contract at WRI, and additional capital expenditures we plan to make when we take responsibility for operating the mine; cash collateral requirements for additional reclamation bonds in new mining areas; and payments for our heritage health benefit costs. See “Factors Affecting our Liquidity”. Unforeseen changes in our ongoing business requirements could also impact our liquidity. Our principal sources of cash flow at Westmoreland Coal Company are dividends from WRI, distributions from ROVA and from Westmoreland Mining subject to the provisions in their respective debt agreements and dividends from the subsidiaries that operate power plants.
While we believe that the Company currently has sufficient capital resources and committed financing arrangements to provide us with adequate liquidity through early 2008, the variability inherent in our mining and power operations and the variability of payments under our postretirement medical plans may adversely impact our actual cash requirements and cash flows. We do not believe we have capital resources or committed financing arrangements in place to provide adequate liquidity to meet currently projected cash requirements beginning in early 2008 based on our most recent forecast. We are considering several alternatives for raising additional capital during 2007.
One of the alternatives available to us is to repay the $30 million bridge loan used to acquire ROVA with proceeds from an equity offering. Repaying this bridge loan would provide us access to the anticipated semi-annual cash distributions from ROVA which are currently required to be applied to the principal and interest payments on the $30 million bridge loan. If we are unable to repay or refinance the bridge loan, we have the option to extend the term of that loan to four years. If we elect to extend the loan beyond its initial one-year term, the Company will be required to issue warrants to the lender to purchase 150,000 shares of our common stock at a premium of 15% to the then current stock price. These warrants would be exercisable for a three-year period from the date of issuance. If the term of the loan is extended, all cash distributions from ROVA would continue to be required to be applied to the principal and interest payments on the loan through its term.
We are also considering a common stock rights offering to allow our shareholders the opportunity to make an additional investment in the Company. There can be no assurance that a common stock rights offering can be completed on a timely basis, or at all.
We believe that one of the other alternatives available to us is the sale of one or more of the Company’s assets. There can be no assurance that any sale could be completed on terms acceptable to the Company.
Other capital-raising options may be available to us such as a private placement of equity, although we can not be assured that pursuing such an option will be successful.
While no assurance can be given that any of these alternatives can be successfully implemented, management believes that sufficient capital can be raised to meet the Company’s liquidity requirements.
Factors Affecting our Liquidity
Our heritage health benefit costs consist primarily of payments for post retirement medical and workers’ compensation benefits. We are also obligated for employee pension and pneumoconiosis benefits. It is important to note that retiree health benefit costs are directly affected by increases in medical service, prescription drug costs and mortality rates. The most recent actuarial valuations of our heritage health benefits obligations, which pertain primarily to former employees who worked in our Eastern mines and are guaranteed life-time benefits under the federal Coal Act, indicated that our 2007 heritage health benefit payments would increase annually through 2011 and then decline to zero over the next approximately sixty years as the number of eligible beneficiaries declines. In 2006, we paid $18.0 million for postretirement benefit expenses, $3.6 million for CBF premiums and $0.9 million for workers’ compensation benefits and received $1.3 million in offsetting Medicare D subsidies. In 2007, we expect to pay $20.6 million in cash costs for postretirement medical benefits and receive $1.8 million of offsetting federal subsidies. In 2007, we expect to make payments for Combined Benefit Fund premiums in the amount of $3.7 million and $1.0 million of payments for workers’ compensation benefits.
The Westmoreland Mining acquisitions in 2001 greatly increased revenues and operating cash flow. The financing obtained to make those acquisitions requires quarterly interest and principal payments of approximately $4.2 million. This debt financing also requires that 25% of excess cash flow, as defined, be set aside to fund the $30 million debt payment due in December 2008. Therefore, only 75% of Westmoreland Mining’s excess cash flow is available to the Company until this debt is paid off in 2008. Westmoreland Mining also entered into the add-on debt facility in 2004 which requires the use of approximately $0.7 million of cash each quarter for debt service. The add-on facility permitted Westmoreland Mining to undertake significant capital projects, principally at the Rosebud and Jewett mines, without adversely affecting cash available to Westmoreland Coal Company. The terms of the add-on facility permitted Westmoreland Mining to distribute this $35 million to Westmoreland Coal Company. Westmoreland Mining’s distributions of $3.5 million in 2006 and $9.1 million in 2005 represented the remainder available from the $35 million add-on facility.
In June 2006, we acquired the 50% interest in ROVA that we did not previously own, which increased revenues and operating cash flow. This acquisition was funded with $35 million in debt as described in Note 2 to our consolidated financial statements. ROVA also has project-level debt which funded the original development of the power plants. The project-level debt requires semi-annual principal payments as described in Note 6 to the financial statements as well as ongoing interest payments. The acquisition debt requires approximately $0.7 million of interest payments each quarter. Should we elect to extend $30 million of the debt term to four years, we will make semi-annual principal payments of approximately $4.3 million, which would amount to substantially all of the cash distributions generated by ROVA over that term.
On March 6, 2007, we entered into an agreement to acquire WGI’s contract to be the exclusive miner at our Absaloka mine for approximately $4 million plus assumption of the reclamation obligation. While certain equipment was included in our purchase, we expect we will need additional capital for investment in mine development projects, mining equipment and to support bonding requirements.
Our ongoing and future business needs may also affect liquidity. We do not anticipate that either our coal or our power production revenues will diminish materially as a result of any future downturn in economic
conditions because ROVA and the power plants that purchase our coal produce relatively low-cost, baseload power. In addition, most of our coal and power production are sold under long-term contracts, which help insulate us from unfavorable market developments. However, contract price reopeners, contract expirations or terminations, and market competition could affect future coal revenues. We may also need additional capital to support our ongoing efforts to develop new projects such as the Gascoyne mine and power facility.
Cash Balances And Line of Credit
Consolidated cash and cash equivalents at December 31, 2006 totaled $26.7 million including $15.6 million at ROVA, $1.5 million at Westmoreland Power Inc., $0.6 million at Westmoreland Mining, $7.5 million at WRI and $1.5 million at our captive insurance subsidiary. The cash at Westmoreland Mining is available to the Company through quarterly distributions, as described below. The cash at our captive insurance subsidiary and WRI is available to the Company through dividends. The cash at ROVA is available to the Company through distributions after debt service and debt reserve account requirements are met. Under the provisions of the ROVA acquisition bridge loan, all cash distributions from ROVA subsequent to December 31, 2006, are to be applied to the principal balance of the loan and related interest.
As of December 31, 2006, Westmoreland Coal Company had $5.5 million of its $14.0 million revolving line of credit available to borrow.
Restricted Cash
We had restricted cash and bond collateral, which were not classified as cash or cash equivalents, of $69.7 million at December 31, 2006 compared to $34.6 million at December 31, 2005. The restricted cash at December 31, 2006 included $29.4 million in ROVA’s debt service accounts and prepayment accounts and $25.4 million in Westmoreland Mining’s debt service reserve, long-term prepayment, and reclamation escrow accounts. At December 31, 2006 our reclamation, workers’ compensation and postretirement medical cost obligation bonds were collateralized by interest-bearing cash deposits of $14.8 million, $11.5 million of which amounts we have classified as non-current assets and $3.3 million of which amounts we have classified as current assets. In addition, we had accumulated reclamation deposits of $62.5 million at December 31, 2006, representing cash received from customers of the Rosebud Mine to pay for reclamation, plus interest earned on the investments.
Preferred Stock
During 2006, we exchanged a total of 179,818 Depositary Shares at an exchange ratio of 1.8691 shares of Common Stock for each Depositary Share, compared to the conversion ratio of 1.708 provided for under the terms of the Certificate of Designation governing the preferred stock. As a result of these preferred stock exchanges, $0.8 million of premium on the exchange of preferred stock for common stock was recorded in 2006, as an increase in net loss applicable to common shareholders. This premium on the exchange of preferred stock for common stock represents the excess of the fair value of consideration transferred to the preferred stock holders over the value of consideration that would have been exchanged under the original conversion terms. While we can redeem preferred shares for cash at any time for the redemption value of $25 plus accumulated dividends, we agreed to these negotiated exchanges as a cash conservation measure and because they reduced the number of outstanding Depositary Shares, thereby eliminating $3.9 million of accumulated dividends and associated future dividend requirements.
Westmoreland Mining Debt Facilities
The original term loan agreement, which financed our acquisition of the Rosebud, Jewett, Beulah, and Savage mines, continues to restrict Westmoreland Mining’s ability to make distributions to Westmoreland Coal Company. Until Westmoreland Mining has fully paid the original acquisition debt, which is scheduled for December 31, 2008, Westmoreland Mining may only pay Westmoreland Coal Company a management fee and distribute to Westmoreland Coal Company 75% of Westmoreland Mining’s surplus cash flow. Westmoreland Mining is depositing the remaining 25% into an account that will be applied to the $30 million balloon payment
due December 31, 2008. In 2004 when Westmoreland Mining entered into the add-on facility, it also extended its revolving credit facility to 2007 and reduced the amount of the facility to $12 million. In December 2005, Westmoreland Mining amended the revolving facility to increase the borrowing base to $20 million and to extend its maturity to April 2008 to better align with its operating needs. The increase includes the ability to issue letters of credit up to $10 million which Westmoreland Mining expects to use for reclamation bond collateral requirements. As of December 31, 2006, a letter of credit for $1.9 million was supported by Westmoreland Mining’s revolving credit facility. Westmoreland Mining had borrowed $4.5 million against the facility and $13.6 million was available to borrow as of that date.
Historical Sources and Uses of Cash
Cash provided by operating activities was $33.2 million for 2006 compared with $28.8 million for 2005. The increase in net loss in 2006 reduced cash provided by operating activities by $1.7 million, which was offset by $13.9 million of increases in non-cash charges to income. Cash provided by operating activities includes $14.5 million invoiced under our power sales agreements, which has been recorded as deferred revenue. Cash distributions from independent power projects decreased $9.4 million in 2006, primarily because our ROVA distributions received after the acquisition were eliminated in consolidation. Unscheduled maintenance outages at ROVA during late 2005 also decreased cash distributions from independent power projects in 2006. Changes in working capital increased cash provided by operating activities in 2006 by $1.1 million compared to an increase in cash provided from changes in working capital of $14.1 million in 2005.
Cash provided by operating activities was $28.8 million for 2005 compared with $9.5 million for 2004. Cash provided by operating activities increased in 2005 due to a decrease in the net loss of $1.3 million, an increase in net non-cash charges to income of $0.6 million, and an increase in cash distributions from independent power projects of $7.5 million. Changes in working capital increased cash provided by operating activities in 2005 by $14.1 million, compared to an increase of $4.3 million in 2004.
Our working capital deficit was $67.4 million at December 31, 2006 compared to $20.1 million at December 31, 2005. The increase in our working capital deficit resulted primarily from the $35.0 million short-term ROVA bridge financing, the consolidation of ROVA which had $28.2 million of negative working capital, and the elimination of $14.1 million in deferred overburden removal costs as the result of a change in accounting principle discussed in Note 3 to our Consolidated Financial Statements. This accounting change had no effect on cash flows.
Our working capital deficit was $20.1 million at December 31, 2005 compared to $6.6 million at December 31, 2004. The increase in our working capital deficit resulted primarily from a $12.6 million increase in the current portion of our asset retirement obligation and an $8.5 million increase in trade accounts payable.
We used $33.9 million of cash in investing activities in 2006 compared to $22.8 million in 2005. The increase was primarily driven by our $7.7 million investment for our ROVA acquisition (net of cash acquired). Cash provided by investing activities in 2006 included $5.1 million received from the sale of mineral interests. Cash used in investing activities in 2006 included $20.9 million of additions to property, plant and equipment for mine development and equipment and investment in a company-wide software system. Cash flows from investing activities in 2006 also included a $10.5 million increase in our restricted cash accounts, pursuant to Westmoreland Mining’s term loan agreement and as collateral for our surety bonds. Additions to property, mine equipment, development projects and investment in a new company-wide software system were $18.3 million in 2005. Increases in restricted cash accounts, bond collateral, and reclamation deposits were $5.1 million in 2005.
We used $22.8 million of cash in investing activities in 2005 compared to $28.5 million in 2004. The decrease was primarily driven by a decrease in our restricted cash of $5.3 million. Cash used in investing activities in 2005 included $18.3 million of additions to property, plant and equipment for mine equipment and investment in a company-wide software system.
We received $16.3 million of cash from our financing activities in 2006. This increase was primarily a result of $35 million of borrowings to finance the ROVA acquisition and was offset by the repayment of $25.6 million of long-term debt. Cash used in financing activities of $5.8 million in 2005 was primarily the result of $7.2 million in borrowings under our long-term debt and revolving lines of credit offset by $12.2 million used for the repayment of long-term debt. In March 2004, Westmoreland Mining entered into the add-on facility. This facility made $35.0 million available to us in 2004. The add-on facility permitted Westmoreland Mining to undertake significant capital projects, principally at the Rosebud and Jewett mines, without adversely affecting cash available to Westmoreland Coal Company. The terms of the add-on facility permitted Westmoreland Mining to distribute this $35 million to Westmoreland Coal Company. Westmoreland Mining’s distributions of $3.5 million in 2006 and $9.1 million in 2005 represented the remainder available from the $35 million add-on facility.
Operational and Capital Expenditure Outlook
We anticipate that the following events and developments will affect our 2007 liquidity and earnings.
•
Tons sold in 2007 are expected to increase by approximately 2% compared to tons sold in 2006. Coal margins are expected to increase reflecting higher prices from customer contract renewals offset in part by increases in the costs of operating the mines.
•
We will receive a reserve dedication payment of $10 million from a customer in early 2007.
•
We anticipate that capital expenditures and new investments related to our mining activities will increase in 2007 from 2006 as a result of the replacement of operational equipment at our mines. As a result, we expect higher depreciation, depletion and amortization expense.
•
In February 2007, the Company sold its interest in a coal royalty for $12.7 million and will recognize a $5.6 million gain on the sale in the first quarter.
•
We anticipate a reduction in our 2007 heritage health benefit expenses as a result of lower health care costs, combined benefit fund premiums, workers’ compensation costs as well as the $5.8 million and additional interest refund expected from the CBF.
•
2007 results will reflect the consolidation of the operating results of ROVA for a full year compared to only six months in 2006.
Pricing Outlook
Pricing for about 3.5% of our sales tons expired on December 31, 2006 and were renewed effective January 1, 2007 at a 44% price increase. Contracts covering about 11% (excluding the NRG contract at the Jewett Mine as described in the paragraph below) of our expected sales tonnage are scheduled to expire on December 31, 2007, with anticipated renewals and repricing effective January 1, 2008.
Contracts covering approximately 10% of the tons that we expect to sell in 2007 are scheduled to expire in 2008. However, the customers under these contracts have the option to renew them. We expect that these options will be exercised. As a result, we expect that less than 1% of our expected sales tonnage will be repriced effective January 1, 2009. Contracts covering approximately 7% of the Company’s expected sales tonnage are scheduled to expire on December 31, 2009 and are anticipated to be renewed and repriced on January 1, 2010.
Sales from the Jewett Mine to NRG Texas’ Limestone Station account for approximately 22% of our sales volume and are subject to annual price redeterminations from January 1, 2008 through contract expiration in 2015. We segregate these sales from our other repricing opportunities because the contract provides for a complex set of calculations and other provisions, rights, and obligations that may distort the effect that the market has on price outcomes. Texas Westmoreland and NRG Texas are currently discussing various alternatives for determination of pricing effective January 1, 2008 forward. One of those alternatives could be adherence to the existing contract under which the price for 2008 has been determined in arbitration to be $1.2069 per million Btu. In 2006, we received a price of $1.246 per million Btu. Additionally, in 2006, the
customer agreed to fund most capital expenditures at the Jewett Mine. Under the existing contract, in 2008 the customer would no longer be responsible to fund capital expenditures unless we and the customer reach an alternative agreement. Based on the arbitration decision, Texas Westmoreland must now decide on the amount of lignite it is willing to sell to NRGT in 2008 at the price determined by the arbitrator. It is anticipated the negotiations between the parties will continue regardless of the arbitrator’s decision because there are advantages to both parties to have a multi-year agreement regarding coal supply. Other alternatives focus on more typical long-term coal contract pricing mechanisms. Including the sales to the Limestone Station in the figures above, 33% of our tons are open to repricing on January 1, 2008 and, assuming no change to the Texas Westmoreland contract with NRG Texas, 22% on January 1, 2009 and 29% on January 1, 2010. We may also, from time-to-time, choose to negotiate contract renewals or other modifications earlier than the expiration and reopener dates scheduled in those contracts.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements within the meaning of the rules of the Securities and Exchange Commission.
Results of Operations
Compared to 2005
Coal Operations
The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods:
Tons of coal sold decreased in 2006 by approximately 0.6 million tons from 2005. However, our coal revenues increased by approximately $32.5 million. Our tons sold decreased primarily as a result of reduced generation due to high hydroelectric availability and an extended planned outage at one of our Rosebud Mine’s primary customer’s plant. Tons sold at our other mines in 2006 did not differ significantly from 2005 tons sold. We were able to offset our decrease in tons sold by increasing our 2006 average price per ton approximately 12%. At the Rosebud and Beulah mines, we achieved approximately 19% and 16% revenue per ton increases, respectively, as our coal sales contracts provided for pass-through adjustments for higher costs and we renewed an expiring contract at current market prices. At the Absolaka Mine, we achieved a 27% revenue per ton increase due to market price reopeners. Lastly, at the Jewett Mine, we received a 3% revenue per ton increase in 2006, as a result of the interim supply agreement negotiated in 2005.
Our coal segment’s cost of sales in 2006 increased by $22.9 million from 2005. This increase was primarily driven by an $18.0 million increase in cost of sales at the Rosebud Mine which was driven primarily by increased base reclamation activities, higher strip ratios, higher commodity costs, and increased taxes and royalties. The Absaloka Mine’s cost of sales accounted for the remaining $4.9 million increase, which was driven mainly by higher contract mining costs and higher taxes and royalties. Cost of sales in 2006 at our other mines did not differ significantly from 2005.
Our coal segment’s depreciation, depletion, and amortization expenses in 2006 increased by approximately $2.8 million from 2005. This increase resulted from increased depletion expenses for asset retirement obligation assets, which increased at the end of 2005 as a result of updated engineering studies.
Our coal segment’s 2006 selling and administrative expenses decreased by $0.7 million from 2005, primarily as a result of a $1.2 million in settlement costs and related legal fees incurred in 2005.
