(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
OR
( ) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to _______.
Commission File No. 001-11155
WESTMORELAND COAL COMPANY
(Exact name of registrant as specified in its charter)
| Delaware | 23-1128670 |
|
(State or other jurisdiction of incorporation or organization) | (I.R.S.
Employer Identification No.) |
14th Floor, 2 North Cascade Avenue, Colorado
Springs, CO 80903
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (719) 442-2600
| TITLE OF EACH CLASS | NAME OF STOCK EXCHANGE ON WHICH REGISTERED |
| Common Stock, par value $2.50 per share | American Stock Exchange |
| Depositary Shares, each representing one-quarter of a share of Series A Convertible Exchangeable Preferred Stock |
|
| Preferred Stock Purchase Rights |
| Series A Convertible Exchangeable Preferred Stock, par value $1.00 per share |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days.
Yes X No ___Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
XIndicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).
Yes X No ___The aggregate market value of voting common stock held by non-affiliates as of June 30, 2003 was $123,081,000.
There were 8,023,384 shares outstanding of the registrant’s Common Stock, $2.50 Par Value (the registrant’s only class of common stock), as of March 10, 2004.
There were 820,333 depositary shares, each representing one quarter of a share of the registrant’s Series A Convertible Exchangeable Preferred Stock, $1.00 par value per preferred share, outstanding as of March 10, 2004.
The definitive proxy statement to be filed not later than 120 days after the end of the fiscal year covered by this Form 10-K is incorporated by reference into Part III.
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| Item | Page |
| 1 | Business | 2 |
| 2 | Properties | 14 |
| 3 | Legal Proceedings | 20 |
| 4 | Submission of Matters to a Vote of Security Holders | 25 |
| 5 | Market for Registrant's Common Equity and Related Stockholder Matters | 27 |
| 6 | Selected Financial Data | 29 |
| 7 | Management's Discussion and Analysis of Financial Condition and Results of Operations | 30 |
| 7A | Quantitative and Qualitative Disclosures About Market Risk | 54 |
| 8 | Financial Statements and Supplementary Data | 56 |
| 9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 95 |
| 9A | Controls and Procedures | 95 |
| 10 | Directors and Executive Officers of the Registrant | 95 |
| 11 | Executive Compensation | 95 |
| 12 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 95 |
| 13 | Certain Relationships and Related Transactions | 95 |
| 14 | Principal Accountant Fees and Services | 95 |
| 15 | Exhibits, Financial Statement Schedule, and Reports on Form 8-K | 96 |
| Signatures | 105 |
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Throughout this Form 10-K, we make statements which are not historical facts or information and that may be deemed “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements include, but are not limited to, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations. For example, words such as “may,” “will,” “should,” “estimates,” “predicts,” “potential,” “continue,” “strategy,” “believes,” “anticipates,” “plans,” “expects,” “intends,” and similar expressions are intended to identify forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties and other factors, which may cause the actual results, levels of activity, performance or achievements of the Company, or industry results, to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others, the following: general economic and business conditions; health care cost trends; the cost and capacity of the surety bond market; the Company’s ability to manage growth and significantly expanded operations; the ability of the Company to implement its business strategy; the Company’s ability to pay the preferred stock dividends that are accumulated but unpaid; the Company’s ability to retain key senior management; the Company’s access to financing; the Company’s ability to maintain compliance with debt covenant requirements; the Company’s ability to successfully identify new business opportunities; the Company’s ability to achieve anticipated cost savings and profitability targets; the Company’s ability to negotiate profitable coal contracts, price reopeners and extensions; the Company’s ability to maintain satisfactory labor relations; changes in the industry; competition; the Company’s ability to utilize its income tax net operating losses; the ability to reinvest excess cash at an acceptable rate of return; weather conditions; the availability of transportation; price of alternative fuels; costs of coal produced by other countries; demand for electricity; the effect of regulatory and legal proceedings, including the bankruptcy filing by Touch America Holdings Inc. and Entech Inc.; the claims between the Company and Montana Power; and the other factors discussed in Items 1, 3 and 7. As a result of the foregoing and other factors, no assurance can be given as to the future results and achievement of the Company’s goals. The Company disclaims any duty to update these statements, even if subsequent events cause its views to change.
References in this document to www.westmoreland.com, any variations of the foregoing, or any other uniform resource locator, or URL, are inactive textual references only. The information on our Web site or any other Web site is not incorporated by reference into this document and should not be considered to be a part of this document.
| ITEM 1 – | BUSINESS |
We are an energy company. We are the oldest independent coal company in the United States with our origin in 1854. The coal we mine is used to produce electric power, and we own interests in power-generating plants. Beginning in 2004, we also will receive royalties from the production of coalbed methane gas.
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We were the 10th largest coal producer in the Unites States, ranked by tons of coal mined in 2002, the last year for which data is available. In 2003, we increased our coal production to 27.7 million tons, about 3% of all the coal produced in the United States, and we believe that we continue to rank among the top 10 U.S. coal producers.
| Mines | |||||
We own five mines; all except the Jewett Mine are located in the northern tier, a niche coal market extending from Montana through Minnesota and other upper Midwestern states. The mines are:
| • | the Absaloka Mine, | ||||
| • | the Rosebud Mine, | ||||
| • | the Jewett Mine, | ||||
| • | the Beulah Mine, and | ||||
| • | the Savage Mine. | ||||
The Absaloka Mine is owned by our subsidiary, Westmoreland Resources, Inc. The Beulah, Jewett, Rosebud, and Savage Mines are owned by our subsidiary, Westmoreland Mining LLC.