Independent Power
Power segment operating income was $12.3 million in 2006 compared to $9.6 million in 2005. Our 2006 energy revenues and costs of sales and expenses were $47.9 million and $31.4 million, respectively. In connection with the ROVA acquisition, we changed our method of recognizing revenue under ROVA’s long-term power sales agreements (see Financial Implications of the ROVA Acquisition). For 2006, revenue received under these agreements totaling $14.5 million was deferred. We reported equity in earnings from independent power operations of $7.7 million in 2006 and $12.7 million in 2005. This change was due to our 2006 acquisition and consolidation of ROVA’s results of operations effective July 1, 2006.
The following table summarizes the power segment’s results for the years ended December 31, 2006 and 2005:
(1)
The Company recorded $14.5 million in deferred revenue in 2006 related to capacity payments at ROVA.
For 2006 and 2005, ROVA produced 1,639,000 and 1,601,000 MW hours, respectively, and achieved average capacity factors of 89% and 87%, respectively.
We also recognized $366,000 in equity earnings in 2006, compared to $455,000 in 2005, from our 4.49% interest in the Ft. Lupton project.
During 2006, our Westmoreland Utilities subsidiary, which operates and provides maintenance services to four power plants in Virginia owned by Dominion Virginia Power, contributed $4.1 million of revenue which is shown as energy revenue and had $3.7 million of costs and expenses which are shown as cost of sales-energy.
Heritage
Our 2006 heritage costs increased by $0.4 million over 2005 expenses. Our black lung benefit recorded in 2006 was $0.4 million compared to a benefit of $3.1 million in 2005. The $3.1 million benefit in 2005 resulted from favorable actuarial projections which decreased our obligations. The change in the black lung benefit was partially offset by a decrease from 2005 to 2006, of $2.2 million in our heritage health benefit, Combined Benefit Fund, and workers’ compensation expenses. These costs decreased as a result of lower postretirement medical benefit projections and workers’ compensation costs driven by favorable 2006 trends in our health care expenses.
Corporate
Our corporate selling and administrative expenses increased by $4.4 million from 2005 to 2006. This increase resulted primarily from a $2.3 million increase in compensation expenses combined with increased
personnel costs for the finance staff and the impact of the adoption of SFAS 123 R. Compensation expense increased in part because 2005 benefited from $0.9 million of decreased cost associated with our long-term incentive performance unit plan. Also, contributing to the increase in 2006, was a $1.3 million increase in professional fees, including costs of our 2005 financial statement restatement and a $0.9 million increase in information technology consulting fees for our systems implementation.
Interest
Interest expense was $19.2 million and $10.9 million for 2006 and 2005, respectively. The increase resulted from the $6.8 million in interest expense from ROVA’s project debt following its acquisition and approximately $1.5 million in increased interest expense primarily from ROVA acquisition debt. Interest income increased by $2.6 million in 2006 as a result of $1.2 million in ROVA interest income, and increased interest income from our restricted cash and bond collateral accounts due to increasing interest rates.
Income Tax
Current income tax expense in both 2006 and 2005 relates to obligations for state income taxes. In each of 2006 and 2005 we accrued $2.1 million for tax assessments in North Carolina for prior years.
Results of Operations
Compared to 2004
Coal Operations
The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods:
Coal segment revenues increased from 2004 primarily as a result of a 1.0 million increase in tons sold and because of higher prices, including a one-time “catch-up” payment of $2.4 million received in the first quarter of 2005, for past cost increases for commodities at the Jewett Mine. The increase in tons sold in 2005 came from new or extended sales contracts at the Rosebud Mine, as well as increases at the Jewett and Absaloka mines. The revenue in 2004 includes a $16.3 million Colstrip Units 1&2 arbitration award for the price reopener with the owners of Colstrip Units 1&2 for coal shipped from July 30, 2001 to May 31, 2004.
Coal segment cost of sales increased in 2005 compared to 2004 primarily as a result of increased tons produced, higher commodity prices (for diesel fuel, electricity and explosives) and higher stripping ratios. Very difficult mining conditions and unusually heavy rainfall increased costs at the Beulah Mine in 2005. Production taxes and royalties on the $16.3 million Colstrip Units 1&2 arbitration award increased cost of sales by $5.1 million in 2004. Costs at the Jewett Mine in 2004 included unplanned repairs to a primary dragline combined with significant weather-related production interruptions.
Coal segment depreciation, depletion and amortization increased to $21.3 million in 2005 compared to $18.2 million in 2004. The increase is primarily related to increased coal production, increased capital expenditures at the mines for both continued mine development and the replacement of mining equipment, and increased amortization of capitalized asset retirement costs.
Our coal segment’s 2005 selling and administrative expenses increased from 2004 by approximately $5.8 million primarily as a result of $1.2 million in settlement costs which were incurred in 2005 along with associated legal fees. Also contributing to the increase were increased legal fees associated with the company’s litigation, increased consulting fees related to Sarbanes-Oxley compliance, and increased compensation expense.
Independent Power
Our equity in earnings from the independent power projects were $12.7 million in both 2005 and 2004. For 2005 and 2004, ROVA produced 1,601,000 and 1,625,000 MW hours, respectively, and achieved capacity factors of 87% in 2005 and 88% in 2004. The slightly lower capacity factor in 2005 was the result of increased start-up hours after scheduled outages. In 2005 and 2004, equity in earnings was reduced by $2.7 and $2.0 million, respectively, for costs associated with higher Halifax County personal property tax assessments from prior years, which we unsuccessfully contested. Most of the contested claims were paid to Halifax County in early 2006. In 2005, the ROVA I and II units had more scheduled outages for planned repairs that decreased the capacity factor, and they experienced more unscheduled outages for repairs than in 2004. We recognized $455,000 in equity earnings in 2005, compared to $317,000 in 2004 from our 4.49% interest in the Ft. Lupton project.
Heritage
Heritage health benefit expenses, exclusive of the cumulative effect of change in accounting principle associated with workers’ compensation, were $5.7 million lower in 2005 compared to 2004 due primarily to three factors:
•
Costs for pneumoconiosis (black lung) benefits were $1.6 million in 2004, compared to a benefit of $3.1 million recorded in 2005 as a result of updated actuarial projections.
•
Workers’ compensation expense was $0.9 million less than in 2004 with the conclusion of the case audits discussed below.
•
Costs for the Combined Benefit Fund were $0.8 million less than in 2004 as a result of a court ruling which reduced our 2005 CBF premiums.
Workers’ compensation expense was significantly higher in 2005 and 2004 relative to 2003 because we conducted and completed case audits of all active claims, and because we used updated mortality tables for those claims. Cash payments, however, declined because indemnity payments for a majority of the beneficiaries were satisfied.
We incurred cash costs of $16.9 million for postretirement medical costs during 2005 compared to $16.7 million in 2004. We incurred cash costs of $1.3 million for workers’ compensation during 2005 compared to $1.9 million in 2004.
Corporate
Our corporate selling and administrative expenses decreased by $2.7 million during 2005 compared to 2004. As a result of the decline in the market price of our common stock in 2005, the projected cost of our long-term incentive performance unit plan declined and resulted in a benefit reflected in selling and administrative expenses of $0.9 million compared to an expense of $2.3 million in 2004.
Interest
Interest expense was $10.9 million and $11.0 million for 2005 and 2004, respectively. Interest associated with the increased debt outstanding from the Westmoreland Mining add-on facility and borrowings under our revolving credit facilities was offset by the lower interest expense on the acquisition financing obtained during 2001 as principal balances were reduced. Interest income decreased in 2005 in spite of larger balances in our restricted cash and surety bond collateral accounts because 2004 included $0.7 million in interest relating to the Colstrip Units 1 & 2 arbitration decision. Both years include amortization of debt financing costs.
Income Tax
Current income tax expense in both 2005 and 2004 related to obligations for state income taxes and federal AMT. In 2005 we accrued $2.1 million for tax assessments for prior years in North Carolina.
New Accounting Pronouncements
In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109” (“FIN 48”), which clarifies the accounting for uncertainty in income tax positions. The provisions of FIN 48 are effective for us on January 1, 2007, with the cumulative effect of the change in accounting principle, if any, recorded as an adjustment to opening retained earnings. We are currently evaluating the impact of adopting FIN 48 but do not believe the adoption of FIN 48 will have a material impact on our Consolidated Financial Statements.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which clarifies the definition of fair value, establishes guidelines for measuring fair value, and expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements and eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS 157 will be effective for the Company on January 1, 2008. We are currently evaluating the impact of adopting SFAS 157 but do not believe the adoption of SFAS 157 will have a material impact on our Consolidated Financial Statements.
ITEM 7A
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk, including the effects of changes in commodity prices and interest rates as discussed below.
Commodity Price Risk
The Company produces and sells commodities - principally coal and electric power - and also purchases commodities - principally diesel fuel, steel and electricity.
The Company produces and sells coal through its subsidiaries, WRI, Westmoreland Mining LLC, and Westmoreland Coal Sales Co., and the Company produces and sells electricity and steam through its subsidiary Westmoreland Energy LLC. Nearly all of the Company’s coal production and all of its electricity and steam production are sold through long-term contracts with customers. These long-term contracts reduce the Company’s exposure to changes in commodity prices. These contracts typically contain price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised. The price may be adjusted in accordance with changes in broad economic indicators, such as the consumer price index, commodity-specific indices, such as the PPI-light fuel oils index, and/or changes in our actual costs. Contracts may also contain periodic price reopeners or renewal provisions, which give us the opportunity to adjust the price of our coal to reflect developments in the marketplace.
During 2006, the Company entered into three derivative contracts to manage a portion of its exposure to price volatility of diesel fuel used in its operations. In a typical commodity swap agreement, the Company receives the difference between a fixed price per gallon of diesel fuel and a price based on an agreed upon published, third-party index if the index price is greater than the fixed price. If the index price is lower, the Company pays the difference. By entering into swap agreements, the Company effectively fixes the price it will pay in the future for the quantity of diesel fuel subject to the swap agreement.
The first two contracts covered approximately 4 million gallons of diesel fuel, which represented an estimated two-thirds of the annual consumption at one of our mines, at a weighted average fixed price of $2.01 per gallon. These contracts settled monthly from February to December, 2006. During 2006, the Company fully settled these contracts, which resulted in a loss of approximately $0.2 million.
In October 2006 the Company entered into a derivative contract to manage a portion of its exposure to the price volatility of diesel fuel to be used in its operations in 2007. The contract covers 2.4 million gallons of diesel fuel at a weighted average fixed price of $2.02 per gallon. This contract settles monthly from January to December, 2007. The Company accounts for this derivative instrument on a mark-to-market basis through earnings. The Consolidated Financial Statements as of December 31, 2006 reflect unrealized losses on this contract of $0.3 million, which is recorded in accounts payable and as cost of sales-coal.
In January 2007, the Company entered into an additional derivative contract to manage a portion of its exposure to the price volatility of diesel fuel to be used in its operations in 2007. The contract covers 1.1 million gallons of diesel fuel at a weighted average fixed price of $1.75 per gallon. This contract settles monthly from February to December, 2007.
Interest Rate Risk
The Company and its subsidiaries are subject to interest rate risk on its debt obligations. The Company’s revolving lines of credit have a variable rate of interest indexed to either the prime rate or LIBOR. Based on balances outstanding on the lines of credit as of December 31, 2006, a one percent change in the prime interest rate or LIBOR would increase or decrease interest expense by $130,000 on an annual basis. Westmoreland Mining’s Series D Notes under its term loan agreement have a variable interest rate based on LIBOR. A one percent change in LIBOR would increase or decrease interest expense on the Series D Notes by $146,000 on an annual basis. A portion of ROVA’s project debt under its Credit Agreement also has a variable interest rate based on LIBOR. A one percent change in LIBOR would increase or decrease interest expense on ROVA’s debt by $0.9 million on an annual basis. The Company’s ROVA acquisition debt also has variable interest rates based on LIBOR. A one percent change in LIBOR would increase or decrease interest expense on the acquisition term loan by approximately $0.4 million on an annual basis. The Rosebud Mine has capital leases with variable interest rates. A one percent change in the interest rates for these leases would increase or decrease interest expenses by less than $0.1 million on an annual basis.
The carrying value and estimated fair value of the Company’s long-term debt with fixed interest rates at December 31, 2006 were $154.6 million and $163.0 million, respectively.
The Company’s heritage health benefit expenses are also impacted by interest rate changes because its workers compensation, pension, pneumoconiosis, and postretirement medical benefit obligations are recorded on a discounted basis.
ITEM 8
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
See accompanying Notes to Consolidated Financial Statements.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Operations
See accompanying Notes to Consolidated Financial Statements.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
Consolidated Statement of Shareholders’ Deficit and Comprehensive Loss
Years Ended December 31, 2004, 2005 and 2006
See accompanying Notes to Consolidated Financial Statements.
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
See accompanying Notes to Consolidated Financial Statements.
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations and Liquidity
Westmoreland Coal Company (“the Company”) is an energy company. The Company’s current principal activities, all conducted within the United States, are the production and sale of coal from Montana, North Dakota and Texas; and the development, ownership and management of interests in cogeneration and other non-regulated independent power plants. The Company’s activities are primarily conducted through wholly-owned or majority owned subsidiaries which generally have obtained separate financing.
The major factors impacting the Company’s liquidity are: payments due on the term loan it entered into to acquire various operations and assets from Montana Power and Knife River in May, 2001 (see note 6); payments due on the acquisition debt associated with its purchase of the ROVA interest (see note 6); payments due for the buyout of the Washington Group International mining contract at WRI (see note 21), and additional capital expenditures the Company plans to make when it takes responsibility to operate the mine; cash collateral requirements for additional reclamation bonds in new mining areas; and payments for its heritage health benefit costs. Unforeseen changes in the Company’s ongoing business requirements could also impact its liquidity. The principal sources of cash flow to Westmoreland Coal Company are dividends from WRI, distributions from ROVA and from Westmoreland Mining subject to the provisions in their respective debt agreements and dividends from the subsidiaries that operate power plants.
While the Company believes that it currently has sufficient capital resources and committed financing arrangements to provide it with adequate liquidity through 2007, the variability inherent in the Company’s mining and power operations and the variability of payments under its postretirement medical plans may adversely impact the Company’s actual cash requirements and cash flows. The Company does not believe it has capital resources or committed financing arrangements in place to provide adequate liquidity to meet currently projected cash requirements beginning in early 2008 based on its most recent forecast. The Company is considering several alternatives for raising additional capital during 2007.
One of the alternatives available to the Company is to refinance the $30 million bridge loan used to acquire ROVA with proceeds from an equity offering. Repaying this bridge loan would provide the Company access to the anticipated semi-annual cash distributions from ROVA which are currently required to be applied to the principal and interest payments due on the $30 million bridge loan. If the Company is unable to refinance the bridge loan, it has the option to extend the term of that loan to four years. If it elects to extend the loan beyond its initial one-year term, the Company will be required to issue warrants to the lender to purchase 150,000 shares of common stock at a premium of 15% to the then current stock price. These warrants would be exercisable for a three-year period from the date of issuance. If the term of the loan is extended, all cash distributions would continue to be required to be applied to the principal and interest payments on the loan through its term.
The Company is also considering a common stock rights offering which would allow the Company’s shareholders the opportunity to make an additional investment in the Company. There can be no assurance that a common stock rights offering can be completed on a timely basis, or at all.
The Company believes that one of the other alternatives available to it is the sale of one or more of the Company’s assets. There can be no assurance that any sale could be completed on terms acceptable to the Company.
The accompanying consolidated financial statements are prepared on a going concern basis and do not include any adjustments that might result from the outcome of the uncertainty regarding the Company’s ability to raise additional capital, refinance its debt obligations or sell some of its assets to meet its obligations.
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Consolidation Policy
The Consolidated Financial Statements of Westmoreland Coal Company (the “Company”) include the accounts of the Company and its majority-owned subsidiaries, after elimination of intercompany balances and transactions. The Company uses the equity method of accounting for investments in affiliates where its ownership is between 20% and 50% and for partnerships and joint ventures in which less than a controlling interest is held.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
The Company has significant long-term liabilities relating to retiree health care, work-related injuries and illnesses, and defined benefit pension plans. Each of these liabilities is actuarially determined and the Company uses various actuarial assumptions, including discount rates and future cost trends, to estimate the costs and obligations for these items. In addition, the Company has significant asset retirement obligations that involve estimating the costs to reclaim mining lands and the timing of cash payments for such costs. If these assumptions do not materialize as expected, actual cash expenditures and costs incurred could differ materially from current estimates. Moreover, regulatory changes could increase the cost to satisfy these or additional obligations.
Coal Revenues
The Company recognizes coal sales revenue at the time title passes to the customer in accordance with the terms of the underlying sales agreements and after any contingent performance obligations have been satisfied. Coal sales revenue is recognized based on the pricing contained in the coal contracts in place at the time that title passes and any retroactive pricing adjustments to those contracts are recognized as revised agreements are reached with the customers and any performance obligations included in the revised agreements are satisfied.
Cash Equivalents
The Company considers all highly liquid debt instruments purchased with original maturities of three months or less to be cash equivalents. All such instruments are carried at cost, which approximates market. Cash equivalents consist of Eurodollar time deposits, money market funds and bank repurchase agreements.
Inventories
Inventories, which include materials and supplies as well as raw coal, are stated at the lower of cost or market. Cost is determined using the average cost method.
Property, Plant and Equipment
Property, plant and equipment are carried at cost and include expenditures for new facilities and those expenditures that substantially increase the productive lives of existing plant and equipment. Maintenance and repair costs are expensed as incurred. Mineral rights and development costs are depleted based upon estimated recoverable proven and probable reserves. Plant and equipment are depreciated on a units-of-production or straight-line basis over the assets’ estimated useful lives, ranging from 3 to 40 years. The Company assesses the carrying value of its property, plant and equipment for impairment whenever events or changes in
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing estimated undiscounted cash flows expected to be generated from such assets to their net book value. If net book value exceeds estimated cash flows, the asset is written down to fair value. When an asset is retired or sold, its cost and related accumulated depreciation and depletion are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss. Fully depreciated plant and equipment still in use is not eliminated from the accounts.
Deferred Overburden Removal Costs
The Company accounts for the costs of removing overburden (stripping costs) in accordance with EITF Issue No. 04-6, “Accounting For Stripping Costs Incurred During Production In The Mining Industry” (“EITF No. 04-6”). All stripping costs incurred after January 1, 2006 during the production phase are absorbed into inventory and recognized as a component of cost of sales - coal in the same period the related revenue is recognized. Stripping costs incurred in 2005 and 2004, prior to the January 1, 2006 effective date of EITF No. 04-6, during the production phases were capitalized and deferred and then expensed as cost of sales - coal using methods and estimates consistent with those used to account for pre-production costs.
During the development of the Company’s mines, before production commences, the costs of removing overburden, net of amounts reimbursed by customers, are capitalized as part of the depreciable cost of building and constructing the mine. Those costs are amortized on a unit of production basis as the coal is produced, based on estimates of total reserves.