All of these mines are surface mines. Surface mining involves extracting coal that lies close to the surface. Where the surface layer contains rock, electric 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, bulldozers, front-end loaders, backhoes, or electric shovels load the coal in dump trucks. After the coal has been extracted, it is processed (typically by crushing), sampled (or “assayed”), and then shipped to customers.
The Absaloka Mine is located on approximately 15,000 acres in Big Horn County, Montana, near the town of Hardin. Coal was first extracted from the Absaloka Mine in 1974. Westmoreland Resources owns the Absaloka Mine. We own 80% of the stock of Westmoreland Resources. Washington Group International, Inc. owns the remaining 20% and operates the mine. Unless otherwise indicated, we own 100% of each of our other subsidiaries.
The Rosebud Mine is located on approximately 25,000 acres in Rosebud and Treasure Counties, Montana, near the town of Colstrip, about 130 miles east of Billings. Coal production from the existing mine complex began in 1968. Coal was first mined near Colstrip in 1924. 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, Northwestern Resources Co., owns and operates the Jewett Mine. Westmoreland Mining acquired the stock of Northwestern Resources from Entech, Inc., a subsidiary of The Montana Power Company, in April 2001.
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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.
The Savage Mine is located on approximately 1,600 acres in Richland County, Montana, near the town of Sidney. Production began at the Savage Mine in 1958. Westmoreland Mining’s subsidiary, Westmoreland Savage Corporation, owns and operates the Savage Mine. Westmoreland Mining acquired the Savage Mine in May 2001 from Knife River Corporation.
The following table presents the sales from our mines in the last three years:
| Year | Absaloka Mine | Rosebud Mine | Jewett Mine | Beulah Mine | Savage Mine |
| 2003 | 6,016 | 11,003 | 7,462 | 2,816 | 379 |
| 2002 | 5,160 | 10,061 | 7,105 | 3,006 | 337 |
| 2001 | 5,904 | 11,284(1) | 7,138(2) | 3,087(3) | 346(4) |
| (1) Of this amount, 7,610,000 tons were sold in 2001 after we acquired the mine. | |||||
| (2) Of this amount, 4,463,000 tons were sold in 2001 after we acquired the mine. | |||||
| (3) Of this amount, 2,014,000 tons were sold in 2001 after we acquired the mine. | |||||
| (4) Of this amount, 236,000 tons were sold in 2001 after we acquired the mine. |
| Customers, Competition, and Coal Supply Agreements. | |||||
We supply coal to plants that generate electricity. These plants compete with all other producers of electricity to be “dispatched,” or called upon to generate power. We compete with many other suppliers of coal to provide fuel to these plants.
| We believe that the competitive advantage of our mines derives from two facts: | |||||
| • | all of our mines are the lowest cost-suppliers to each of their respective principal customers; | ||||
| • | Nearly all of the power plants we supply were specifically designed to use our coal | ||||
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The plants we supply are among the lower cost producers of electric power in their respective regions and employ emissions control technology. 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. (Power-generating plants of this type are sometimes called “baseload” or “baseloaded” plants.)
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 Rosebud, Jewett, and Beulah Mines sell their coal to power plants located adjacent to the mines, so that the coal can be delivered by conveyor belt or in-pit truck rather than by more expensive means such as on-road truck or rail. The customers of the Savage Mine are located 25-30 miles from the mine, so that coal can be transported economically by on-road truck. The Absaloka Mine enjoys about a 300 mile advantage over its principle competitors from the Southern Powder River Basin, (“SPRB”). We believe that all of our mines are the lowest cost-suppliers to each of their respective customers, and that certain of our mines are also in a position to be the next lowest cost alternative suppliers to these customers.
The Rosebud Mine’s primary customers are the owners of the four-unit Colstrip Station, which has a generating capacity of approximately 2,200 megawatts, or MW, and is located adjacent to the mine. The Rosebud Mine has supplied the Colstrip Station since 1975, when Colstrip Units 1&2 commenced commercial operations. Western Energy sells this coal under long-term contracts expiring in 2009 for Colstrip Units 1&2 and in 2019 for Colstrip Units 3&4. The contract with Colstrip Units 1&2 specifies the base price per ton we will receive. The base price is subject to adjustment for certain indices and changes in our costs. Under this contract, we are also entitled to receive a reasonable profit. The price under this contract is renegotiated or “reopened” at 5 year intervals. We are currently arbitrating the final reopener, from 2001. We settled the cost portion of the price reopener in December 2003. During the first week of March 2004, we arbitrated the profit component, and we are awaiting the arbitrators’ decision. Western Energy’s coal supply agreement with the owners of Colstrip Units 3&4 is a cost-plus arrangement that provides a return on investment on mine assets as well as certain set fees. The owners of Colstrip Units 3&4 also compensate Western Energy under separate contract for transporting the coal to them on a conveyor belt that Western Energy owns. With certain exceptions, the contracts with the owners of the Colstrip Station are full requirements contracts; that is, the Colstrip Units are required to purchase their coal requirements from or through the Rosebud Mine. The Rosebud Mine also supplies coal to Minnesota Power under a coal supply agreement that expires in 2008. Under this contract, Minnesota Power pays a base price per ton, which increases each year by a fixed percentage.
The Jewett Mine’s sole customer is Texas Genco, L.P., the owner of the two-unit Limestone Electric Generating Station, which has a generating capacity of approximately 1,710 MW and is located adjacent to the mine. The Jewett Mine has supplied the Limestone Station since 1985, when it commenced commercial operations. The Jewett Mine sells lignite to Texas Genco pursuant to an Amended Lignite Supply Agreement (“ALSA”) that expires in 2015. The ALSA provides for the annual determination of volumes and pricing, with pricing based on an equivalent value of coal from Wyoming’s SPRB, as delivered to and used at the Limestone Station. Northwestern Resources and Texas Genco have disputed the proper interpretation of some elements of the ALSA from time to time. In January of 2004, Northwestern Resources and Texas Genco settled certain of the disputes between them. Among other things, Texas Genco committed to purchase approximately 7 million tons of lignite from the Jewett Mine per year during the years 2004 through 2007, and, for that same period, the parties agreed to the price for that lignite, and resolved various contract disputes.
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The Beulah Mine supplies the Coyote Station, which has a generating capacity of approximately 420 MW and is located adjacent to the mine, and the Heskett Station, which has a generating capacity of 100 MW and is located in Mandan, North Dakota, approximately 74 miles from the mine. (Coal is shipped to the Heskett Station on the Burlington Northern Santa Fe Railway (“BNSF”).) The Beulah Mine has supplied the Coyote Station since 1981, when it commenced commercial operations, and the Heskett Station since 1963. The contract with the Coyote Station expires in 2016. The contract with the Heskett Station expires in 2005, but we have the option to renew it for an additional five years. The price of the coal under these contracts is based on certain of the Beulah Mine’s costs, is adjusted for certain indices and mine costs, and for the Coyote Station is supplemented by a provision setting forth guaranteed minimum and maximum net income levels. The Beulah Mine’s contracts with the Coyote Station and with a minor exception, the Heskett Station are each full requirements contracts.
The Savage Mine supplies coal to the Lewis & Clark Station, which has a generating capacity of approximately 49 MW, and the Sidney Sugars plant, which uses coal from the Savage Mine to heat its boilers and process sugar beets. These facilities are located approximately 20 and 25 miles from the mine, respectively, so that coal can be transported to them economically by on-road truck. The Savage Mine has supplied the Lewis & Clark Station since 1958, when it commenced commercial operations. The Savage Mine’s contracts with the Lewis & Clark Station and the Sidney Sugars plant run until 2007 and 2008, respectively. These contracts, which involve smaller volumes than our other coal supply contracts, are with minor exceptions each full requirements contracts.
The Absaloka Mine faces a different competitive situation than our other mines. The Absaloka Mine sells its coal in the rail market, to utilities located in the northern tier of the United States that are served by the BNSF. These utilities may purchase coal from us or from other producers, and we compete with other producers on the basis of price and quality, with the purchasers also taking into account the cost of transporting the coal to their plants. The Absaloka Mine was developed to supply the Sherburne County Station, a three unit power plant near Minneapolis, Minnesota, with a generating capacity of 2,292 MW. The Absaloka Mine has a transportation advantage to the Sherburne County Station because it is located about 300 rail miles closer to that power plant than other mines competing for that business. The Absaloka Mine has supplied the Sherburne County Station since 1976, when it commenced commercial operations. The Absaloka Mine has three separate coal sales contracts to supply the Sherburne County Station. The largest, with Xcel Energy, covers 3.4 million tons per year and expires in 2007. Westmoreland Resources also currently supplies 1.0 million tons per year to the Sherburne County Station through an agreement held by Westmoreland Coal Sales Company with Xcel Energy. We are paid prices under these contracts that are adjusted by certain indices. The second largest, with Western Fuels Association, the fuel buyer for Southern Minnesota Municipal Power Agency (“SMMPA”), covers almost all of SMMPA’s fuel requirements for Unit 3 at the Sherburne County Station, or approximately 1.5 million tons per year, and expires in 2007. The price we receive under this contract is also adjusted by certain indices. The Absaloka Mine also sells coal to the Xcel Energy’s A.S. King Station and to Consumers Energy Company, through Midwest Energy Resources Company (a subsidiary of Detroit Edison), under contracts expiring in 2007 and 2004, respectively.
In February 2004, we reached agreement with the Crow Tribe for exploration of new coal reserves in order to continue serving these customers beyond exhaustion of the reserves in our existing lease.