Income Taxes
The Company accounts for deferred income taxes using the asset and liability method. Deferred tax liabilities and assets are recognized for the expected future tax consequences of events that have been reflected in the Company’s financial statements based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities, as well as net operating loss and tax credit carryforwards, using enacted tax rates in effect in the years in which the differences are expected to reverse. The Company establishes a valuation allowance against its net deferred tax assets to the extent the Company believes that it is more likely than not that it will not realize the net deferred tax assets. The ultimate realization of deferred tax assets is dependent upon the generation of the appropriate type of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment.
Postretirement Health Care Benefits and Pension Plans
The Company and its subsidiaries provide certain health care benefits for retired employees and their dependents either voluntarily or as a result of the Coal Act. Substantially all of the Company’s current employees may also become eligible for these benefits if certain age and service requirements are met at the time of termination or retirement as specified in the plan document. The majority of these benefits are provided through self-insured programs.
The Company accounts for postretirement benefits other than pensions in accordance with SFAS No. 106 “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (“SFAS 106”), as amended by SFAS No. 158 “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS 158”). SFAS No. 106 requires the cost to provide the benefits to be accrued over the employees’ period of active service. These costs are determined on an actuarial basis.
The Company elected under SFAS No. 106 to amortize its transition obligation for past service costs relating to these benefits over a twenty year period. Unrecognized actuarial gains and losses are amortized
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
over the estimated average remaining service period for active employee plans and over the estimated average remaining life expectancy of the participants for retiree plans.
For UMWA represented union employees who retired prior to 1976, the Company provides similar medical benefits by making payments to a multiemployer union trust fund. The Company expenses such payments when they become due.
The Company sponsors non-contributory defined benefit pension plans which are accounted for in accordance with SFAS No. 87 “Employers’ Accounting for Pensions” (“SFAS 87”), as amended by SFAS No. 158. SFAS No. 87 requires the cost to provide the benefits to be accrued over the employees’ period of active service. These costs are determined on an actuarial basis.
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS 158. This statement requires balance sheet recognition of the overfunded or underfunded status of pension and postretirement benefit plans. Under SFAS 158, actuarial gains and losses, prior service costs or credits, and any remaining transition assets or obligations that have not been recognized under previous accounting standards must be recognized as assets or liabilities with a corresponding adjustment to accumulated other comprehensive income, net of tax effects, until they are amortized as a component of net periodic benefit cost. SFAS 158 is effective for publicly-held companies for fiscal years ending after December 15, 2006. Based on the Company’s unfunded obligations as of December 31, 2006, the Company’s assets decreased by approximately $4.5 million, and liabilities for pension and other postretirement benefit plans were increased by approximately $90.7 million, which resulted in an increase in shareholders’ deficit of approximately $95.2 million. The adoption of SFAS 158 will not affect the Company’s future pension and postretirement medical benefit expenses, as determined under the provisions of SFAS 106 and SFAS 87.
Workers’ Compensation Benefits
The Company is self-insured for workers’ compensation claims incurred prior to 1996. Workers’ compensation claims incurred after January 1, 1996 are covered by a third party insurance provider.
The liabilities for workers’ compensation claims are actuarially determined estimates of the ultimate losses incurred based on the Company’s experience, and include a provision for incurred but not reported losses. Adjustments to the probable ultimate liabilities are made annually based on subsequent developments and experience and are included in operations at the time of the revised estimate.
Effective January 1, 2005, Westmoreland changed its method of accounting for workers’ compensation. Under the new method, the liability is recorded on a discounted basis. The gross obligation is actuarially determined using historical five year trends for workers’ compensation medical expenses and life expectancies. A risk-free interest rate (4.75% at December 31, 2006) is then used to present value the obligation. Westmoreland believes this change is preferable since it aligns the accounting of workers’ compensation liabilities with the Company’s other long-term employee benefit obligations, which are recorded on a discounted basis. In addition, these obligations have a predictable payment pattern. The change decreased the workers’ compensation liability by $2.7 million at January 1, 2005. If this change were applied retroactively, the loss for 2004 would have decreased by $1.0 million ($0.12 per share).
Asset Retirement Obligations
SFAS No. 143, “Accounting for Asset Retirement Obligations”, addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The Company’s asset retirement obligation (“ARO”) liabilities primarily consist of estimated costs related to reclaiming surface land and support facilities at its mines in accordance with federal and state reclamation laws as defined by each mining permit.
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The Company estimates its ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future costs for a third party to perform the required work. Cost estimates are escalated for inflation, and then discounted at the credit-adjusted risk-free rate. The Company records an ARO asset associated with the initial recorded liability. The ARO asset is amortized based on the units of production method over the estimated recoverable, proven and probable reserves at the related mine, and the ARO liability is accreted to the projected settlement date. Changes in estimates could occur due to revisions of mine plans, changes in estimated costs, and changes in timing of the performance of reclamation activities.
Reclamation Deposits and Contractual Third Party Reclamation Receivables
Certain of the Company’s customers have either agreed to reimburse the Company for reclamation expenditures as they are incurred or have pre-funded a portion of the expected reclamation costs. Amounts received from customers and held on deposit are recorded as reclamation deposits. Amounts that are reimbursable by customers are recorded as third party reclamation receivables when the related reclamation obligation is recorded.
Financial Instruments
Pursuant to SFAS No. 107, “Disclosures about Fair Value of Financial Instruments”, the Company is required to disclose the fair value of financial instruments where practicable. The carrying amounts of cash equivalents, accounts receivable and accounts payable reflected on the balance sheets approximate the fair value of these instruments due to the short duration to maturities. The fair value of long-term debt is based on the interest rates available to the Company for debt with similar terms and maturities.
Comprehensive Income
During 2006, 2005, and 2004, the Company recognized an additional minimum pension liability as a result of the accumulated pension benefit obligation exceeding the fair value of pension plan assets at year end. The additional minimum liability is reported as a separate component of other comprehensive loss. The additional minimum liability decreased by $1.7 million in 2006, and increased by $3.4 million and $1.2 million in 2005 and 2004, respectively.
During 2006, the Company adopted SFAS 158 (as discussed in note 3) and recognized the underfunded status of its pension and postretirement benefit plans. Based on its unfunded obligations, the Company recorded an unfunded pension liability of $4.8 million and an unfunded postretirement benefit obligation of $90.4 million as a cumulative effect adjustment to accumulated other comprehensive loss in shareholder’s deficit.
In 1992, ROVA entered into interest rate exchange agreements (“swap agreements”) with banks which were created for the purpose of securing a fixed interest rate. These swap agreements were classified as cash flow hedges, and therefore, unrealized gains and losses on these swap agreements were recorded as a separate component of accumulated other comprehensive loss in shareholder’s deficit. The swap agreements were settled during 2006.
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The following is a summary of other comprehensive loss for the years ending December 31, 2004, 2005, and 2006:
Earnings Per Share
Basic earnings per share is computed by dividing net loss available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined on the same basis except that the weighted average shares outstanding are increased to include additional shares for the assumed exercise of stock options and stock appreciation rights (SARs), if dilutive, and the impact of restricted stock outstanding. The number of additional shares from options and SARs is calculated by assuming that outstanding stock options were exercised and that the proceeds from such exercises were used to acquire shares of common stock at the average market price during the reporting period. The number of additional shares from restricted stock is calculated by assuming that an amount equal to the unamortized compensation costs attributable to the restricted shares outstanding is used to acquire shares of common stock at the average market price during the reporting period. For the years ended December 31, 2006, 2005 and 2004, the Company reported a net loss applicable to common shareholders, as a result, all potential shares were antidilutive.
The following is a summary of the securities that could potentially dilute basic earnings per share, but have been excluded from the computations of diluted income loss per share for the years ended December 31, 2006, 2005 and 2004:
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Reclassifications
Certain prior year amounts have been reclassified to conform to the current year presentation.
Recent Accounting Pronouncements
In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109” (“FIN 48”), which clarifies the accounting for uncertainty in income tax positions. The provisions of FIN 48 are effective for the Company on January 1, 2007, with the cumulative effect of the change in accounting principle, if any, recorded as an adjustment to opening retained earnings. The Company is currently evaluating the impact of adopting FIN 48 but does not believe the adoption of FIN 48 will have a material impact on its Consolidated Financial Statements.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”), which clarifies the definition of fair value, establishes guidelines for measuring fair value, and expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements and eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS 157 will be effective for the Company on January 1, 2008. The Company is currently evaluating the impact of adopting SFAS 157 but does not believe the adoption of SFAS 157 will have a material impact on its Consolidated Financial Statements.
2.
ROVA ACQUISITION
On June 29, 2006, the Company acquired a 50% interest in a partnership which owns the 230 MW Roanoke Valley power plant located in Weldon, North Carolina (“ROVA”) from a subsidiary of E.ON U.S. LLC - formerly LG&E Energy LLC. The acquisition increased the Company’s ownership interest in the partnership to 100%. As part of the transaction, the Company acquired certain additional assets from LG&E Power Services LLC, a subsidiary of E.ON U.S. LLC, consisting primarily of five contracts under which two subsidiaries of the Company will now operate and provide maintenance services to ROVA and four power plants in Virginia owned by Dominion Virginia Power. These contracts are referred to as operating agreements.
The Company paid $27.5 million in cash at closing for the 50% interest in ROVA. In conjunction with the acquisition of ROVA, the Company paid a $2.5 million fee to Dominion North Carolina Power in exchange for its agreement to waive the right of first refusal which it claimed to have in connection with the transaction. The total purchase price of $30.3 million included $0.3 million in transaction costs. The Company also contributed $5.0 million to ROVA which was deposited into a debt protection account to replace collateral previously provided by E.ON U.S. LLC.
The Company financed the acquisition and the deposit to the debt protection account with a $30 million bridge loan facility from SOF Investments, L.P. (“SOF”), a $5 million term loan with First Interstate Bank, and with corporate funds (see Note 6).
As a result of the acquisition, the accounts of ROVA have been included in the consolidated balance sheet beginning on June 30, 2006. For financial reporting purposes, the acquisition is deemed to have occurred on June 30, 2006, and ROVA’s results of operations have been consolidated with the Company’s beginning July 1, 2006. The purchase price has been allocated based upon an appraised fair value of the identifiable assets acquired and liabilities assumed. The excess of fair value of the net identifiable assets acquired over the purchase price was allocated as a pro rata reduction of the amounts that otherwise would have been assigned to property, plant, and equipment and intangible assets.
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The $30.3 million purchase price for the additional 50% of ROVA acquired was allocated as follows (in thousands):
Restricted assets represent restricted cash deposits required to be maintained under ROVA’s debt agreement. Debt consists of term loans and bonds issued which were used primarily to fund the construction of the facility and qualified expenditures.
The initial accounts of ROVA, including the effects of the purchase price adjustments attributable to the acquisition, that were included in the Company’s Consolidated Balance Sheet of June 30, 2006 as a result of the acquisition and consolidation of 100% of ROVA are as follows (in thousands):
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Intangible assets and liabilities acquired include the estimated fair value of two power purchase agreements and two coal supply agreements. The Company recorded an asset of $0.3 million for one of the power purchase agreements, assets totaling $13.3 million for the two coal supply agreements, and a liability of $13.3 million for the other power purchase agreement. The intangible assets and liabilities are being amortized over the terms of the related agreements. The net amortization of the intangible asset for the coal supply agreement and the intangible liability for the power purchase agreement was $0.3 million in 2006.
The following table summarizes the consolidated pro forma results of operations for the combined companies for the years ended December 31, 2006 and 2005 had the ROVA acquisition taken place at the beginning of those periods (in thousands, except per share data):
ROVA’s historical accounting policy for revenue recognition has been to record revenue as amounts were invoiced pursuant to the provisions of the power sales agreements. The power sales agreements were entered into prior to the effective date of EITF 91-06, “Revenue Recognition of Long-Term Power Sales Contracts”. Accordingly, the agreements were not subject to the accounting requirements of that consensus. The agreements also were entered into prior to the effective date of the consensus of EITF 01-08, “Determining Whether an Arrangement Contains a Lease” (“EITF 01-08”), and accordingly were not subject to the accounting requirement of that consensus.
With the Company’s acquisition of the remaining 50% interest in ROVA, the power sales agreements are considered to be within the scope of EITF 01-08. Under the provisions of EITF 01-08 the power sales arrangements are considered to contain a lease within the scope of SFAS No. 13, “Accounting for Leases”. The lease is classified as an operating lease, and as a result, the Company recognizes amounts invoiced under the power sales agreements as revenue based on the per kilowatt hour weighted average of the capacity payments estimated to be received over the remaining term of the power sales agreements. The capacity payments that ROVA receives are higher in the first 15 years of the power sales agreements (through 2009 for ROVA I and 2010 for ROVA II), but decrease for the remaining 10 years of the agreements. As a result of this change in revenue recognition, adjustments were included in the pro forma statements of operations presented above to reduce revenue in 2006 and 2005 by $28.6 million and $29.0 million, respectively.
The pro forma statements of operations also include adjustments for the amortization of intangible assets, amortization of fair market value adjustments to property, plant, and equipment and debt, and interest expense on the acquisition debt.
3.
CHANGES IN ACCOUNTING PRINCIPLES
In September 2006, the FASB issued SFAS No. 158, an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (“SFAS 158”). This statement requires balance sheet recognition of the overfunded or underfunded status of pension and postretirement benefit plans. Under SFAS 158, actuarial gains and losses, prior service costs or credits, and any remaining transition assets or obligations that have not been recognized under previous accounting standards must be recognized as assets or liabilities with a corresponding
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Notes to Consolidated Financial Statements - (Continued)
adjustment to accumulated other comprehensive loss, net of tax effects, until they are amortized as a component of net periodic benefit cost. SFAS 158 is effective for publicly-held companies for fiscal years ending after December 15, 2006. Based on the Company’s unfunded obligations as of December 31, 2006, the Company’s assets decreased by approximately $4.5 million, and liabilities for pension and other postretirement benefit plans increased by approximately $90.7 million, resulting in an increase in shareholders’ deficit of approximately $95.2 million. The adoption of SFAS 158 will not affect the Company’s future pension and postretirement medical benefit expenses, as determined under the provisions of SFAS 106 and SFAS 87.
The following is a summary of the effect of the adoption of SFAS 158 on the Company’s Balance Sheet as of December 31, 2006 (in thousands):
Recognition of Revenue Under Power Sales Agreements
In connection with the acquisition of the remaining 50% interest in ROVA, the Company has applied the provisions of EITF 01-08, “Determining Whether an Arrangement Contains a Lease” (see Note 2) to two power sales agreements. A portion of the capacity payments under ROVA’s two power sales agreements are considered to be operating leases under EITF 01-08. Under both agreements, ROVA invoices and collects the capacity payments based on kilowatt hours produced if the units are dispatched or for the kilowatt hours of available capacity if the units are not fully dispatched. Under the power sales agreement for ROVA II, ROVA also collects capacity payments during periods of scheduled outages based on the kilowatt hours of dependable capacity of the unit. The capacity payments that ROVA invoices and collects are higher in the first 15 years of the power sales agreements (through 2009 for ROVA I and 2010 for ROVA II), but decrease for the remaining 10 years of the agreements due to a reduction in the rate paid per MW hour of capacity. Effective July 1, 2006, the Company is recognizing amounts invoiced under the power sales agreements as revenue on a pro rata basis, based on the weighted average per kilowatt hour capacity payments estimated to be received over the remaining term of the power sales agreements. Under this method of recognizing revenue, $14.5 million of amounts invoiced during 2006 have been deferred from recognition until 2010 and beyond.
Deferred Overburden Removal Costs
In June 2005, the FASB ratified a modification to the consensus reached in EITF 04-06. The EITF clarified that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. The effect of initially applying this consensus is accounted for in a manner similar to a cumulative effect adjustment with the adjustment recognized in the opening balance of retained earnings in the year of adoption. The Company adopted EITF 04-6 effective January 1, 2006. The adjustment to eliminate deferred stripping costs, previously recorded on the balance sheet as deferred overburden removal costs, was recorded
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Notes to Consolidated Financial Statements - (Continued)
as a $16.8 million cumulative effect adjustment to the beginning accumulated deficit as of January 1, 2006. During 2006, net loss reported was less than $0.1 million less than it would have been under the Company’s previous methodology of accounting for deferred stripping costs.
Share-Based Payments
In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” (“SFAS 123(R)”), which replaces SFAS No. 123 and supersedes APB Opinion No. 25. SFAS No. 123(R) requires all share-based payments to employees and directors, including grants of stock options, be recognized in the financial statements based on their fair values.
The Company adopted SFAS No. 123(R) on January 1, 2006, as prescribed, using the modified prospective method. Accordingly, compensation expense for all newly granted awards and awards modified, repurchased, or cancelled after January 1, 2006 is being recognized ratably over the vesting period based on the fair value of the awards at the date of grant.
Compensation expense for the unvested portion of stock option awards that were outstanding as of January 1, 2006 is being recognized ratably over the remaining vesting period, based on the fair value of the awards at date of grant as calculated for the pro forma disclosure under SFAS No. 123. See Note 12 “Incentive Stock Options and Stock Appreciation Rights”.
There was no cumulative effect adjustment recorded in the Company’s Statement of Operations for the change in accounting related to the adoption of SFAS 123(R). The adoption of SFAS 123(R) had the effect of increasing the net loss for the year ended December 31, 2006 by approximately $0.6 million.
Staff Accounting Bulletin No. 108 (“SAB 108”)
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin, or SAB No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”. SAB No. 108 provides guidance for quantifying and assessing the materiality of misstatements of financial statements, including uncorrected misstatements that were not material to prior years’ financial statements. SAB 108 provides for a one time transitional adjustment to retained earnings (accumulated deficit) for errors which were not previously deemed to be material, but which are material under the guidance of SAB 108. The Company adopted SAB No. 108 and recorded a cumulative effect adjustment to correct its accounting for accrued postretirement medical benefits, and to correct a litigation accrual that should have been recorded in purchase accounting in 2001.
4.
INVESTMENT IN INDEPENDENT POWER PLANTS
Westmoreland Energy LLC (“WELLC”), a wholly owned subsidiary of the Company, has acquired general and limited partner interests in partnerships which were formed to develop and own cogeneration and other non-regulated independent power plants. As of December 31, 2006, the Company owns a 4.49% interest in partnerships which own a 290 MW power plant in Ft. Lupton, Colorado (“Ft. Lupton”). The Company’s share of the earnings of Ft. Lupton were $0.4 million, $0.5 million, and $0.3 million for the years ended December 31, 2006, 2005, and 2004, respectively.
Prior to the acquisition of the remaining ownership interest in ROVA in 2006, the Company owned a 50% interest in ROVA. The following is a summary of ROVA’s balance sheet as of December 31, 2005 and its
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
results of operations for the six months ended June 30, 2006 and the years ended December 31, 2005 and 2004:
The results of operations for 2006 include the period from January 1, 2006 to June 30, 2006. Thereafter, the results of operations of ROVA are consolidated.
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Notes to Consolidated Financial Statements - (Continued)
5.
RESTRICTED CASH AND BOND COLLATERAL
The Company’s restricted cash and bond collateral consist of the following:
For all of its restricted cash and bond collateral accounts, the Company can select from several investment options for the funds and receives the investment returns on these investments.
Corporate
The Company is required to obtain surety bonds in connection with its self-insured workers’ compensation plan and certain health care plans. The Company’s surety bond underwriters require collateral to issue these bonds. As of December 31, 2006 and 2005, the amount held in collateral accounts was $5.5 million and $5.3 million respectively, for the workers’ compensation plan and $4.4 million and $4.2 million respectively, for health care plans.
Coal Segment
Pursuant to the WML term loan agreement, WML is required to maintain a debt service reserve account and a long-term prepayment account. As of December 31, 2006 and December 31, 2005, there was a total of $10.3 million and $10.0 million, respectively in the debt service reserve account. The prepayment account is to be used to fund a $30.0 million payment due December 31, 2008 for the Series B notes. There was $15.1 million and $12.2 million in the prepayment account at December 31, 2006 and 2005, respectively.
As of December 31, 2006 the Company had reclamation bond collateral in place for its active Absaloka, Rosebud, Jewett and Beulah mines. These government-required bonds assure that coal mining operations comply with applicable federal and state regulations relating to the performance and completion of final
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
reclamation activities. The amounts deposited in the bond collateral account secure the bonds issued by the bonding company.
ROVA
Pursuant to the terms of its Credit Agreement, ROVA must maintain a debt protection account (“DPA”). At December 31, 2006 the DPA was funded with $28.1 million. Additional funding of the DPA of $1.1 million per year is required through 2008. The required funding level is reduced by $6.7 million in 2009 and by $3.0 million in 2010.
The Credit Agreement also requires ROVA to fund a repairs and maintenance account and an ash reserve account totaling $3.2 million from January 31, 2004 through January 31, 2010, after which date the funding requirement reduces to $2.8 million. The funds for the repairs and maintenance account are required to be deposited every six months based on a formula contained in the agreement. The ash reserve account was fully funded at December 31, 2006. As of December 31, 2006, these accounts had a combined balance of $1.2 million.
6.
LINES OF CREDIT AND LONG-TERM DEBT
The amounts outstanding at December 31, 2006 and 2005 under the Company’s lines of credit and long-term debt consist of the following:
The ROVA current and total term debt includes debt premiums of $0.8 million and $4.9 million, respectively.
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Notes to Consolidated Financial Statements - (Continued)
The maturities of all long-term debt and the revolving credit facilities outstanding at December 31, 2006 are (in thousands):
Corporate Revolving Line of Credit
The Company has a $14.0 million revolving credit facility with First Interstate Bank. Interest is payable monthly at the bank’s prime rate (8.25% per annum at December 31, 2006). The Company is required to maintain financial ratios relating to liquidity, indebtedness, and net worth. As of December 31, 2006, the Company was in compliance with such covenants. The revolving credit facility is collateralized by the Company’s stock in Westmoreland Resources Inc. (“WRI”), which owns the Absaloka Mine in Big Horn County, Montana, and the dragline located at WRI’s Absaloka mine. In June 2006, the term of this facility was extended to June 30, 2008.
Westmoreland Mining LLC
Westmoreland Mining LLC (“WML”) has a $20.0 million revolving credit facility (the “Facility”) with PNC Bank, National Association (“PNC”) which expires on April 27, 2008. The interest rate is either PNC’s Base Rate plus 1%, or a Euro-Rate plus 3%, at WML’s option. As of December 31, 2006, the interest rate under the Facility is 9.25% per year. In addition, a commitment fee of 1/2 of 1% of the average unused portion of the available credit is payable quarterly. The amount available under the facility is based upon, and any outstanding amounts are secured by, eligible accounts receivable.
WML has a term loan agreement under which $56.6 million in Series B Notes, $20.4 million in Series C Notes and $14.6 million in Series D Notes are outstanding as of December 31, 2006. The Series B Notes bear interest at a fixed interest rate of 9.39% per annum; the Series C Notes bear interest at a fixed rate of 6.85% per annum; and the Series D Notes bear interest at a variable rate based upon LIBOR plus 2.90% (8.26% per annum at December 31, 2006). All of the notes are secured by the assets of WML and the term loan agreement requires the Company to comply with certain covenants and minimum financial ratio requirements related to liquidity, indebtedness, and capital investments. As of December 31, 2006, WML was in compliance with such covenants.
The Company engages in leasing transactions for equipment utilized in operations. Certain leases at the Rosebud Mine qualify as capital leases and were recorded as an asset and liability at the net present value of the minimum lease payments at the inception of the leases. The present value of these lease payments at December 31, 2006 and 2005 was $3.2 million and $3.4 million respectively, at a weighted average interest rate of 4.68% and 5.22%, respectively. The Jewett Mine also has a note payable outstanding from the purchase of a parcel of land at December 31, 2006, in the amount of $0.3 million ($0.5 million at December 31, 2005), with interest payable at 6.0% annually.
ROVA
The Company funded the ROVA acquisition and debt protection account deposit in part with a $30.0 million bridge loan facility from SOF Investments, L.P. (“SOF”) and a $5.0 million term loan with First
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Notes to Consolidated Financial Statements - (Continued)
Interstate Bank. The SOF bridge loan has a one-year term extendable to four years at the option of the Company. The loan bears interest at the London Interbank Offering Rate (“LIBOR”) plus 4% (9.53% per annum at December 31, 2006). The Company also paid SOF a 1% closing fee. If the Company elects to extend the loan beyond its initial one-year term, it will be required to issue warrants to purchase 150,000 shares of the Company’s common stock to SOF at a premium of 15% to the then current stock price. These warrants would be exercisable for a three-year period from the date of issuance. The loan is secured by a pledge of the semi-annual cash distributions from ROVA commencing in January 2007 as well as pledges from the Company’s subsidiaries that directly or indirectly acquired the operating agreements.
The $5.0 million term loan with First Interstate Bank has a one-year term expiring June 29, 2007. Interest is payable at the bank’s prime rate (8.25% per annum at December 31, 2006).
On December 18, 1991, ROVA entered into a Credit Agreement (“Tranche A”) with a consortium of banks (the “Banks”) and an institutional lender for the financing and construction of the first ROVA facility. On December 1, 1993, the Credit Agreement was amended and restated (“Tranche B”) to allow for the financing and construction of the second ROVA facility. Under the terms of the Credit Agreement, ROVA was permitted to borrow up to $229.9 million from the banks (“Bank Borrowings”), $120.0 million from an institutional lender, and $36.8 million in tax-exempt facility revenue bonds (“Bond Borrowings”) under two indenture agreements with the Halifax County, North Carolina, Industrial Facilities and Pollution Control Financing Authority (“Financing Authority”). The borrowings are evidenced by promissory notes and are secured by substantially all of the book value of ROVA’s assets including land, the facilities, ROVA’s equipment, inventory, accounts receivable, certain other assets and assignment of all material contracts. Bank Borrowings amounted to $51.2 million at December 31, 2006, and mature in 2008. The Credit Agreement provides for interest to be paid on the Bank Borrowings at rates set at varying margins in excess of the Banks’ base rate, LIBOR or certificate of deposit rate, for various terms from one day to one year in length, each selected by ROVA when amounts are borrowed. The weighted average interest rate on the Bank Borrowings at December 31, 2006, was 6.9% per annum.
Under the terms of the Credit Agreement, interest on the Tranche A institutional borrowings is fixed at 10.42% per annum and interest on the Tranche B institutional borrowings is fixed at 8.33% per annum. The Credit Agreement requires repayment of the Tranche A institutional borrowings in 38 semiannual installments ranging from $0.9 million to $4.3 million. Payment of the Tranche A institutional borrowings commenced in 1996 and is currently scheduled to be completed in 2014.
The Credit Agreement requires repayment of the Tranche B institutional borrowings in 40 semiannual installments ranging from $0.3 million to $6.5 million. Payment of the Tranche B institutional borrowings commenced in 1996 and is currently scheduled to be completed in 2015.
In accordance with the indenture agreements, the Financing Authority issued $29.5 million of 1991 Variable Rate Demand Exempt Facility Revenue Bonds (“1991 Bond Borrowings”) and $7.2 million of 1993 Variable Rate Demand Exempt Facility Revenue Bonds (“1993 Bond Borrowings”). The 1991 Bond Borrowings and the 1993 Bond Borrowings are secured by irrevocable letters of credit in the amounts of $30.1 million and $7.4 million, respectively, which were issued by the banks. The weighted average interest rate on the bonds at December 31, 2006 was 4.03% per annum. The 1991 Bond Indenture Agreement requires repayment of the 1991 Bond Borrowings in four semi-annual installments of $1.2 million, $1.2 million, $14.8 million, and $12.4 million. The first installment of the 1991 Bond Borrowings is due in January 2008. The 1993 Indenture Agreement requires repayment of the 1993 Bond Borrowings in three semi-annual installments of $1.6 million, $1.8 million and $3.8 million. The first installment is due in July 2009.
Irrevocable letters of credit in the amounts of $4.5 million and $1.5 million were issued to ROVA’s customer by the banks on behalf of ROVA for ROVA I and ROVA II, respectively, to ensure performance under their respective power sales agreements.
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Notes to Consolidated Financial Statements - (Continued)
The debt agreements contain various restrictive covenants primarily related to construction of the facilities, maintenance of the property, and required insurance. Additionally, financial covenants include restrictions on incurring additional indebtedness and property liens, paying cash distributions to the partners, and incurring various commitments without lender approval. At December 31, 2006, ROVA was in compliance with the various covenants.
7.
POSTRETIREMENT MEDICAL BENEFITS
Single-Employer Plans
The Company and its subsidiaries provide certain health care benefits for retired employees and their dependents either voluntarily or as a result of the Coal Act. Under the Coal Act, the Company is required to provide postretirement medical benefits for certain UMWA miners and their dependants by making payments into certain benefit plans. Substantially all of the Company’s current employees may also become eligible for these benefits if certain age and service requirements are met at the time of termination or retirement as specified in the related plan documents. These benefits are provided through self-insured programs. The Company follows SFAS No. 106 as amended by SFAS No. 158 and has elected to amortize its unrecognized, unfunded accumulated postretirement benefit obligation over a 20-year period.
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The following table sets forth the actuarial present value of postretirement medical benefit obligations and amounts recognized in the Company’s financial statements:
The present value of the actuarially determined liability for postretirement medical costs decreased approximately $33.7 million between December 31, 2005 and 2006, principally because of the increase in discount rate and favorable changes in mortality, termination, and retirement experience. The discount rate is adjusted annually based on an Aa corporate bond index adjusted for the difference in the duration of the bond index and the duration of the benefit obligations.
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Notes to Consolidated Financial Statements - (Continued)
The components of net periodic postretirement benefit cost are as follows:
Of the total net periodic benefit cost, $22.0 million, $23.5 million and $22.9 million relates to the Company’s former Eastern mining operations and is included in heritage health benefit costs in 2006, 2005, and 2004, respectively. The remainder of $1.6 million, $1.0 million and $0.8 million, respectively, relates to current operations and is included in selling and administrative expenses.
The health care cost trend assumed on covered charges was 10.0% for 2007, decreasing by 1% per year to an ultimate trend of 5.0% in 2012 and beyond. The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement health care benefits.
The effect of a one percent change on the health care cost trend rate used to calculate periodic postretirement medical costs and the related benefit obligation are summarized in the table below:
Based on the same assumptions used in measuring the Company’s benefit obligation at December 31, 2006, the Company expects to pay health benefits in each year from 2007 to 2011 of $17.0 million, $17.7 million, $18.3 million, $18.7 million, and $18.8 million, respectively. The aggregate health benefits expected to be paid in the five-years from 2012 to 2016 are $90.0 million.
Multiemployer Plan (Combined Benefit Fund)
The Company makes payments to the UMWA Combined Benefit Fund (“CBF”), which is a multiemployer health plan neither controlled by or administered by the Company. The CBF is designed to pay health care benefits to UMWA workers (and dependents) who retired prior to 1976. The Company is required by the Coal Act to make monthly premium payments into the CBF. These payments are based on the number of the Company’s UMWA employees who retired prior to 1976, and the Company’s pro-rata assigned share of UMWA retirees whose companies are no longer in business. The Company expenses payments to the CBF when they are due. Payments in 2006, 2005 and 2004 were $3.6 million, $4.6 million and $5.4 million, respectively. As discussed in Note 18, the Company expects to recover excessive premium payments made in prior years.
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Notes to Consolidated Financial Statements - (Continued)
Workers’ Compensation Benefits
The Company was self-insured for workers’ compensation benefits prior to January 1, 1996. Beginning in 1996, the Company purchased third party insurance for new workers’ compensation claims. Based on updated actuarial and claims data, $1.3 million, $2.5 million, and $3.4 million was charged to operations in 2006, 2005 and 2004, respectively, for self insured workers compensation benefits. Payments for workers’ compensation benefits were $1.1 million, $1.3 million, and $1.9 million in 2006, 2005 and 2004, respectively.
The discount rates used in determining the workers’ compensation benefit accruals at December 31, 2006 and 2005 were 4.75% and 5.50%, respectively.
Pneumoconiosis (Black Lung) Benefits
The Company is self-insured for federal and state pneumoconiosis benefits for former employees and has established an independent trust to pay these benefits.
The following table sets forth the funded status of the Company’s obligation:
The overfunded status of the Company’s obligation is included as excess of trust assets over pneumoconiosis benefit obligation in the accompanying Consolidated Balance Sheet. Of this excess, $5.6 million is recorded in current assets reflecting the portion of the excess the Company is able to withdraw during 2007.
The discount rates used in determining the accumulated pneumoconiosis benefit obligation at December 31, 2006 and 2005 were 5.80% and 5.65%, respectively.
8.
PENSION PLANS
Defined Benefit Pension Plans
The Company provides defined benefit pension plans for its full-time employees. Benefits are generally based on years of service and the employee’s average annual compensation for the highest five continuous years of employment as specified in the plan agreement. The Company’s funding policy is to contribute annually the minimum amount prescribed, as specified by applicable regulations. Prior service costs and actuarial gains and losses are amortized over expected future period of service of the plan’s participants using the straight-line method.
Supplemental Executive Retirement Plan
The Company maintains a Supplemental Executive Retirement Plan (“SERP”). The SERP is an unfunded non-qualified deferred compensation plan which provides benefits to certain employees beyond the maximum
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Notes to Consolidated Financial Statements - (Continued)
limits imposed by the Employee Retirement Income Security Act and the Internal Revenue Code. The SERP plan is unfunded.
The following table provides a reconciliation of the changes in the benefit obligations of the plans, and the fair value of assets of the qualified plan for the years ended December 31, 2006 and 2005 and the amounts recognized in the Company’s financial statements for both the defined benefit pension and SERP plans:
The portion of the net actuarial loss expected to be recognized as a component of pension cost in 2007 is $0.7 million.
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Notes to Consolidated Financial Statements - (Continued)
The components of net periodic pension cost and related assumptions are as follows:
These costs are included in the accompanying statement of operations in selling and administrative expenses.
The weighted-average asset allocation of the Company’s qualified pension trusts at December 31, 2006 and 2005 was as follows:
The Company’s investment goals are to maximize returns subject to specific risk management policies. The Company sets the expected return on plan assets based on historical trends and forecasts provided by its third-party fund managers. Its risk management policies permit investments in mutual funds, and prohibit direct investments in debt and equity securities and derivative financial instruments. The Company addresses diversification by the use of mutual fund investments whose underlying investments are in domestic and international fixed income securities and domestic and international equity securities. These mutual funds are readily marketable and can be sold to fund benefit payment obligations as they become payable.
The Company expects to contribute $4.2 million to its pension plans during 2007.
The pension benefits expected to be paid in each year from 2007 to 2011 are $1.1 million, $1.4 million, $1.8 million, $2.1 million, and $2.6 million, respectively. The aggregate pension benefits expected to be paid in the five years from 2012 to 2016 are $18.8 million. The benefits expected to be paid are based on the same
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Notes to Consolidated Financial Statements - (Continued)
assumptions used to measure the Company’s pension benefit obligation at December 31, 2006 and include estimated future employee service.
9.
HERITAGE HEALTH BENEFIT EXPENSES
The caption “Heritage health benefit expenses” used in the Consolidated Statements of Operations refers to costs of benefits the Company provides to our former Eastern mining operation employees as well as other administrative costs associated with providing those benefits. The components of these expenses are (in thousands):
10.
ASSET RETIREMENT OBLIGATIONS, RECLAMATION DEPOSITS AND CONTRACTUAL THIRD PARTY RECLAMATION RECEIVABLES
Asset Retirement Obligations
Changes in the Company’s asset retirement obligations during 2006 and 2005 were (in thousands):
As of December 31, 2006 the Company has reclamation bonds in place for its active mines in Montana, North Dakota and Texas and for inactive mining sites in Virginia which are now awaiting final bond release. These government-required bonds assure that coal mining operations comply with applicable federal and state regulations relating to the performance and completion of final reclamation activities. The Company estimates that the cost of final reclamation for its mines when they are closed in the future will total approximately $488.4 million, with a present value of $184.1 million. As permittee the Company is responsible for the total amount. The financial responsibility for a portion of final reclamation of the mines when they are closed has been shifted by contract to certain customers, while other customers have provided guarantees or funded escrow accounts to cover final reclamation costs. These are discussed below. Costs of final reclamation of mining pits prior to mine closure are recovered in the price of coal shipped.
Reclamation Deposits
Reclamation deposits of $62.5 million at December 31, 2006 consist of $17.3 million of cash and cash equivalents and $45.2 million of federal agency bonds (government backed securities). The Company has the intent and ability to hold these securities to maturity, and, therefore, accounts for them as held-to-maturity
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Notes to Consolidated Financial Statements - (Continued)
securities. Held-to-maturity securities are recorded at amortized cost, adjusted for the amortization or accretion of premiums or discounts calculated on the effective interest method. Interest income is recognized when earned.
The amortized cost, gross unrealized holding losses and fair value of held-to-maturity securities at December 31, 2006 are as follows (in thousands):
Maturities of held-to-maturity securities are as follows at December 31, 2006 (in thousands):
Contractual Third Party Reclamation Receivables
The Company has recognized as an asset $41.9 million as contractual third party reclamation receivables, representing the present value of obligations of certain customers and a contract miner to reimburse the Company for a portion of the asset retirement costs at the Company’s Rosebud, Jewett, and Absaloka mines.