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The following table shows, for each of the past five years, our coal revenues, the tons sold from mines that we owned at the time of production, the percentage of our coal sales made under long-term contracts, and the weighted average price per ton that we received under these long-term contracts.
| Year | Coal Revenues in Dollars (in 000’s) |
Coal Sales in Equivalent Tons (in 000’s) |
Percentage of Coal Sales Under Long-Term Contracts |
Weighted Average Price Per Ton Received under Long-Term Contracts(1) |
| 2003 | $ 294,986 | 27,762 | 99% | $ 10.45 |
| 2002 | 301,235 | 26,062 | 100% | 11.29 |
| 2001 | 231,048 | 20,503 | 99% | 11.05 |
| 2000 | 35,137 | 4,910 | 100% | 7.16 |
| 1999 | 38,539 | 5,466 | 100% | 7.05 |
| (1) | The weighted average price per ton that we received declined from 2002 to 2003 principally because, as anticipated, the Jewett Mine transitioned from cost-plus-fees pricing to the market-based pricing mechanism described above, effective July 1, 2002. |
Our coal revenues include amounts earned by our coal sales company from sales of coal produced by mines other than ours. In 2003 and 2002, such amounts were $5.5 million and $6.8 million, respectively.
We consider a contract that calls for deliveries to be made over a period longer than one year a long-term contract. In 2003, our two largest contract customers, the owners of Colstrip Units 3&4 and Texas Genco, accounted for 34% and 24%, respectively, of our coal revenues. No other customer or contract accounted for as much as 10% of our coal revenues in 2003. The owners of Colstrip Units 3&4 are Avista Corporation, NorthWestern Corporation, PacifiCorp, Portland General Electric Company, PPL Montana LLC, and Puget Sound Energy, Inc.
The following table presents our estimate of the sales under our existing long-term contracts, for the next five years. The prices for all of these tons are subject to revision and adjustments based upon market prices, certain indices, and/or cost recovery. We also would expect to continue to supply customers whose contracts expire before the end of 2008, but have not included those tonnages in this projection.
| Projected Sales Tonnage Under | |
| Existing Long-Term Contracts (in millions of tons) |
|
| 2004 | 29.6 |
| 2005 | 28.8 |
| 2006 | 28.3 |
| 2007 | 27.8 |
| 2008 | 22.3 |
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This table generally excludes new contracts and takes into account the scheduled outages at our customers’ plants, where known. We anticipate replacing sales as contracts expire with extensions, new contracts, or spot sales over the life of our coal reserves.
| Protecting the Environment | |||||
We consider ourselves stewards of the environment. We reclaim the areas that we mine, and we believe that our activities are 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 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 important to us. We maintain active safety programs at all of our mines. Our mines focus on 100% compliance with safe practices, safety rules, and regulations. Based on data from the Mine Safety and Health Administration (“MSHA”), an agency of the U.S. Department of the Interior, our mines had a lost-time incident rate of 1.48 in 2003, compared to the national average of 2.35 (through third quarter). The lost-time incident rate is an industry standard measure of safety performance for surface mines that measures frequency of incidents.
Through Westmoreland Energy LLC and its direct and indirect subsidiaries, we own interests in three power-generating plants:
| • | a 50% interest in the Roanoke Valley I Project, a 180 MW coal-fired plant located in Weldon, North Carolina; | ||||
| • | a 50% interest in the Roanoke Valley II Project, a 50 MW coal-fired plant also located in Weldon, North Carolina; and | ||||
| • | a 4.49% interest in the Fort Lupton Project, a 290 MW natural-gas fired plant located in Fort Lupton, Colorado. | ||||
We call the Roanoke Valley units ROVA I and ROVA II and both units the ROVA Project.
The ROVA Project and the Fort Lupton Project are each independent power projects. Independent power projects are power-generating plants that were not built by the regulated utility that purchases the plant’s output.
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Each of these projects has a long-term contract with a fuel supplier and a long-term contract with a “steam host,” a business that uses the steam that is generated in the production of power. These projects also have long-term contracts with electric utilities, which purchase the power that the projects generate. The table below presents information about each of our projects.
| Project | Roanoke Valley I |
Roanoke Valley II |
Ft. Lupton |
| Location | Weldon, North Carolina |
Weldon, North Carolina |
Ft. Lupton, Colorado |
| Gross Megawatt Capacity | 180 MW | 50 MW | 290 MW |
| Our Equity Ownership | 50.0% | 50.0% | 4.49% |
| Electricity Purchaser | Dominion Virginia Power | Dominion Virginia Power | Public Service of Colorado |
| Steam Host | Patch Rubber Company | Patch Rubber Company | Rocky Mtn. Produce, Ltd |
| Fuel Type | Coal | Coal | Natural Gas |
| Fuel Supplier | TECO Coal/ CONSOL | TECO Coal/ CONSOL | Thermo Fuels, Inc. |
| Commercial Operation Commencement Date | 1994 | 1995 | 1994 |
| Contracts with steam host & electricy purchaser expire in | 2019 | 2020 | Unit 1 - 2019 Unit 2 - 2009 |
Like the power plants to which we sell coal, these projects compete with all other producers of electricity. The ROVA Project is baseloaded. In 2003, ROVA I had a capacity factor of 89% and ROVA II had a capacity factor of 90%. ROVA I produced 1,301,000 megawatt hours (MWh) in 2003; ROVA II produced 352,000 MWh during the year.
The Fort Lupton Project is a “peaking” plant. It provides power only when the demand for electricity exceeds the output of baseloaded units. The Fort Lupton Project produced approximately 899,000 MWh during 2003.
As part of our 2001 acquisitions, we obtained the stock of North Central Energy Company (“North Central”). North Central owns property and mineral rights in southern Colorado. In 2003, North Central leased the rights to explore, drill, and produce coalbed methane gas to Petrogulf Corporation for $300,000 and a royalty interest on production from wells drilled on North Central’s properties. Coalbed methane gas is natural gas that occurs in coal beds. Coalbed methane gas typically has a heating value, or Btu content, similar to that of other forms of natural gas and has uses identical to and competes with other forms of natural gas. As of December 31, 2003, twelve wells had been drilled. Commercial production began in early 2004. In 2003, North Central also sold certain surface and mineral property to local land owners for $1.4 million.
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Due to our excellent historical loss record, we have elected to retain some of the risks associated with operating our company, through the retention of a certain level of primary property and casualty insurance, thereby reducing the effect of escalating insurance premiums in those lines. We retain these risks through our wholly-owned, consolidated insurance subsidiary, Westmoreland Risk Management Ltd., a Bermuda corporation. We reduce our major exposure by insuring for losses in excess of our retained limits with a number of third party insurance companies. We have elected to report Westmoreland Risk Management as a taxable entity in the United States.
We previously owned a 20% partnership interest in Dominion Terminal Associates (“DTA”), the owner of a coal storage and vessel-loading facility in Newport News, Virginia. We sold our interest in DTA effective June 30, 2003.
Except for the assets of Westmoreland Risk Management, all of our assets are located in the United States. We had no export sales and derived no revenues from outside the United States during the five-year period ended December 31, 2003.
Our business is somewhat seasonal:
| • | The owners of the power plants to which we supply coal typically schedule maintenance for those plants in the spring and fall, when demand for electric power is typically less than it is during other seasons. For this reason, our coal revenues are usually higher in the winter and summer. | ||||
| • | The ROVA Project also typically undergoes scheduled maintenance in the spring and fall, so our equity in earnings from independent power is also lower in those seasons. | ||||
Numerous federal, state and local governmental permits and approvals are required for mining and independent power operations. Both our coal mining business and our independent power operations are subject to extensive governmental regulation, particularly with regard to matters such as employee health and safety, and permitting and licensing requirements which cover all phases of environmental protection. The permitting process encompasses both federal and state laws, addressing reclamation and restoration of mined land and protection of hydrologic resources. Federal regulations also protect the benefits for current and retired coal miners.
We believe that our operations comply with all applicable laws and regulations, and it is our policy to operate in compliance with all applicable laws and regulations, including those involving environmental matters. However, because of extensive and comprehensive regulatory requirements, violations occur from time to time in the mining and independent power industries. None of the violations to date or the monetary penalties assessed upon us has been material.
| Environmental Laws | |||||
We are subject to various federal, state and local environmental laws. Some of these laws, discussed below, place many requirements on our mines and the independent power plants in which we own interests.
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Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes mining, environmental protection and reclamation standards for all aspects of surface mining. OSM may delegate authority to state regulatory programs if they meet OSM standards. OSM has approved reclamation programs in Montana, North Dakota and Texas, and these states’ regulatory agencies have assumed primacy in mine environmental protection and compliance. Mine operators must obtain permits issued by the state regulatory authority. OSM maintains oversight authority on the permitting and reclamation process. We endeavor to comply with approved state regulations and those of OSM through contemporaneous reclamation, maintenance and monitoring activities.
Each of our mining operations must obtain all required permits before any activity can occur. Under the states’ approved program, an applicant for a permit must address requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation. While there may be some general differences between the states’ SMCRA approved programs, they are all very 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 permit submission for compliance with SMCRA and generally engages in a critical comment process designed to insure regulatory compliance and successful reclamation. When the state is satisfied that the permit applicant can and will comply with SMCRA, it will issue a permit. To insure 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 (“RCRA”); and Comprehensive Environmental Response, Compensation, and Liability Acts (“CERCLA”). Besides OSM, other Federal regulatory agencies are involved in monitoring or permitting specific aspects of mining operations. The U.S. Environmental Protection Agency (“EPA”) is the lead agency for States or Tribes with no authorized programs under the Clean Water Act, RCRA and CERCLA. The U.S. Bureau of Alcohol, Tobacco and Firearms (“ATF”) regulates the use of explosive blasting.
Clean Air Act. The Clean Air Act, the 1990 amendments to the Clean Air Act (“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 Clean Air Act permitting requirements and/or emission control requirements. The Clean Air Act directly affects the ROVA Project and indirectly affects our mines by extensively regulating the air emissions of particulates, fugitive dust, sulfur dioxide, nitrogen oxides and other compounds emitted by coal-fired generating plants.
Title IV of the Clean Air Act Amendments places limits on sulfur dioxide emissions from power-generating plants and sets baseline emission standards for these facilities. The affected electricity generators have been able to meet these requirements by, among other ways, switching to lower sulfur fuels, installing pollution control devices, such as flue gas desulphurization systems, which are known as “scrubbers,” reducing electricity generating levels or purchasing sulfur dioxide emission allowances. Emission sources receive sulfur dioxide emission allowances, which can be traded or sold.