At the Rosebud Mine, certain customers were contractually obligated under a coal supply agreement to pay the final reclamation costs for a specific area of the mine. They satisfied that obligation by pre-funding their respective portions of those costs. The funds are invested in cash equivalents and government-backed interest-bearing securities. As of December 31, 2006, the value of those funds, classified as reclamation deposits on the Consolidated Balance Sheets, was $62.5 million. One customer under the same coal supply agreement elected not to pre-fund its obligation but in 2003 began to fund a separate reclamation account over the remaining term of the coal contract to satisfy the contract provisions. The balance in the restricted account maintained by the customer was $5.0 million and the present value of that customer’s obligation was $3.8 million as of December 31, 2006, and was classified as contractual third party reclamation receivables in the Consolidated Balance Sheets.
At the Jewett Mine, the customer is contractually responsible for all post-production reclamation obligations. The present value of the customer’s obligation at mine closure was $26.5 million as of December 31, 2006, which is classified as contractual third party reclamation receivables on the Consolidated Balance Sheets. The former owners of the customer have provided a $50.0 million corporate guarantee to the Railroad Commission of Texas to assure performance of such final reclamation.
At the Absaloka Mine at December 31, 2006, the contract miner, Washington Group International (“WGI”), was obligated to perform the vast majority of all reclamation activities, including all final backfilling, regrading and seeding. WRI owns the Absaloka Mine, and Westmoreland owns 80% of WRI. WRI has a maximum financial responsibility for these activities of $2.6 million, which amount has been pre-funded. Once the contract miner has performed its final reclamation obligations, WRI will be responsible for site maintenance and monitoring until final bond release. To assure compliance, and as part of a settlement of several outstanding issues in 2002, the contract miner has established an escrow account into which 6.5% of every contract mining invoice payment is being deposited. The balance in the escrow account maintained by
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Notes to Consolidated Financial Statements - (Continued)
WGI as of December 31, 2006 was $6.5 million. The present value of the contract miner’s reclamation receivable was $11.6 million as of December 31, 2006, and is classified as contractual third party reclamation receivables in the accompanying consolidated balance sheet.
On March 6, 2007, the Company, WRI and WGI signed a comprehensive settlement agreement pursuant to which the mining contract between WRI and WGI will be terminated on March 30, 2007 and all claims among the parties were settled, including the dispute relating to the coal sales agency agreement and the litigation relating to WGI’s performance under the mining contract. As part of this settlement, WGI will release the funds in the escrow account to WRI in exchange for WRI’s assuming liability for the reclamation obligation.
The asset retirement obligation, contractual third party reclamation receivable, and reclamation deposits for each of the Company’s mines and ROVA are summarized below (in thousands):
11.
STOCKHOLDERS’ EQUITY
Preferred and Common Stock
The Company has two classes of capital stock outstanding, common stock, par value $2.50 per share, and Series A Convertible Exchangeable Preferred Stock, par value $1.00 per share (“Series A Preferred Stock”). Each share of Series A Preferred Stock is represented by four Depositary Shares. The full amount of the quarterly dividend on the Series A Preferred Stock is $2.125 per preferred share or $0.53 per Depositary Share. The Company paid quarterly dividends of $0.25 per Depositary Share from October 1, 2004 through July 1, 2006. The Company suspended the payment of preferred stock dividends following the recognition of the deficit in shareholders’ equity described below. The quarterly dividends which are accumulated through and including January 1, 2007 amount to $14.5 million in the aggregate ($90.53 per preferred share or $22.63 per Depositary Share).
The Company is currently reporting a deficit in shareholders’ equity. As a result, the Company is prohibited from paying preferred stock dividends because of the statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which the Company is incorporated. Under Delaware law, the Company is permitted to pay preferred stock dividends only to the extent that shareholders’ equity exceeds the par value of the preferred stock ($160,000 at December 31, 2006).
During 2006, the Company exchanged a total of 179,818 Depositary Shares at an exchange ratio of 1.8691 shares of Common Stock for each Depositary Share, compared to the conversion ratio of 1.708 provided for under the terms of Certificate of Designation governing the preferred stock. As a result of these preferred stock exchanges, $0.8 million of premium on the exchange of preferred stock for common stock was recorded in 2006 as an increase in net loss applicable to common shareholders. This premium on the exchange of preferred stock for common stock represents the excess of the fair value of consideration transferred to the preferred stock holders over the value of consideration that would have been exchanged under the original
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Notes to Consolidated Financial Statements - (Continued)
conversion terms. While the Company can redeem preferred shares at any time for the redemption value of $25 plus accumulated dividends paid in cash, the Company has agreed to the negotiated exchanges as a cash conservation measure and because the exchanges reduced the number of outstanding Depositary Shares, thereby eliminating $3.9 million of accumulated dividends and associated future dividend requirements.
Restricted Net Assets
At December 31, 2006, Westmoreland Coal Company had approximately $112.5 million of net assets at its subsidiaries that were not available to be transferred to it in the form of dividends, loans, or advances due to restrictions contained in the credit facilities of these subsidiaries. Approximately $46.7 million of net assets of the subsidiaries are unrestricted.
12.
INCENTIVE STOCK OPTIONS AND STOCK APPRECIATION RIGHTS
As of December 31, 2006, the Company had stock options and SARs outstanding from three stock incentive plans for employees and three stock incentive plans for directors.
The employee plans provide for the grant of incentive stock options (“ISOs”), non-qualified options under certain circumstances, SARs and restricted stock. ISOs and SARs generally vest over two or three years, expire ten years from the date of grant, and may not have an option or base price that is less than the market value of the stock on the date of grant. The maximum number of shares that could be issued or granted under the employee plans is 1,150,000, and as of December 31, 2006, a total of 210,472 shares are available for future grants.
The non-employee director plans generally provide for the grant of options for 20,000 shares when elected or appointed, and options for 10,000 shares after each annual meeting. Beginning in 2006, directors were granted SARs as a form of award. The maximum number of shares that could be issued or granted under the director plans is 900,000, and as of December 31, 2006, 19,176 shares were available for future grants.
On December 30, 2005, the Company accelerated the vesting of all unvested SARs, essentially all of which were in the money, which resulted in additional compensation expense of $0.5 million. The Company elected to accelerate the vesting of the SARs because doing so reduced the expense that the Company would be required to recognize in the future under SFAS No. 123(R).
The Company granted 161,500 SARs under an employee plan during 2006 which vest over a three year period. The Company also granted 16,067 SARs under a non-employee director plan in 2006 which vest over a four year period. The exercise price of each SAR granted was equal to the market value of a share of the Company’s common stock on the date of the grant. As of December 31, 2006, there was less than $0.1 million of intrinsic value for vested SARs and less than $0.1 million for all SARs outstanding. Upon vesting, the holders may exercise the SARs and receive an amount equal to the increase in the value of the common stock between the grant date and the exercise date in shares of common stock.
Compensation cost arising from share-based payment arrangements was $2.6 million, $2.3 million, and $2.2 million during 2006, 2005, and 2004, respectively, including $1.8 million, $1.4 million, and $1.4 million, respectively, for stock issued as matching contributions to the Company’s 401(k) Savings Plan. The intrinsic value of options and SARs exercised during 2006, 2005, and 2004 was $3.6 million, $3.1 million, and $1.7 million, respectively.
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Notes to Consolidated Financial Statements - (Continued)
Information with respect to both the employee and director SARs is as follows:
Information about SARs outstanding as of December 31, 2006 is as follows:
The weighted-average fair value of each SAR granted in 2006, 2005, and 2004 was $14.64, $10.13, and $11.41, respectively. There will be no future compensation expense arising from the SARs granted prior to 2006 because of the accelerated vesting discussed above. The amount of unamortized compensation expense for SARs outstanding at December 31, 2006 was $2.2 million which is expected to be recognized over approximately three years.
The fair value of SARs granted is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions for 2006 and 2005:
Information with respect to employee and director stock options is as follows:
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Notes to Consolidated Financial Statements - (Continued)
Information about stock options outstanding as of December 31, 2006 is as follows:
The amount of unamortized compensation expense for options outstanding at December 31, 2006 was less than $0.1 million.
Prior to January 1, 2006, the Company applied the intrinsic-value-based method of accounting prescribed by Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees”, and related interpretations, to account for its fixed-plan stock options. Under this method, compensation expense was recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”), established accounting and disclosure requirements using a fair-value-based method of accounting for stock-based employee compensation plans. As allowed under SFAS No. 123, the Company had elected to continue to apply the intrinsic-value-based method of accounting described above, and adopted only the disclosure requirements of SFAS No. 123, prior to the adoption of SFAS 123(R)effective January 1, 2006.
The following table illustrates the pro forma effect on net loss and net loss per share in 2005 and 2004 as if the compensation cost for the Company’s fixed-plan stock options had been determined based on fair value at their grant dates consistent with SFAS No. 123:
13.
TRANSACTIONS WITH AFFILIATED COMPANIES
WRI has a coal mining contract with WGI, its 20% stockholder. Mining costs incurred under the contract were $24.6 million, $22.7 million and $22.3 million in 2006, 2005 and 2004, respectively.
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14.
SALE OF MINERAL LEASES
In February 2006, a wholly-owned subsidiary of the Company sold its undivided interests in two coal bed methane leases in southern Colorado for net proceeds of $5.1 million and recognized a $5.1 million gain on the sale.
15.
DERIVATIVE INSTRUMENTS
During 2006, the Company entered into three derivative contracts to manage a portion of its exposure to the price volatility of diesel fuel used in its operations. In a typical commodity swap agreement, the Company receives the difference between a fixed price per gallon of diesel fuel and a price based on an agreed upon published, third-party index if the index price is greater than the fixed price. If the index price is lower, the Company pays the difference. By entering into swap agreements, the Company effectively fixes the price it will pay in the future for the quantity of diesel fuel subject to the swap agreement.
The first two contracts covered approximately 4 million gallons of diesel fuel, which represented an estimated two-thirds of the annual consumption at one of our mines, at a weighted average fixed price of $2.01 per gallon. These contracts settled monthly from February to December, 2006. During 2006, the Company realized a net loss of approximately $0.2 million on these derivative contracts.
In October 2006, the Company entered into a derivative contract to manage a portion of its exposure to the price volatility of diesel fuel to be used in its operations in 2007. The contract covers 2.4 million gallons of diesel fuel at a weighted average fixed price of $2.02 per gallon. This contract settles monthly from January to December, 2007. The Company accounts for this derivative instrument on a mark-to-market basis through earnings. The Consolidated Financial Statements as of December 31, 2006 reflect an unrealized loss on this contract of $0.3 million, which is recorded in accounts payable and as cost of sales - coal.
In January 2007, the Company entered into an additional derivative contract to manage a portion of its exposure to the price volatility of diesel fuel to be used in its operations in 2007. The contract covers 1.1 million gallons of diesel fuel at a weighted average fixed price of $1.75 per gallon. This contract settles monthly from February to December, 2007.
Information regarding derivative instruments for the year ended December 31, 2006 is as follows:
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Notes to Consolidated Financial Statements - (Continued)
16.
INCOME TAXES
Income tax expense attributable to net loss before income taxes consists of:
The Company accrued $2.1 million in 2005 and an additional $2.1 million in 2006 for a North Carolina state income tax assessment.
Income tax expense attributable to net loss before income taxes differed from the amounts computed by applying the statutory Federal income tax rate of 34% to pre-tax income as a result of the following:
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Notes to Consolidated Financial Statements - (Continued)
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2006 and 2005 are presented below:
The Company believes it 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 its mining operations. As a result, the Company has determined that a valuation allowance is required for all of its regular federal net operating loss carryforwards, since they are not available to reduce AMT income in the future. The Company has also determined that a full valuation allowance is required for all its AMT credit carryforwards, since they are only available to offset future regular income taxes payable. In addition, the Company has determined that since its net deductible temporary differences will not reverse for the foreseeable future, and the Company is unable to forecast that it will have taxable income when they do reverse, a full valuation allowance is required for these deferred tax assets. The Company has also therefore recorded a full valuation allowance for its state net operating losses, since it believes that it is not more likely than not that they will be realized.
During the year ended December 31, 2006, the Company recorded an increase to its valuation allowance of approximately $40.9 million relating to the increase in the liabilities for pension and other postretirement benefits recorded as an adjustment to accumulated other comprehensive loss upon adoption of SFAS 158, an increase in the valuation allowance of approximately $6.6 million for the effect of the adoption of EITF 04-06 which was changed directly to accumulated deficit, an increase in the valuation allowance for the effect of the
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adoption of SAB 108 of $1.8 million which was charged directly to accumulated deficit and an increase in the valuation allowance for the tax effect of excess stock option deductions of $1.2 million included in the Company’s net operating loss carryforward.
As of December 31, 2006, the Company has available Federal net operating loss carryforwards to reduce future regular taxable income which expire as follows:
The Company has AMT credit carryforwards of $6.2 million which are available indefinitely to offset future regular Federal taxes payable. The Company also has $6.1 million of Indian coal production tax credits which are available indefinitely to offset future regular Federal taxes payable as well as future AMT.
17.
COMMITMENTS
Lease Obligations
The Company leases certain of its coal reserves from third parties and pays royalties based on either a per ton rate or as a percentage of revenues received. Royalties charged to expense under all such lease agreements amounted to $35.5 million, $27.4 million and $27.2 million in 2006, 2005 and 2004, respectively.
The Company has operating lease commitments expiring at various dates, primarily for real property and equipment. Rental expense under operating leases during 2006, 2005 and 2004 totaled $6.3 million, $4.3 million and $3.4 million, respectively. Minimum future rental obligations existing under leases with remaining terms of one year or more at December 31, 2006 are as follows (in thousands):
Coal Supply Agreements
Westmoreland Partners, which owns ROVA, has two coal supply agreements with TECO Coal Corporation (“TECO”). If Westmoreland Partners continues to purchase coal under these contracts at the current volume and pricing and does not extend these coal supply agreements, then Westmoreland Partners would be obligated to pay TECO $26.5 million in each of 2007, 2008, 2009, 2010, 2011 and an aggregate of $84.7 million after 2011.
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Long-Term Sales Commitments
The following table presents estimated total sales tonnage under existing long-term contracts for the next five years from the Company’s existing mining operations. The prices for all future tonnage are subject to revision and adjustments based upon market prices, certain indices and/or cost recovery.
The tonnages in the table above represent estimated sales tonnage under existing, executed contracts and generally exclude pending or anticipated contract renewals or new contracts. These projections reflect customers’ scheduled major plant outages, if known. The figures above exclude the new agreement with Colstrip Units 1&2 entered into during March 2007 and effective January 1, 2010 for an estimated 3 million tons per year.
18.
CONTINGENCIES
Royalty Claims
The Company acquired Western Energy Company (“WECO”) from Montana Power Company in 2001. WECO produces coal from the Rosebud Mine, which includes federal leases, a state lease and some privately owned leases near Colstrip, Montana. The Rosebud Mine supplies coal to the four units of the adjacent Colstrip Power Plant. In the late 1970’s, a consortium of six utilities, including Montana Power, entered into negotiations with WECO for the long-term supply of coal to Units 3&4 of the Colstrip Power Plant, which would not be operational until 1984 and 1985, respectively. The parties could not reach agreement on all the relevant terms of the coal price and arbitration was commenced. The arbitration panel issued its opinion in 1980. As a result of the arbitration order, WECO and the Colstrip owners entered into a Coal Supply Agreement and a separate Coal Transportation Agreement. Under the Coal Supply Agreement, the Colstrip Units 3&4 owners pay a price for the coal F.O.B. mine. Under the Coal Transportation Agreement, the Colstrip Units 3&4 owners pay a separate fee for the transportation of the coal from the mine to Colstrip Units 3&4 on a conveyor belt that was designed and constructed by WECO and has been continuously operated and maintained by WECO.
In 2002 and 2006, the State of Montana, as agent for the Minerals Management Service (“MMS”) of the U.S. Department of the Interior, conducted audits of the royalty payments made by WECO on the production of coal from the federal leases. The audits covered three periods: October 1991 through December 1995, January 1996 through December 2001, and January 2002 through December 2004. Based on these audits, the Office of Minerals Revenue Management (“MRM”) of the Department of the Interior issued orders directing WECO to pay royalties in the amount of $8.6 million on the proceeds received from the Colstrip owners under the Coal Transportation Agreement during the three audit periods. The orders held that the payments for transportation were payments for the production of coal. The Company believes that only the costs paid for coal production are subject to the federal royalty, not payments for transportation.
WECO appealed the orders of the MRM to the Director of the MMS. On March 28, 2005, the MMS issued a decision stating that payments to WECO for transportation across the conveyor belt were part of the
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Notes to Consolidated Financial Statements - (Continued)
purchase price of the coal and therefore subject to the royalty charged by the federal government under the federal leases. However, the MMS dismissed the royalty claims for periods more than seven years before the date of the order on the basis that the statute of limitations had expired, which reduced the total demand from $8.6 million to $5.0 million.
On June 17, 2005, WECO appealed the decision of the MMS on the transportation charges to the United States Department of the Interior, Office of Hearings and Appeals, Interior Board of Land Appeals (“IBLA”). On September 6, 2005, the MMS filed its answer to WECO’s appeal. This matter is still pending before the IBLA.
The total amount of the MMS royalty claims including interest through the end of 2003 was approximately $5.0 million. This amount, if payable, is subject to interest through the date of payment, and as discussed above, the audit only covered the period through 2001.
By decision dated September 26, 2006, the MMS issued a demand to WECO assessing a royalty underpayment charge of $1.6 million, which the MMS asserts is attributable to coal production from Federal Coal Lease No. M18-080697-0. This assessment is based on the same MMS analysis as the assessments previously asserted by the MMS pursuant to its decisions dated September 23, 2002 but applies to a later period. The amount of the potential liability is $1.6 million, plus interest.
In 2003, the State of Montana Department of Revenue (“DOR”) assessed state taxes for years 1997 and 1998 on the transportation charges collected by WECO from the Colstrip Units 3&4 owners. The taxes are payable only if the transportation charges are considered payments for the production of coal. The DOR is relying upon the same arguments used by the MMS in its royalty claims. WECO has disputed the state tax claims.
In 2006, DOR issued additional assessments for certain of these taxes for years 1998-2001. WECO appealed and DOR elected to proceed to hearing on these objections using its internal administrative hearing process. This is the first stage of the eventual adjudication which could ultimately conclude with the Montana Supreme Court. It is likely that the IBLA will rule on the MMS issue before this DOR process reaches the Montana state court system, and it is likely that the federal court will have ruled on any appeal from the IBLA before the DOR issue reaches the Montana Supreme Court. The total of the state tax claims through the end of 2001, including interest through the end of 2006, was approximately $20.4 million. If this amount is payable it is subject to interest from the time the tax payment was due until it is paid.