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The Clean Air Act Amendments also require power plants that are major sources of nitrogen oxides in moderate or higher ozone non-attainment areas to install reasonably available control technology for nitrogen oxides, which are precursors of ozone. In addition, the EPA promulgated final rules that would require coal-burning power plants in 19 eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions beginning in May 2004. Installation of additional control measures required under the final rules will make it more costly to operate coal-fired generating plants. We discuss these rules below in more detail in the context of the ROVA Projects.
Clean Water Act. The Clean Water Act of 1972 affects coal mining operations by establishing in-stream water quality standards and treatment standards for effluent and/or waste water discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water. States are also adopting anti-degradation regulations in which a state designates certain water bodies or streams as “high quality.” These regulations would prohibit the diminution of water quality in these streams. Waters discharged from coal mines to high quality streams will be required to meet or exceed new “high quality” standards. The designation of high quality streams at our coal mines could require more costly water treatment and could aversely affect our coal production. We believe that all of our mines are in compliance with current discharge requirements.
Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act (“RCRA”), 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 concluded that coal combustion wastes do not warrant regulation as hazardous wastes under RCRA and has retained the hazardous waste exemption for these materials. However, the EPA has determined that national non-hazardous waste regulations under RCRA are needed for coal combustion wastes disposed in surface impoundments and landfills and used as mine-fill. The agency also concluded beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. As long as this exemption remains in effect, it is not anticipated that regulation of coal combustion waste will have any material effect on the amount of coal used by electricity generators.
| Health and Benefits | |||||
Mine Safety and Health. Congress enacted the Coal Mine Health and Safety Act in 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. The states in which we operate have programs for mine safety and health regulation and enforcement. Our safety activities are discussed above.
Black Lung. Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973.
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Coal Act. As discussed in more detail below, the Coal Industry Retiree Health Benefit Act imposes substantial costs on us.
| Independent Power | |||||
Many of the environmental laws and regulations described above, including the Clean Air Act Amendments, the Clean Water Act and RCRA, apply to our independent power plants as well as to our coal mining operations. These laws and regulations require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies. Meeting the requirements of each jurisdiction with authority over a project can delay or sometimes prevent the completion of a proposed project, as well as require extensive modifications to existing projects. The operators of the ROVA and Fort Lupton Projects are responsible for obtaining the required permits and complying with the relevant environmental laws.
On December 17, 1999, the EPA issued regulations under Section 126 of the Clean Air Act (the “Section 126 rule”) calling for combined nitrogen oxide reductions of 510,000 tons during each annual ozone season (May 1 – September 30) from certain named power stations in the Eastern U.S., including the ROVA Project. The additional nitrogen oxide reductions began in 2003, but in North Carolina compliance begins in June 2004. The rule responds to petitions filed by several northeastern states under Section 126 of the Clean Air Act and seeks to control nitrogen oxide emissions that the petitioning states allege prevent them from attaining the ambient air quality standards for ozone. Each source is assigned an emissions allocation.
At this time, the ROVA Project is evaluating strategies for complying with the Section 126 rule. In 2000, the ROVA Project installed neural networks in its boilers. The neural network increases boiler efficiency and reduces nitrogen oxide and carbon monoxide emissions. While the neural network reduces the level of nitrogen oxide and carbon monoxide emissions from the ROVA Project, the project operator is evaluating additional compliance strategies, including installation of additional pollution control equipment and emission trading.
Including our subsidiaries, we directly employed 919 people on December 31, 2003, compared with 882 people on December 31, 2002. We hired more employees in 2003 in order to increase production from the Rosebud Mine. 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.
Please refer to Note 13 of the Consolidated Financial Statements for additional information about the segments of our business.
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Our Internet address is www.westmoreland.com. We do not intend for the information on our website to constitute part of this report. We make available, free of charge on or through our Internet website, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (“Exchange Act”), as soon as reasonably practicable after we file those materials electronically with, or furnish them to, the Securities and Exchange Commission.
| ITEM 2 - | 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. We include in “coal reserves” 162 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 that process above in Item 1, under “Governmental Regulation,” and we explain our assessment of that process as applied to these 162 million tons below. A “coal deposit” is a coal bearing body, which has been appropriately sampled and analyzed in trenches, outcrops, and drilling to support sufficient tonnage and grade to warrant further exploration work. This coal does not qualify as a “coal reserve” until, among other things, we conduct a final comprehensive evaluation based upon unit cost per ton, recoverability, and other material factors and conclude that it is legally and economically feasible to mine the coal.
All of our final reclamation obligations are secured by bonds as required by the respective state agencies. Payment of the actual cost of the major portion of final reclamation is the responsibility of third parties. Contemporaneous reclamation activities are performed at each mine in the normal course of operations and coal production.