The MMS has asserted two other royalty claims against WECO. In 2002, the MMS held that “take or pay” payments received by WECO during the period from October 1, 1991 to December 31, 1995 from two Colstrip Units 3&4 owners were subject to the federal royalty. The MMS is claiming that these “take or pay” payments are payments for the production of coal, notwithstanding that no coal was produced. WECO filed a notice of appeal with MMS on October 22, 2002, disputing this royalty demand. No ruling has yet been issued by MMS. The total amount of the royalty demand, including interest through August 2003, is approximately $2.7 million.
In 2004, the MMS issued a demand for a royalty payment in connection with a settlement agreement dated February 21, 1997 between WECO and one of the Colstrip owners, Puget Sound Energy. This settlement agreement reduced the coal price payable by Puget Sound as a result of certain “inequities” caused by the fact that the mine owner at the time, Montana Power, was also one of the Colstrip customers. The MMS has claimed that the coal price reduction is subject to the federal royalty. WECO has appealed this demand to the MMS, which has not yet ruled on the appeal. The amount of the royalty demand, with interest through mid-2003, is approximately $1.3 million.
Finally, in May 2005 the State of Montana asserted a demand for unpaid royalties on the state lease for the period from January 1, 1996 through December 31, 2001. This demand, which was for $0.8 million, is
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Notes to Consolidated Financial Statements - (Continued)
based on the same arguments as those used by the MMS in its claim for payment of royalties on transportation charges and the 1997 retroactive “inequities” adjustment of the coal price payable by Puget Sound.
Neither the MMS nor the DOR has made royalty or tax demands for all periods during which WECO has received payments for transportation of coal. Presumably, the royalty and tax demands for periods after the years in dispute-generally, 1997 to 2004-and future years will be determined by the outcome of the pending proceedings. However, if the MMS and DOR were to make demands for all periods through the present, including interest, the total amount claimed against WECO, including the pending claims and interest thereon through December 31, 2006, could exceed $33.0 million.
The Company believes that WECO has meritorious defenses against the royalty and tax demands made by the MMS and the DOR. The Company expects a favorable ruling from the IBLA, although it could be a year or more before the IBLA issues its decision. If the outcome is not favorable to WECO, the Company plans to seek relief in Federal district court.
Moreover, in the event of a final adverse outcome with DOR and MMS, the Company believes that certain of the Company’s customers are contractually obligated to reimburse the Company for any royalties and taxes imposed on the Company for the production of coal sold to the Colstrip owners, plus the Company’s legal expenses. Consequently, the Company has not recorded any provisions for these matters. Legal expenses associated with these matters are expensed as incurred. WECO expects to recover these expenses from the Colstrip Units 3&4 owners upon the final determination of these claims.
Rensselaer Tax Assessment
Niagara Mohawk Power Corporation (“NIMO”) was party to power purchase agreements with independent power producers, including the Rensselaer project, in which the Company owned an interest. In 1997, the New York Public Service Commission approved NIMO’s plan to terminate or restructure 29 power purchase contracts. The Rensselaer project agreed to terminate its Power Purchase and Supply Agreement after NIMO threatened to seize the project under its power of eminent domain. NIMO and the Rensselaer project executed a settlement agreement in 1998 with a payment to the project. On February 11, 2003, the North Carolina Department of Revenue notified the Company that it had disallowed the exclusion of gain as non-business income from the settlement agreement between NIMO and the Rensselaer project. The State of North Carolina assessed a current tax of $3.5 million, interest of $1.3 million (through 2004), and a penalty of $0.9 million. The Company consequently filed a protest. The North Carolina Department of Revenue held a hearing on May 28, 2003. In November 2003, the Company submitted further documentation to the State to support its position. On January 14, 2005, the North Carolina Department of Revenue concluded that the additional assessment is statutorily correct. On July 27, 2005, the Company responded to the North Carolina Department of Revenue providing additional information.
As a result of discussions between counsel for the Company and counsel for the Department of Revenue in February 2007, the department indicated that it will revise its assessment to $4.2 million, inclusive of interest but without a penalty. The Company has an accrued reserve of $4.2 million at December 31, 2006, which is the minimum amount the Company believes it will be required to pay.
Combined Benefit Fund
Under the Coal Act, the Company is required to provide postretirement medical benefits for certain UMWA miners and their dependents by making payments into certain benefit plans, one of which is the Combined Benefit Fund (“CBF”).
The Coal Act merged the UMWA 1950 and 1974 Benefit Plans into the CBF, and beneficiaries of the CBF were assigned to coal companies across the country. Congress authorized the Department of Health & Human Services (“HHS”) to calculate the amount of the premium to be paid by each coal company to whom
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Notes to Consolidated Financial Statements - (Continued)
beneficiaries were assigned. Under the statute, the premium was to be based on the aggregate amount of health care payments made by the 1950 and 1974 Plans in the plan year beginning July 1, 1991, less reimbursements from the Federal Government, divided by the number of individuals covered. That amount is increased each year by a cost of living factor.
Prior to the creation of the CBF, the UMWA 1950 and 1974 Plans had an arrangement with HHS pursuant to which they would pay the health care costs of retirees entitled to Medicare, and would then seek reimbursement for the Medicare-covered portion of the costs from HHS. The parties had lengthy disputes over the years concerning the amount to be reimbursed, which led them to enter into a capitation agreement in which they agreed that HHS would pay the Plans a specified per-capita reimbursement amount for each beneficiary each year, rather than trying to ascertain each year the actual amount to be reimbursed. The capitation agreement was in effect for the plan year beginning July 1, 1991, the year specified by the Coal Act as the baseline for the calculation of Coal Act premiums.
In assessing the annual premium of the coal operators under the CBF, the Trustees of the CBF used an interpretation by HHS that “reimbursements” in the base-line year were the amounts that would have been payable by the government if the actual Medicare regulations were applied, not the amounts actually received by the CBF under the capitation agreement. This method of calculating the CBF premium resulted in a higher amount than would have been the case if the government payments under the capitation agreement had been applied. The coal operators disagreed with the HHS interpretation and initiated litigation in the mid - 1990’s.
In 1995, the Court of Appeals for the Eleventh Circuit ruled, in a victory for the coal companies, that the meaning of the statute was clear, i.e., that “reimbursements” meant the actual amount by which the CBF was reimbursed, regardless of the amount of the Medicare-covered expenditures under government regulations. In 2002, the Court of Appeals for the District of Columbia Circuit ruled that the statute was ambiguous, and remanded the case to the Commissioner of Social Security, as successor to HHS, for an explanation of its interpretation so that the court could evaluate whether the interpretation was reasonable. The Commissioner of Social Security affirmed the previous interpretation and the coal companies then brought another legal challenge. On August 12, 2005, the United States District Court for the District of Maryland agreed with the Eleventh Circuit that the term “reimbursements” unambiguously means the actual amount by which the CBF was reimbursed, and the Court granted summary judgment to the coal operators. However, the judge ruled that until all appeals have been exhausted and the case is final, the CBF can retain the premium overpayments, although the judge applied the new premium calculation prospectively.
On December 21, 2006, the United States Court of Appeals for the Fourth Circuit ruled in favor of the coal operators and affirmed the decision of the Maryland District Court that “reimbursements” in the Coal Act premium calculation refers to actual reimbursements received by the CBF.
The difference in premium payments for Westmoreland is substantial. Pursuant to the holdings of the Eleventh Circuit and the Federal District Court of Maryland, Westmoreland has overpaid and expensed premiums by more than $5.8 million for the period from 1993 through 2006.
In March 2007, the Trustees of the CBF and the coal companies reached agreement that during 2007 the CBF would refund the overpayments together with interest to the coal companies. Accordingly during 2007, the Company expects to receive the $5.8 million plus interest, as full and final settlement of this litigation.
The Company paid premiums to the CBF of approximately $332,000 for each of the first nine months of 2006, compared to $396,000 per month prior to the Maryland District Court decision. The premiums were reduced to approximately $306,000 per month beginning in October, 2006.
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Notes to Consolidated Financial Statements - (Continued)
1992 UMWA Benefit Plan Surety Bond
On May 11, 2005, XL Specialty Insurance Company and XL Reinsurance America, Inc. (together, “XL”), filed in the U.S. District Court, Southern District of New York, a Complaint for Declaratory Judgment against Westmoreland Coal Company and named Westmoreland Mining LLC as a co-defendant. The Complaint asked the court to confirm XL’s right to cancel a $21.3 million bond that secures Westmoreland’s obligation to pay premiums to the UMWA 1992 Plan, and also asked the court to direct Westmoreland to pay $21.3 million to XL to reimburse XL for the $21.3 million that would be drawn under the bond by the 1992 Plan Trustees upon cancellation of the bond.
At a hearing held on January 31, 2006, the judge advised the parties that the United States District Court for New Jersey would be a more appropriate venue. On March 1, 2006, the plaintiffs filed their complaint in the New Jersey District Court. On April 12, 2006, the defendants filed a motion to dismiss for lack of jurisdiction because there is no diversity of citizenship. The motion was granted on March 21, 2007 and the case was dismissed. The plaintiffs have the option of bringing the litigation in state court.
On February 7, 2007, Westmoreland Coal Company voluntarily reduced the amount of the XL bond, with the consent of XL, from approximately $21.3 million to $9.0 million. This reduction was permitted by amendments to the Coal Act that were signed into law on December 20, 2006.
The Company believes that it has no obligation to reimburse XL for draws under the bond unless the draw is the result of a default by the Company under its obligations to the UMWA 1992 Plan. No default has occurred. If XL prevails on its claim, the Company will be required to provide cash collateral of $9.0 million for its obligations to the 1992 Plan or, alternatively, provide a letter of credit.
Derivative Action Brought by Washington Group International, Inc. in Connection With Sales Agency Agreement
On February 17, 2006, the Company was served with a complaint filed by Washington Group International, Inc. (“WGI”) in Colorado District Court, City and County of Denver. The defendants in this legal action were Westmoreland Coal Company, Westmoreland Coal Sales Company (“WCSC”), WRI, and certain directors and officers of WRI. WGI owns a 20% interest in WRI and the Company owns the remaining 80%. This litigation related to a coal sales agency agreement between WRI and WCSC, a wholly owned subsidiary of the Company, which was entered into in January of 2002. Under this coal sales agency agreement, WCSC agreed to act as agent for WRI in marketing and selling WRI’s produced coal in exchange for an agency fee per ton sold. WGI objected to this fee and claimed in its complaint that the directors of WRI and its President breached their fiduciary duty by granting an over-market agency fee to an affiliated company. WGI’s share of the amount in dispute, if the fee was to be rescinded retroactively to 2002 and the fee then in effect applied, is approximately $0.6 million. The Company believes that the sales agency fee reflects a fair rate for marketing and selling coal since 2002 and further believes that WCSC provides service to WRI for which it should be compensated at a fair rate. The Company has not reserved any amount in the financial statements for this claim.
On March 6, 2007, the Company, WRI and WGI signed a comprehensive settlement agreement pursuant to which the mining contract between WRI and WGI will terminate on March 30, 2007 and all claims among the parties were settled, including the dispute relating to the coal sales agency agreement and the litigation relating to WGI’s performance under the mining contract.
McGreevey Litigation
In late 2002, the Company was served with a complaint in a case styled McGreevey et al. v. Montana Power Company et al. in a Montana State court. The plaintiffs are former stockholders of Montana Power who filed their first complaint on August 16, 2001. This was the Plaintiffs’ Fourth Amended Complaint; it added
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Westmoreland as a defendant to a suit against Montana Power Company, various officers of Montana Power Company, the Board of Directors of Montana Power Company, financial advisors and lawyers representing Montana Power Company and the purchasers of some of the businesses formerly owned by Montana Power Company and Entech, Inc., a subsidiary of Montana Power Company. The plaintiffs seek to rescind the sale by Montana Power of its generating, oil and gas, and transmission businesses, and the sale by Entech of its coal business, or to compel the purchasers to hold these businesses in trust for the shareholders. The Plaintiffs contend that they were entitled to vote to approve the sale by Entech to the Company even though they were not shareholders of Entech. Westmoreland has filed an answer, various affirmative defenses and a counterclaim against the plaintiffs. Shortly after the Company was named as a defendant, the litigation was transferred from Montana State Court to the U.S. District Court in Billings, Montana.
There has been no significant activity in the case involving Westmoreland for the past four years. Settlement discussions between the plaintiffs and other defendants appear to have been unsuccessful. We have never participated in settlement discussions with the plaintiffs because we believe that the case against the Company is totally without merit. Even if the plaintiffs could establish that shareholder consent was required for the sale of Montana Power’s coal business in 2001, there is virtually no legal support for the argument that such a sale to a buyer acting in good faith, purchasing from a wholly owned subsidiary, and relying on the seller’s representations can be rescinded. Indeed, the practical issues relating to such rescission would present a significant obstacle to such a result, particularly when the business has been operated by the buyer for six years, significant amounts of capital have been invested, reserves have been depleted, and the original seller is in bankruptcy and has no means to complete a repurchase or operate the business following a repurchase.
The Company has considered seeking a dismissal of the claims against it but is waiting for the outcome of a matter under review in the bankruptcy proceedings in Delaware involving Touch America (formerly Montana Power Company). In those proceedings, the unsecured creditors have asserted that the claims originally filed by McGreevey in Montana - the claims against the officers and directors which, if successful, would likely result in a payment by the insurance carrier that provided D&O insurance to Montana Power Company - belong to the creditors, not the shareholders who are the plaintiffs in the McGreevey action. If the Delaware Bankruptcy Court holds that those claims are “derivative” and thus belong to the corporation, then the unsecured creditors may have a right to those claims. Although the Delaware Bankruptcy Court will not directly decide that issue with respect to the claims against the various asset purchasers, including the Company, such a decision would likely affect the analysis of the Montana District Court where our case is pending.
No reserve has been accrued by the Company in this matter.
19.
BUSINESS SEGMENT INFORMATION
Segment information is presented in accordance with SFAS 131, “Disclosures about Segments of an Enterprise and Related Information”. This standard is based on a management approach, which requires segmentation based upon our internal organization and reporting of revenue and operating income based upon internal accounting methods.
During 2006, the Company revised its segments. The changes were designed to provide better performance information between the Company’s existing operations and its former Eastern U.S. coal mining operations. The Company’s operations are now classified into four segments: coal, independent power, heritage and corporate. The coal segment includes the production and sale of coal from Montana, North Dakota and Texas. The independent power operations include the ownership of interests in cogeneration and other non-regulated independent power plants and business development expenses. The heritage segment includes costs of benefits the Company provides to former employees of its previously owned Eastern U.S. coal mining operations which have been disposed of. The corporate segment represents all costs not otherwise classified, including corporate office expenses. Assets attributed to the heritage segment consist primarily of cash, bonds
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
and deposits restricted to pay heritage health benefits. Prior year segment information has been reclassified to conform to the new segment presentation.
Summarized financial information by segment for 2006, 2005 and 2004 is as follows:
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The Company derives its coal revenues from a few key customers. The customers from which more than 10% of total revenue has been derived and the percentage of total revenue from those customers is summarized as follows:
The Company derives its energy revenues primarily from one key customer. The total revenue derived from that customer was $54.7 million, or 12.2% of the Company’s total revenues.
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
20.
QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 2006 and 2005 is as follows:
Westmoreland Coal Company and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
21.
SUBSEQUENT EVENT
Sale of Coal Royalties Rights at Wyoming Mine
On February 27, 2007, the Company sold its rights to a fixed royalty stream related to the future mining of 225 million of tons of coal at Peabody Energy Corporation’s Caballo Mine in Wyoming to Natural Resource Partners L.P. for $12.7 million. The sale of the coal royalty will result in a gain of approximately $5.6 million during the first quarter of 2007.
Agreement to Terminate WGI’s Mining Contract at WRI
On March 6, 2007, the Company, WRI and WGI executed a comprehensive agreement. Pursuant to that agreement, effective March 30, 2007, WRI terminated the WGI mining contract and assumed direct responsibility for mining operations at the Absaloka Mine, and assumed all liability for reclaiming the mine. In addition, WGI transferred $7.0 million in a reclamation escrow account to WRI, WRI purchased certain equipment from WGI, WRI paid WGI $4.2 million, and the parties terminated all the litigation between them.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Westmoreland Coal Company:
We have audited the accompanying consolidated balance sheets of Westmoreland Coal Company and subsidiaries as of December 31, 2006 and 2005, 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, 2006. 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, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, 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 discussed in note 1 to the consolidated financial statements, the Company has suffered recurring losses from operations, has a working capital deficit, and a net capital deficiency that 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. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
As discussed in notes to the consolidated financial statements, the Company changed its method for accounting and reporting for share based payments effective January 1, 2006, its method of accounting for deferred overburden removal costs effective January 1, 2006, its method of accounting for pension and other postretirement benefits effective December 31, 2006, and its method of quantifying misstatements effective January 1, 2006. Also, as discussed in note 3 to the consolidated financial statements, the Company changed its method of accounting for workers compensation benefits effective January 1, 2005.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of the Sponsoring Organizations of the Treadway Commission (COSO) expressed an unqualified opinion on management’s assessment of, and an adverse opinion on the effective operation of, internal control over financial reporting.
KPMG LLP
Denver, Colorado
March 30, 2007
ITEM 9
ITEM 9 -
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
This item is not applicable.
ITEM 9A
ITEM 9A -
CONTROLS AND PROCEDURES
(a)
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Internal control over financial reporting refers to a process designed by, or under the supervision of, the Chief Executive Officer and Chief Financial Officer and effected by the board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:
•
pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;
•
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and our board of directors; and
•
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
Management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2006 using the framework set forth in the report of the Treadway Commission’s Committee of Sponsoring Organizations (COSO), Internal Control - Integrated Framework. The Public Company Accounting Oversight Board’s Auditing Standard No. 2 defines a material weakness as a significant deficiency, or combination of significant deficiencies, that result in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. In conducting the aforementioned evaluation, we determined that a deficiency in our internal control over financial reporting at December 31, 2005, which we had determined was a material weakness in our internal controls at December 31, 2005, also existed and was a material weakness in our internal control over financial reporting at December 31, 2006. That material weakness related to our controls over accounting for capitalized asset retirement costs and asset retirement obligations.