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The following table provides information about our mines as of December 31, 2003.
| Absaloka Mine |
Rosebud Mine |
Jewett Mine |
Beulah Mine |
Savage Mine |
|
| Owned by | Westmoreland Resources, Inc. | Western Energy Company | Northwestern Resources Co. | Dakota Westmoreland Corporation | Westmoreland Savage Corporation |
| Location | Big Horn County, MT | Rosebud and Treasure Counties, MT | Leon, Freestone and Limestone Counties, TX | Mercer and Oliver Counties, ND | Richland County, MT |
| Coal Reserves (thousands of tons) Proven (1) Probable (3) |
53,586(2) 0 |
233,841(2) 0 |
99,859 0 |
40,471(2) 3,815 |
12,900(2) 4,008 |
| Permitted Reserves (thousands of tons) |
28,000 | 154,941 | 99,859 | 6,000 | 4,300 |
| Coal Deposits (thousands of tons)(4) |
576,584 | 280,000 | 0 | 0 | 0 |
| 2003 Production (thousands of tons) |
6,016 | 11,003 | 7,462 | 2,816 | 379 |
| Lessor | Crow Tribe | Federal Govt; State of MT; Great Northern Properties |
Private parties | Private parties; State of ND; Federal Govt |
Federal Govt; Private parties |
| Lease Term | Through exhaustion | varies | varies | 2009-2019 | varies |
| Curent production capacity (millions of tons) |
7 | 12 | 7 | 4 | 0.4 |
| Coal Type | Sub-bituminous | Sub-bituminous | Lignite | Lignite | Lignite |
| Acres disturbed by mining | 3,520 | 14,652 | 13,250 | 4,221 | 503 |
| Acres for which reclamation is complete | 2,400 | 6,782 | 8,816 | 2,849 | 209 |
| Major Customers | Xcel Energy, Western Fuels Assoc., Midwest Energy | PPL Montana, Puget Sound, Portland General, Avista, Pacificorp, Minnesota Power | Texas Genco | Otter Tail, MDU, Minnkota, Northwestern Public Service | MDU, Sidney Sugars |
| Delivery Method | Rail | Truck / Rail / Conveyor | Conveyor | Conveyor / Rail | Truck |
| Approx. Heat Content (BTU/lb.) (5) |
8,700 | 8,529 | 6,670 | 7,000 | 6,371 |
| Approx. Sulfur Content (%) (6) |
0.63 | 0.74 | 1.00 | 1.00 | 0.45 |
| Year Opened | 1974 | 1975(7) | 1985 | 1963 | 1958 |
| Total Tons Mined Since Inception (million of tons) |
127.8 | 346 | 141 | 79 | 12 |
| (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. |
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| (2) | Includes tons for each mine as described below that are not fully permitted but otherwise meet the definition of "proven" coal reserves. |
| (3) | Probable reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation. |
| (4) | We have assigned all coal deposits to operating mining equipment and plant facilities. |
| (5) | Approximate heat content applies to the coal mined in 2003. |
| (6) | Approximate sulfur content applies to the tons mined in 2003. |
| (7) | Initial sales from the current mine complex began in 1975. Mining first occurred at the site in 1924. |
We lease all our coal properties except at the Jewett Mine, where some reserves are controlled through fee ownership. We believe that we have satisfied all conditions that we must meet in order to retain the properties and keep the leases in force.
Our Westmoreland Resources subsidiary began constructing the mine in late 1972. Construction was completed in early 1974. Westmoreland Resources has been the mine’s only owner.
The Absaloka Mine’s primary excavating machine (completed in 1979) is a dragline with a bucket capacity of 110 cubic yards. Westmoreland Resources owns the dragline. The Absaloka Mine’s facilities consist of a truck dump, primary and secondary crushers, conveyors, coal storage barn, train loadout, rail loop, shop, warehouse, boiler house, deep well and water treatment plant, and other support facilities. These facilities date from the construction of the mine. Westmoreland Resources’ mining contractor and minority stockholder owns most of the other equipment at the mine.
We believe that all the coal reserves and coal deposits shown in the table above for the Absaloka Mine are recoverable through the Absaloka Mine’s existing facilities with current technology and the existing infrastructure. These reserves and deposits were estimated to be 799.8 million tons as of January 1, 1980, based principally upon a report by Intrasearch, Inc., an independent firm of consulting geologists, prepared in February 1980.
Westmoreland Resources leases all of its remaining coal reserves and coal deposits from the Crow Tribe of Indians. The lease runs until exhaustion of the mineable and merchantable coal in the acreage subject to the lease. In February 2004, Westmoreland Resources reached an agreement with the Crow Tribe to explore and develop additional acreage located on the Crow reservation immediately adjacent to the Absaloka Mine.
Washington Group is contractually responsible for reclaiming the Absaloka Mine, whatever the cost, except for $1.7 million, which is the responsibility of Westmoreland Resources and is being funded through annual installments of $113,000 through 2005. Washington Group is also contractually obligated to fund a reclamation escrow account or post security for its reclamation obligation. After reclamation is complete, Westmoreland Resources is responsible for maintaining and monitoring the reclaimed property until the release of the reclamation bond. For the property mined through December 31, 2003, Westmoreland Resources’ estimated future cost of maintaining and monitoring the property until bond release is $1.5 million.
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Of the 53.6 million tons shown for the Absaloka Mine in the table above as proven coal reserves, 25.6 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” Westmoreland Resources has chosen not to obtain permits for all of the coal reserves in its current mine plan because it already has sufficient permitted coal to meet production, given the current rate of mining and demand, through 2007. In Montana, the Department of Environmental Quality 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. We anticipate that Westmoreland Resources will file an application covering an estimated 25 million tons of unpermitted reserves in the first half of 2004. We do not believe additional exploration or development of this area is necessary for Westmoreland Resources to obtain the necessary permits. Based upon our current knowledge of the permitting process in Montana and the nature of the Absaloka Mine’s reserves, we believe that there are no matters that would hinder Westmoreland Resources’ ability to obtain this mining permit on a timely basis.