Management’s procedures over accounting for the estimated cost of future reclamation of the Company’s mines were not designed effectively. Specifically, the Company did not maintain adequate controls to review the assumptions used and the data input into the electronic spreadsheets used to calculate the Company’s capitalized asset retirement costs and asset retirement obligations resulting in more than a remote likelihood that a material misstatement of the Company’s annual or interim financial statements would not be prevented or detected. This material weakness in internal control over financial reporting resulted in an overstatement of capitalized asset retirement costs and asset retirement obligations. The Company corrected these errors in accounting prior to the issuance of the Company’s 2006 consolidated financial statements.
As a result of this material weakness in internal control over financial reporting, management concluded that the Company’s internal control over financial reporting was not effective as of December 31, 2006.
Management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been audited by KPMG LLP, independent registered public accounting firm, as stated in their report which appears herein.
(b)
Changes in Internal Control over Financial Reporting
Management has evaluated, with the participation of the Chief Executive Officer and Chief Financial Officer, whether any changes in our internal control over financial reporting that occurred during our last fiscal quarter have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on the evaluation we conducted, management has concluded that no such changes have occurred.
(c)
Remediation Efforts in Response to Material Weakness
To remediate the material weakness described above and enhance our internal controls over financial reporting, the following improvements to our internal controls have been or will be implemented during 2007:
•
The calculations for asset retirement obligations will be standardized at all of our mines and will be simplified.
•
An additional layer of financial supervision and review has been added at each of our mines.
•
Personnel in our Corporate office will perform a detailed review of all asset retirement obligation calculations.
•
Additional training will be provided to those responsible for performing and reviewing asset retirement obligation calculations.
(d)
Evaluation of Disclosure Controls and Procedures
Management is required by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 to evaluate, with the participation of the Chief Executive Officer and Chief Financial Officer, the effectiveness of disclosure controls and procedures as of the end of the period covered by this report. Disclosure controls and procedures refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management was required to apply its judgment in evaluating and implementing possible controls and procedures.
Our evaluation of our internal controls over financial reporting indicated that a deficiency in our internal controls, which we had determined to be a material weakness in internal control over financial reporting at December 31, 2005, also existed at December 31, 2006. This material weakness in internal control related to our accounting for capitalized asset retirement costs and asset retirement obligations. As a result of this material weakness, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2006, our disclosure controls and procedures were not effective.
(e)
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Westmoreland Coal Company:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting in Item 9A(a), that Westmoreland Coal Company and subsidiaries (the Company) did not maintain effective internal control over financial reporting as of December 31, 2006, because of the effect of material weakness identified in management’s assessment, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Westmoreland Coal Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in management’s assessment as of December 31, 2006.
Management’s procedures over accounting for the estimated cost of future reclamation of the Company’s mines were not designed effectively. Specifically, the Company did not maintain adequate controls to review the assumptions used and the data input into the electronic spreadsheets used to calculate the Company’s capitalized asset retirement costs and asset retirement obligations resulting in more than a remote likelihood that a material misstatement of the Company’s annual or interim financial statements would not be prevented or detected. This material weakness in internal control resulted in errors in accounting for capitalized asset retirement costs and asset retirement obligations.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Westmoreland Coal Company and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, shareholders’ equity and
comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2006. The aforementioned material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the December 31, 2006 consolidated financial statements, and this report does not affect our report dated March 30, 2007, which expressed an unqualified opinion on those financial statements.
In our opinion, management’s assessment that the Company did not maintain effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
KPMG LLP
Denver, Colorado
March 30, 2007
ITEM 9B
ITEM 9B -
OTHER INFORMATION
None
PART III
ITEM 10
ITEM 10 -
DIRECTORS, OFFICERS AND CORPORATE GOVERNANCE
The information required by this item with respect to directors is hereby incorporated by reference to the material appearing in the Company’s definitive proxy statement to be filed pursuant to Regulation 14A in connection with the annual meeting of stockholders to be held in 2007 (the “Proxy Statement”) under the caption “Election of Directors”.
The information required by this item with respect to executive officers is provided above, following Item 4, under the caption “Executive Officers of the Company.”
Information required by this item with respect to the nominating process, the audit committee and the audit committee financial expert is hereby incorporated by reference to the material appearing in the Proxy Statement under the caption “Corporate Governance.”
We have adopted a code of ethics that applies to our directors, officers and employees (including our principal executive officer, principal financial officer and principal accounting officer). This code is available on our website, www.westmoreland.com, under “Corporate Governance.” The information contained on the Company’s website is not a part of, or incorporated by reference into, this Annual Report on Form 10-K. Any amendments to or waivers of the code of ethics granted to the Company’s executive officers or the controller will be published promptly on our website or by other appropriate means in accordance with SEC rules.
Information required by this item with respect to the compliance with Section 16(a) is hereby incorporated by reference to the material appearing in the Proxy Statement under the caption “Section 16(a) Beneficial Ownership Reporting Compliance.”
ITEM 11
ITEM 11 -
EXECUTIVE COMPENSATION
The information required by this item is hereby incorporated by reference to the material appearing in the Proxy Statement under the captions “Compensation Discussion and Analysis,” “Executive Compensation,” “Director Compensation,” “Compensation and Benefits Committee Report,” and “Corporate Governance - Compensation and Benefits Committee Interlocks and Insider Participation.”
ITEM 12
ITEM 12 -
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item with respect to security ownership of certain beneficial owners and management and the Company’s equity compensation plans is hereby incorporated by reference to the material appearing in the Proxy Statement under the caption “Beneficial Ownership of Securities” and “Equity Compensation Plan Information.”
ITEM 13
ITEM 13 -
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item is hereby incorporated by reference to the material appearing in the Proxy Statement under the captions “Corporate Governance” and “Certain Transactions.”
ITEM 14
ITEM 14 -
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is hereby incorporated by reference to the material appearing in the Proxy Statement under the caption “Auditors.”
PART IV
ITEM 15
ITEM 15 -
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
1. The financial statements filed herewith are: the Consolidated Balance Sheets of the Company and subsidiaries as of December 31, 2006 and December 31, 2005, and the related Consolidated Statements of Operations, Shareholders’ Equity and Cash Flows for each of the years in the three-year period ended December 31, 2006 together with the Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements, and the report of the independent registered public accounting firm thereon which are contained in Item 8.
2. The following financial statement schedules are filed herewith:
Report of Independent Registered Public Accounting Firm
Schedule I - Condensed Financial Statements of Parent Company
Schedule II - Valuation Accounts
The following financial statements of subsidiaries not consolidated and 50 percent or less owned persons are filed herewith:
Financial statements of Westmoreland-LG&E Partners as of December 31, 2005 and 2004 and for each of the years in the two-year period ended December 31, 2005 and the six months ended June 30, 2006, with the Independent Auditors Reports thereon.
3. The exhibits listed in the Exhibit Index immediately preceding such exhibits are filed with or incorporated by reference in this report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WESTMORELAND COAL COMPANY
By:
/s/ David J. Blair
David J. Blair
Chief Financial Officer
(A Duly Authorized Officer)
Date: March 30, 2007
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Westmoreland Coal Company:
Under date of March 30, 2007, we reported on the consolidated balance sheets of Westmoreland Coal Company and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, shareholders’ equity (deficit) and comprehensive loss, and cash flows for each of the years in the three-year period ended December 31, 2006, which are included in the December 31, 2006 Annual Report on Form 10-K of Westmoreland Coal Company and subsidiaries. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related consolidated financial statement schedules I and II. These financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statement schedules based on our audits.
In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
The audit report on the consolidated financial statements of Westmoreland Coal Company and subsidiaries referred to above contains an explanatory paragraph that states that the Company has suffered recurring losses from operations, has a working capital deficit, and a net capital deficiency that 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. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
As discussed in notes to the consolidated financial statements, the Company changed its method for accounting and reporting for share-based payments effective January 1, 2006, its method of accounting for deferred overburden removal costs effective January 1, 2006, its method of accounting for pension and other postretirement benefits effective December 31, 2006, and its method of quantifying misstatements effective January 1, 2006. Also, as discussed in note 3 to the consolidated financial statements, the Company changed its method of accounting for workers compensation benefits effective January 1, 2005.
KPMG LLP
Denver, Colorado
March 30, 2007
WESTMORELAND COAL COMPANY
SCHEDULE I - CONDENSED BALANCE SHEET
(Parent Company Information - See Notes to Consolidated Financial Statements)
WESTMORELAND COAL COMPANY
SCHEDULE I - CONDENSED STATEMENT OF OPERATIONS
(Parent Company Information - See Notes to Consolidated Financial Statements)
WESTMORELAND COAL COMPANY
SCHEDULE I - CONDENSED STATEMENT OF CASH FLOWS
(Parent Company Information - See Notes to Consolidated Financial Statements)
WESTMORELAND COAL COMPANY AND SUBSIDIARIES
Valuation Accounts
Years ended December 31, 2006, 2005 and 2004
Amounts above include current and non-current valuation accounts.
(A)
Uncollectible note charged to allowance
(B)
Consists of reserves related to the uncollectibility of notes receivable reported as a reduction of other assets in the Company’s Consolidated Balance Sheets.
Westmoreland - LG&E Partners
Financial Statements & Supplementary Data
WESTMORELAND-LG&E PARTNERS
Balance Sheets
As of December 31, 2005 and 2004
See accompanying notes to financial statements.
WESTMORELAND-LG&E PARTNERS
Statements of Operations and Comprehensive Income
For the six months ended June 30, 2006 and the years ended December 31, 2005 and 2004
See accompanying notes to financial statements.
WESTMORELAND-LG&E PARTNERS
Statements of Partners’ Capital
For the six months ended June 30, 2006 and the years ended December 31, 2005 and 2004
See accompanying notes to financial statements.
WESTMORELAND-LG&E PARTNERS
Statements of Cash Flows
For the six months ended June 30, 2006 and the years ended December 31, 2005 and 2004
See accompanying notes to financial statements.
WESTMORELAND-LG&E PARTNERS
NOTES TO FINANCIAL STATEMENTS
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization - Westmoreland-LG&E Partners (the “Venture”), a Virginia general partnership, was formed to own and operate two cogeneration facilities (the “Facilities”) located in Weldon, North Carolina. The first facility (“ROVA I”) is a 180 MW facility and the second facility (“ROVA II”) is a 50 MW facility adjacent to ROVA I. The Facilities share certain coal handling, electrical distribution, and administrative equipment. The Facilities produce electric power and steam by burning coal. The steam is sold to a local industrial plant for use in its manufacturing process. ROVA I and ROVA II operate as exempt wholesale generators as determined by the Federal Energy Regulatory Commission (“FERC”). ROVA I commenced commercial operation on May 29, 1994 (Commercial Operations Date). ROVA II commenced commercial operation on June 1, 1995 (Commercial Operations Date).
On June 29, 2006, Westmoreland Coal Company (“Westmoreland”) acquired a 50% partnership interest in the venture from a subsidiary of E.ON U.S. LLC (“E.ON”) - formerly LG&E Energy LLC. The transaction increases Westmoreland’s interest in the Venture to 100%. As part of the same transaction, Westmoreland acquired certain additional assets from LG&E Power Services LLC, a subsidiary of E.ON, consisting primarily of contracts under which Westmoreland will now operate and provide maintenance services to ROVA and four power plants in Virginia. For accounting purposes, the acquisition was assumed to have been completed effective June 30, 2006.
Subsequent to the acquisition, the partners in the Venture are Westmoreland-Roanoke Valley, L.P. (“Westmoreland L.P.”), a limited partnership between Westmoreland Energy LLC. (“WEI”), as the sole limited partner, and WEI-Roanoke Valley, Inc., a wholly owned subsidiary of WEI, as the sole general partner, and Westmoreland North Carolina Power LLC, a wholly owned subsidiary of WEI. The partner previous to the acquisition was LG&E Roanoke Valley L.P. (“LG&E L.P.”), a limited partnership between LG&E Power Roanoke Incorporated, an indirect wholly owned subsidiary of LG&E Power Inc. (“LPI”), as the sole limited partner, and LG&E Power 16 Incorporated, an indirect wholly owned subsidiary of LPI, as the sole general partner. Under the terms of the General Partnership Agreement (“Partnership Agreement”), after priority allocations to Westmoreland L.P., all income, loss, tax deductions and credits, and cash distributions were allocated approximately 50% to Westmoreland L.P. and 50% to Westmoreland North Carolina Power LLC.
Power Sales Agreement - The Venture has entered into two Power Purchase and Operating Agreements (“Power Agreements”) with North Carolina Power Company, a division of Dominion Virginia Power Company (“DVP”), for the sale of all energy produced by the Facilities. Each Power Agreement is for an initial term of 25 years from the respective Commercial Operations Date. Revenue is recognized for these Power Agreements as amounts are invoiced.
Under the terms of ROVA I Power Agreement, the energy price consists of an Energy Purchase Price (“ROVA I Energy Price”) and a Purchased Capacity Unit Price (“ROVA I CUP”). ROVA I Energy Price is billed for each kilowatt-hour delivered and is comprised of a Base Fuel Compensation Price (“ROVA I Fuel Price”) and an Operating and Maintenance Price (“ROVA I O&M Price”). ROVA I Fuel Price is adjusted quarterly and ROVA I O&M Price is adjusted annually based upon the Gross Domestic Product Implicit Price Deflator Index (“GDPIPD”). ROVA I CUP is determined by dividing the sum of the applicable capacity components (the Fixed Capacity Component and the O&M Capacity Component) by a three-year rolling average capacity factor (“Average Capacity Factor”) expressed in cents per kilowatt-hour. Annually, on April 1, the O&M Capacity Component is adjusted by the percentage change in the GDPIPD. The Venture recognizes revenue based on the billed ROVA I Energy Price and ROVA I Delivered Capacity expressed in kilowatt-hours multiplied by ROVA I CUP. In addition, a notional, off-balance sheet account (the “Tracking Account”) has been established to accumulate differences in actual capacity versus the three-year rolling average capacity to facilitate calculation of Capacity Purchase Payment Adjustments. If the Actual Capacity Factor for any year is less than the Average Capacity Factor, the Tracking Account is decreased and the Venture will recognize additional revenue from the Capacity Purchase Payment Adjustment to the extent of the positive balance in the
WESTMORELAND-LG&E PARTNERS
NOTES TO FINANCIAL STATEMENTS - (Continued)
Tracking Account. If the Actual Capacity Factor for any year is greater than the Average Capacity Factor, the Tracking Account is increased, but no additional revenue is recognized. As of June 30, 2006, December 31, 2005 and 2004, the Tracking Account contained a positive balance of $829,022, $829,022 and $1,168,971, respectively, which is not included in the financial statements.
Under the terms of ROVA II Power Agreement, the energy price consists of an Energy Purchase Price (“ROVA II Energy Price”) and a Purchased Capacity Price (“ROVA II Capacity Price”). ROVA II Energy Price is billed for each kilowatt-hour delivered, reduced by 2.25% for line losses, and is comprised of a Base Fuel Compensation Price (“ROVA II Fuel Price”) and an Operating and Maintenance Price (“ROVA II O&M Price”). ROVA II Fuel Price is adjusted quarterly and ROVA II O&M Price is adjusted annually based upon the GDPIPD. ROVA II Capacity Price is based on the Dispatch Level, Dependable Capacity, and Net Electrical Output, and is comprised of a fixed amount per kilowatt-hour plus a variable amount per kilowatt-hour, which is adjusted annually based upon the GDPIPD. The Venture recognizes revenue based on the billed ROVA II Energy Price and ROVA II Capacity Price.
Energy Services Agreement - The Venture has entered into an Energy Services Agreement (“Energy Agreement”) with Patch Rubber Company for the sale of steam produced by the Facilities. The Energy Agreement is for an initial term of 15 years from the later of ROVA I Initial Delivery Date or ROVA II Initial Delivery Date with three five-year renewal options. Under the terms of the Energy Agreement, the volume of steam delivered determines payments to the Venture. The prices of delivered steam is increased annually based upon the Gross National Product Implicit Price Deflator Index (“GNPIPD”) beginning January 1, 1991, except that such increase shall not exceed 3% per year. The Venture recognizes revenue on steam sales based on the volume of steam delivered.
Cash Equivalents - The Venture considers all highly liquid securities purchased with an original maturity of three months or less to be cash equivalents.
Fuel Inventories - Fuel inventories, which consist primarily of coal, are valued at the lower of cost or market. Cost is determined by the moving weighted average method.
Property, Plant, and Equipment - Depreciation is provided on a straight-line method over the estimated useful lives of the assets except for the ash monofills. The ash monofills are amortized on a cost per ton basis multiplied by tons sent to each monofill. The ash monofills were built as disposal sites for the ash generated during operations.
Balance of property, plant, and equipment, at cost, as of December 31, 2005 and 2004, is as follows:
WESTMORELAND-LG&E PARTNERS
NOTES TO FINANCIAL STATEMENTS - (Continued)
Loan Origination Fees - Loan origination fees incurred in conjunction with obtaining the construction and term loan, institutional loan, and bond financing have been capitalized. These costs are being amortized by the effective-interest method over the lives of the notes and bonds. Accumulated amortization as of December 31, 2005 and 2004 was $9,149,105 and $8,440,671, respectively.
Restricted Assets - Restricted assets represent cash deposits to the Debt Protection Account (“DPA”), the Ash Reserve Account (“Ash”) and the Repair and Maintenance Account (“R&M”) as required by the Credit Agreement. At December 31, 2005 and 2004, the DPA balance was fully funded at $21,724,657 and $20,408,247, respectively. The maximum Ash balance is $600,000, of which $606,009 and $603,276 has been funded by the Venture at December 31, 2005 and 2004, respectively, in accordance with the terms of the Credit Agreement. The maximum R&M balance is $2,200,000 through January 31, 2004, and $2,600,000 thereafter until January 31, 2010, of which $518,330 and $1,543,017 has been funded by the Venture at December 31, 2005 and 2004, respectively, in accordance with the terms of the Credit Agreement. The remaining R&M balance will be funded incrementally on each distribution date until such time as it is fully funded. See Note 3 Long-Term Debt.
Intangible Asset - The Venture paid $215,973 to construct a steam host physically located on the property of Patch Rubber Company. The Venture has rights to use the system through October 2006. These costs have been amortized on a straight-line basis over a period of nine years. Accumulated amortization was $215,973 and $205,589 at December 31, 2005 and 2004, respectively.
Major Maintenance - The Venture expenses major maintenance costs as incurred.
Income Taxes - The Venture is a partnership and, as such, does not record or pay income taxes. Each Venture partner reports its respective share of the Venture’s taxable income or loss for income tax purposes.
Derivatives - Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, requires that all derivatives be recognized in the financial statements as either assets or liabilities and that they be measured at fair value. Changes in fair value are recorded as adjustments to the assets or liabilities being hedged in Other Comprehensive Income (Loss), or in current earnings, depending on whether the derivative is designated and qualifies for hedge accounting, the type of hedge transaction represented and the effectiveness of the hedge.
In connection with the adoption of SFAS No. 133, SFAS No. 138 and SFAS No. 149, the Venture classified its Interest Rate Exchange Agreements (“Swap Agreements”) as cash flow hedges. At December 31, 2005 and 2004, the fair value of the Swap Agreements is recorded as a noncurrent liability of $126,134 and $1,139,311, respectively. The change in fair value is recorded as a component of Other Comprehensive Income. The swap agreement was terminated as of June 30, 3006.
Asset Retirement Obligation - In August 2001, FASB issued Statement No. 143, Accounting for Asset Retirement Obligations, and the Venture adopted this statement effective January 1, 2003. Statement No. 143 addresses financial accounting for legal obligations associated with the retirement of long-lived assets and requires the Venture to recognize the fair value of an asset retirement obligation in the period in which that obligation is incurred. The Venture capitalizes the present value of estimated retirement costs as part of the carrying amount of long-lived assets.
WESTMORELAND-LG&E PARTNERS
NOTES TO FINANCIAL STATEMENTS - (Continued)
As of December 31, 2005 and 2004, the Venture’s obligation recorded in Other Noncurrent Liabilities was $400,307 and $374,119, respectively. Changes in the Venture’s asset retirement obligations for the years ended December 31, 2005 and 2004 were as follows:
Use of Estimates - Financial statements prepared in conformity with accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates.
Reclassification - Certain prior period amounts have been reclassified to conform to the current period presentation.
2.
FINANCIAL INSTRUMENTS
The Venture is a party to financial instruments with off-balance sheet risk. Pursuant to SFAS No. 107, Disclosures about Fair Value of Financial Instruments, the Venture is required to disclose the fair value of financial instruments where practicable. The carrying amounts of cash equivalents, accounts receivable, and accounts payable reflected on the balance sheets approximate the fair value of these instruments due to the short duration to maturity. The fair value of long-term debt is based on the interest rates available to the Venture for debt with similar terms and maturities. The fair value of interest rate swaps is based on the quoted market price.
The carrying value and estimated fair value of the Venture’s financial instruments as of December 31, 2005 and 2004 are as follows:
WESTMORELAND-LG&E PARTNERS
NOTES TO FINANCIAL STATEMENTS - (Continued)
3.
LONG-TERM DEBT
Long-term debt at December 31, 2005 and 2004 consisted of the following:
On December 18, 1991, the Venture entered into the Credit Agreement (“Tranche A”) with a consortium of banks (the “Banks”) and an Institutional Lender for the financing and construction of ROVA I facility. On December 1, 1993, the Credit Agreement was amended and restated (“Tranche B”) to allow for the financing and construction of the ROVA II facility. Under the terms of the Credit Agreement, the Venture is permitted to borrow up to $229,887,000 from the Banks (“Bank Borrowings”), $120,000,000 from an Institutional Lender (“Institutional Borrowings”), and $36,760,000 in tax-exempt facility revenue bonds (“Bond Borrowings”) under two Indenture Agreements with the Halifax County, North Carolina, Industrial Facilities and Pollution Control Financing Authority (“Financing Authority”). The borrowings are evidenced by promissory notes and are secured by land, the facilities, the Venture’s equipment, inventory, accounts receivable, certain other assets and the assignment of all material contracts. Bank borrowings amounted to $73,071,787 and $90,791,724 at December 31, 2005 and 2004, respectively and mature in 2008. The Credit Agreement requires interest on the Bank borrowings at rates set at varying margins in excess of the Banks’ base rate, London Interbank Offering Rate (“LIBOR”) or certificate of deposit rate (“CD”), for various terms from one day to one year in length, each to be selected by the Venture when amounts are borrowed. Interest payments for all elections are generally due at the end of the applicable interest period. However, if such interest period extends beyond a quarterly date, then interest is due on each quarterly date and at the end of the applicable interest period. During the years ended December 31, 2005 and 2004, the weighted average interest rate on the outstanding Bank borrowings was 4.80% and 2.90%, respectively. The interest rate at December 31, 2005 and 2004 was 5.86% and 3.85%, respectively.
At the Tranche A Conversion Date (January 31, 1995), Westmoreland L.P. and LG&E L.P. contributed a combined total of $8,571,224 (“Tranche A Equity Funding”) to the Venture to reduce the principal amount of the outstanding Tranche A Bank Borrowings. The remaining principal balance of the Tranche A Bank Borrowings converted into a term loan (“Tranche A Term Loan”). Principal payments under the Tranche A Term Loan are based upon fixed percentages, ranging from 0.75% to 7.55% of the Tranche A Term Loan, and are paid in 38 semiannual installments ranging from $850,000 to $4,250,000.
At the Tranche B Conversion Date (October 19, 1995), Westmoreland L.P. and LG&E L.P. contributed a combined total of $9,222,152 (“Tranche B Equity Funding”) to the Venture to reduce the principal amount of the outstanding Tranche B Bank Borrowings. The remaining principal balance of the Tranche B Bank
WESTMORELAND-LG&E PARTNERS
NOTES TO FINANCIAL STATEMENTS - (Continued)
Borrowings converted into a term loan (“Tranche B Term Loan”). Principal payments under the Tranche B Term Loan are based upon fixed percentages, ranging from 0.68% to 7.87% of the Tranche B Term Loan, and are paid in 40 semiannual installments ranging from $294,000 to $6,510,000.
Under the terms of the Credit Agreement, interest on the Tranche A Institutional Borrowings is fixed at 10.42% and interest on the Tranche B Institutional Borrowings is fixed at 8.33%.
In accordance with the Indenture Agreement, the Financing Authority issued $29,515,000 of 1991 Variable Rate Demand Exempt Facility Revenue Bonds (“1991 Bond Borrowings”) and $7,245,000 of 1993 Variable Rate Demand Exempt Facility Revenue Bonds (“1993 Bond Borrowings”). The 1991 Bond Borrowings and the 1993 Bond Borrowings are secured by irrevocable letters of credit in the amounts of $30,058,400 and $7,378,387, respectively, which were issued to the respective Trustee by the Banks. The fees associated with the letters of credit totaled $781,424 and $751,449 for the years ended December 31, 2005 and 2004, respectively. The weighted average interest rate for the outstanding Bond Borrowings was 4.09%, 2.43% and 1.24% for the six months ended June 30, 2006 and the years ended December 31, 2005 and 2004, respectively. The interest rate at December 31, 2005 and 2004 was 3.10% and 1.62%, respectively. The 1991 Bond Indenture Agreement requires repayment of the 1991 Bond Borrowings in four semi-annual installments of $1,180,600, $1,180,600, $14,757,500, and $12,396,300. The first installment of the 1991 Bond Borrowings is due in January 2008. The 1993 Indenture Agreement requires repayment of the 1993 Bond Borrowings in three semi-annual installments of $1,593,900, $1,811,250, and $3,839,850. The first installment is due in July 2009.
On January 17, 1992, the Venture entered into Interest Rate Exchange Agreements (“Swap Agreements”) with the Banks, which were created for the purpose of securing a fixed interest rate of 8.03% on approximately 63.3% of the Tranche A Bank Borrowings. These Swap Agreements have been classified as cash flow hedges. In return, the Venture receives a variable rate based on LIBOR, which averaged 4.75%, 3.3% and 1.46% during the first six months of 2006 and for the years ended December 31, 2005 and 2004, respectively. Under the terms of the Swap Agreements, the difference between the interest at the rate selected by the Venture at the time the funds were borrowed and the fixed interest rate is paid or received quarterly. Swap interest incurred under this agreement was $124,606, $947,958 and $2,229,660 for the six months ended June 30, 2006 and for the years ended December 31, 2005 and 2004, respectively.
To ensure performance under the Power Agreement, irrevocable letters of credit in the amounts of $4,500,000 and $1,476,000 were issued to DVP by the Banks on behalf of the Venture for ROVA I and ROVA II, respectively. The fees associated with the letters of credit totaled $53,342, $89,640 and $86,258 for the six months ended June 30, 2006 and for the years ended December 31, 2005 and 2004, respectively.
The debt agreements contain various restrictive covenants primarily related to construction of the Facilities, maintenance of the property, and required insurance. Additionally, the financial covenants include restrictions on incurring additional indebtedness and property liens, paying cash distributions to the partners, and incurring various commitments without lender approval. At June 30, 2006, December 31, 2005 and 2004, the Venture was in compliance with the various covenants.
Pursuant to the terms of the Credit Agreement, the Venture must maintain a debt protection account (“DPA”). On November 30, 2000, Amendment 6 to the Credit Agreement (“Amendment 6”) was negotiated with the Banks and the full funding level was increased to $22,000,000 and an additional $2,000,000 was funded. Beginning in 2002, additional funding of $1.1 million per year is required through 2008. In 2009, $6.7 million of the $9.7 million contributed from 2000-2008 will be available for partnership distribution. In 2010, the remaining $3 million will be available for partnership distribution and the full funding level reverts back to $20,000,000. At December 31, 2005, the DPA consists of $21,724,657 in cash (see Note 1, Restricted Assets) and a letter of credit in the amount of $5,000,000 provided by E.ON.
Balances held in the DPA are available to be used to meet shortfalls of debt service requirements. If the balance in the DPA falls below the required balance, the cash flow from the Facilities must be paid into the
WESTMORELAND-LG&E PARTNERS
NOTES TO FINANCIAL STATEMENTS - (Continued)
DPA until the deficiency is corrected. There were no deficiencies at June 30, 2006, December 31, 2005 or 2004.
The Credit Agreement requires the Venture to maintain an R&M account. Pursuant to Amendment 6, the Venture was required to increase its maximum funding level from $1.5 million to $2.2 million by January 31, 2004. See Note 1, Restricted Assets. The maximum funding level increased to $2.6 million from January 31, 2004 through January 31, 2010, after which date it reverts back to $2.2 million.
Under the terms of the Credit Agreement, the Venture must maintain an Ash Reserve Account. Pursuant to Amendment 6, the funding level of the Ash Reserve Account was reduced from $1,000,000 to $600,000. See Note 1, Restricted Assets. Also, a provision was made for the funds to be used for debt protection after the funds in the DPA and R&M are exhausted. Should the funds be used for debt protection, or should the Venture receive written notice from the Banks’ independent engineer that construction of a new ash monofill will be required, the funding level will immediately increase to $1,000,000.
Future principal payments on long-term debt at June 30, 2006, are as follows:
4.
COMMITMENTS AND CONTINGENCIES
Coal Supply Agreement - The Venture has entered into two Coal Supply Agreements (“Coal Agreements”) with TECO Coal Corporation (“TECO”). Under the terms of the Coal Agreements, TECO entered into a subcontract with Kentucky Criterion Coal Company (“KCCC”), an affiliate of WEI, to provide 79.5% of the coal requirements under the Coal Agreements. On December 16, 1994, WEI sold the assets of KCCC to Consol of Kentucky, Inc. (“Consol”). TECO consented to the assignment of the subcontract with KCCC to Consol. Each Coal Supply Agreement is for an initial term of 20 years from the respective Commercial Operations Date with two five-year renewal options. Under the terms of the Coal Agreements, the Venture must purchase a combined minimum of 512,500 tons of coal each contract year (“Minimum Quantity”). In the event the Venture fails to purchase the Minimum Quantity in any contract year, the Venture may be liable for actual and direct damages incurred by TECO, up to a maximum of $5 per ton for each ton short for ROVA I or 20% of the current base price for each ton short for ROVA II. The base price is adjusted annually on July 1 of each contract year based upon the GNPIPD. The average cost of coal per ton, including transportation cost, for the six months ended June 30, 2006 and for the years ended December 31, 2005 and 2004 was $49.62, 48.59 and $49.37, respectively. Coal purchases from TECO for the six months ended June 30, 2006 and for the years ended December 31, 2005 and 2004 were $10,390,453, $20,304,811 and $21,049,907, respectively.
Lime Supply Agreement - The Venture has entered into two Lime Supply Agreements (“Lime Agreements”) with O. N. Minerals (Chemstone) Corporation. The Lime Agreements were for an initial term of five years from the respective commercial operations dates and have been extended through December 31, 2008. Under the terms of the Lime Agreements, the Venture must purchase the greater of 100% of the Facility’s requirement or 10,000 tons of pebble lime per year for ROVA I and 4,500 tons of hydrated lime per year for ROVA II. The base price is increased annually over the life of the Lime Agreements.
WESTMORELAND-LG&E PARTNERS
NOTES TO FINANCIAL STATEMENTS - (Continued)
The average lime cost per ton, including transportation cost, for the six months ended June 30, 2006 and the years ended December 31, 2005 and 2004 was $98.15, $86.70 and $86.12, respectively. Total purchases and transportation under the agreements were $1,237,210, $1,597,170 and $2,067,817, respectively, for the six months ended June 30, 2006 and the years ended December 31, 2005 and 2004. See Rail Transportation Agreement below for information about contract terms and conditions.
Rail Transportation Agreement - The Coal Rail Transportation Agreement (“Coal Rail Agreement”) is for an initial term of 20 years from the commercial date of ROVA I, with two five-year renewal options. Under the terms of the Coal Rail Agreement, the base rate per ton is adjusted annually for the life of the Coal Rail Agreement. Additionally, the Venture must utilize CSX Transportation (“CSX”) for up to 95% of the coal received by the Facility on an annual basis. Failure to comply with this requirement may result in liquidated damages based on the difference between the 95% contract requirement and tons actually received. Total charges under the Coal Rail Agreement for the six months ended June 30, 2006 and the years ended December 31, 2005 and 2004 were $5,959,700, $10,564,729 and $12,270,821, respectively.
The Venture has entered into a Rail Transportation Agreement for the transportation of lime to the Facilities with CSX. The Lime Rail Transportation Agreement (“Lime Rail Agreement”), as amended, extends through June 10, 2008. Under the terms of the Lime Rail Agreement, the base rate per ton is adjusted annually, as determined in the Lime Rail Agreement, each June 11. Additionally, the Venture must utilize CSX for up to 95% of the lime received by ROVA I on an annual basis. Failure to comply with this requirement may result in liquidated damages based on the difference between the 95% contract requirement and the tons actually received. See Lime Supply Agreement above.
Property Tax Audit - The Venture is located in Halifax County, North Carolina and is the County’s largest taxpayer. In 2002, the County hired an independent consultant to review and audit personal property tax returns for the previous five years. In May 2002, the County advised the Venture that its returns were being scrutinized for potential underpayment and undervaluation of the property subject to tax. The Venture responded that its valuation was consistent with an agreement reached with the County in 1996. On November 5, 2002, the County assessed the Venture $4.6 million for the years 1997 to 2001. The Venture filed a protest with the Property Tax Commission. On May 26, 2004, the Tax Commission denied the Venture’s protest and issued an order consistent with the County’s assessment. The Venture appealed the Tax Commission’s decision to the North Carolina Court of Appeals on June 24, 2004. In December 2005, the Venture received an adverse ruling from the North Carolina Court of Appeals. The Venture did not appeal this ruling. At December 31, 2005, the Venture has recorded a liability of $10.6 million for this contingency in accounts payable and accrued liabilities on the balance sheet for the tax years 1996 to 2005. During the first quarter of 2006, the Venture paid $7.1 million, including penalties and interest, for the 1996 to 2001 tax years. During the second quarter of 2006, the Venture settled all outstanding personal property assessments for years 2000 to 2005, including interest and penalties, for approximately $3.7 million. Because the Venture had previously accrued for the assessments in its financial statements, there was no material impact on the Venture’s financial statements in the first six months of 2006 as a result of the settlement.
5.
RELATED-PARTY TRANSACTIONS
The Venture entered into an operating agreement with LG&E Power Services LLC, (the “Operator”), an affiliate of LPI, for the operation and maintenance of the Facility and administration of the Venture’s day-to-day operations expiring 25 years after the Commencement Date. The agreement provides for the reimbursement of payroll and other direct costs incurred by the Operator in performance of the agreement, reimbursement of the Operator’s overhead and general and administrative costs based on stated percentages of the reimbursable payroll costs, and a fixed fee. Reimbursed costs and fees incurred under the agreement were $3,090,014, $7,176,792 and $6,220,711, respectively, for the six months ended June 30, 2006 and for the years
WESTMORELAND-LG&E PARTNERS
NOTES TO FINANCIAL STATEMENTS - (Continued)
ended December 31, 2005 and 2004. At December 31, 2005 and 2004, $393,313 and $372,153, respectively, were owed to the Operator and are included in accounts payable in the accompanying financial statements.
The Venture incurred various costs that were paid to LPI and its affiliates, primarily relating to venture management fees, financial management, engineering, environmental services, and internal legal fees on behalf of the Venture. Fees incurred totaled $263,923, $575,149 and $580,993, respectively, for the six months ended June 30, 2006 and for the years ended December 31, 2005 and 2004. At December 31, 2005 and 2004, $104,994 and $131,358, respectively, were owed to LPI and are included in accounts payable-affiliate in the accompanying financial statements.
The Venture incurred various costs that were paid to WEI primarily relating to venture accounting fees and cost accounting services. Fees paid totaled $135,550, $276,628 and $236,500 for the six months ended June 30, 2006 and for the years ended December 31, 2005 and 2004, respectively. At December 31, 2005 and 2004, $14,000 and $0, respectively, were owed to WEI and are included in accounts payable-affiliate in the accompanying financial statements.
The Venture incurred maintenance costs, which were paid to Westmoreland Technical Services, Inc. (“WTS”). These costs totaled $915,132, $2,268,902 and $2,416,306 for the six months ended June 30, 2006 and for the years ended December 31, 2005 and 2004. At December 31, 2005 and 2004, $40,053 and $319,380, respectively, were owed to WTS and are included in accounts payable-affiliate in the accompanying financial statements.
Report of Independent Registered Public Accounting Firm
To the Partners of
Westmoreland-LG&E Partners:
We have audited the accompanying statements of operations and comprehensive loss, partners’ capital, and cash flows for the six months ended June 30, 2006. These 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 financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Westmoreland-LG&E Partners for the six moths ended June 30, 2006, in conformity with U.S. generally accepted accounting principles.
KPMG LLP
Denver, Colorado
March 30, 2007
INDEPENDENT AUDITORS’ REPORT
To the Partners of
Westmoreland-LG&E Partners
Louisville, Kentucky
We have audited the accompanying balance sheets of Westmoreland-LG&E Partners (the “Venture”) as of December 31, 2005 and 2004 and the related statements of operations and comprehensive income, partners’ capital, and cash flows for each of the two years in the period ended December 31, 2005. These financial statements are the responsibility of the Venture’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Venture’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Venture as of December 31, 2005 and 2004 and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.
Deloitte & Touche LLP
Indianapolis, Indiana
March 10, 2006
EXHIBIT INDEX
*
Compensatory benefit plan or arrangement or management contract.