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.
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 to operate the Rosebud Mine with initial sales to the Corette Station in 1968. Construction of Colstrip Station began in 1975. The long-term contracts required for this plant provided the foundation for a major expansion of the Rosebud Mine. We acquired the stock of Western Energy in 2001.
The Rosebud Mine’s primary excavating machines are four draglines, three with bucket-capacities of 60 cubic yards, purchased in 1975, 1976, and 1980, and one with a bucket-capacity of 80 cubic yards, purchased in 1983. The Rosebud Mine’s facilities consist of truck dumps, crushing, storage, and conveying systems, a rail loadout, rail loop, shops, warehouses, and other support facilities. These facilities date from 1974.
We estimate that the Rosebud Mine had coal reserves of 233.8 million tons as of December 31, 2003. This estimate is based on a study of the Rosebud Mine’s reserves dated October 31, 2003 conducted by Western Energy and adjusted for production since that date. We estimate that the Rosebud Mine had coal deposits of approximately 280 million tons at the end of 2003. This estimate is based on a study of the reserves at the Rosebud Mine dated September 28, 1994, prepared by the Environmental and Engineering Department of Western Energy while it was owned by Montana Power. This study was updated by Rosebud engineering in 2003. Our estimate is also based in part on a lease with the U.S. Department of the Interior that Western Energy obtained in 1999. We believe that all of these reserves are recoverable through the Rosebud Mine’s existing facilities with current technology and the existing infrastructure.
We are responsible for reclaiming the Rosebud Mine. The owners of the Colstrip Station are responsible for paying the costs of reclamation relating to mine areas where its coal supply is produced, which is approximately 63% of the estimated total cost of final reclamation for the Rosebud Mine. Certain owners have satisfied these obligations by prefunding their respective portions of those costs.
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Of the 233.8 million tons shown for the Rosebud Mine in the table above as proven coal reserves, 78.9 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” Western Energy has chosen not to permit all of the coal reserves in its mine plan because it already has sufficient coal in its current permitted mine plan, given the current rate of mining and demand for its production, through 2013. Based upon our current knowledge of the nature of the remaining reserves and the permitting process in Montana, we believe that there are no matters that would hinder Western Energy’s ability to obtain additional mining permits in the future.
The Rosebud Mine purchases electric power from NorthWestern Energy under regulated default supply pricing. Access to the mine is from Highway 39 via Castle Rock Road.
Development of the Jewett Mine began in 1979, when Northwestern Resources and Utility Fuels, Inc. signed an agreement calling for production of “the most economic 240 million tons” from the project area to supply the planned Limestone Station. The coal deposit was evaluated through a series of exploration programs, including physical and chemical analysis, according to predetermined criteria. The Jewett Mine has been in continuous operation since 1985 and consists of five active areas with as many as four lignite seams within each area. Since 1979, ownership of the Limestone Station has been transferred several times, most recently to Texas Genco. We acquired the stock of Northwestern Resources in 2001.
The Jewett Mine’s primary excavating machines consist of three walking draglines, each with a bucket-capacity of 84 cubic yards, one walking dragline with a bucket-capacity of 128 cubic yards, and one bucketwheel excavator. The Jewett Mine’s facilities consist of a truck dump, crusher, conveyors, coal storage, shop/warehouse complex, administrative support buildings, and water treatment facilities. These facilities date from the construction of the mine. Texas Genco owns the draglines, the bucketwheel and other mobile equipment used to extract lignite and provides this equipment to Northwestern Resources without charge. Northwestern Resources 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 Northwestern Resources’ geologists and engineers prepared the initial estimates of the mine’s reserves at a time when Montana Power owned Northwestern Resources. To further define the coal reserve, exploration drilling was utilized to delineate that part of the deposit that could economically be mined. Additional drilling has been conducted from time to time to further define the limits of the coal seams. As of December 31, 2003, all planned exploration is complete. We believe that all the Jewett Mine’s coal reserves are recoverable through its existing facilities with current technology and the existing infrastructure.
Final reclamation of the Jewett Mine, at the end of its useful life, is the financial responsibility of its customer.
The Railroad Commission of Texas, or RCT, regulates surface mining in Texas and issues mining permits under its OSM-approved program. In Texas, it typically takes eighteen months to two years from the time an initial application is filed to obtain a new permit. A permit term encompasses five years of mining. The Jewett Mine currently holds two mining permits that cover 100% of the proven coal reserves in the table above. Permit 32E is a renewal of the same general permit that has been in place and actively mined since 1985. Permit 32E expired in July 2003; however, the RCT allowed the Jewett Mine to continue to operate pending a decision on our application to renew that permit. We submitted an application to renew this permit to the RCT in the first quarter of 2002. The renewal term will be from the date of the RCT approval through July 2008, and we do not expect the RCT’s delay in renewing the permit prior to July 2003 to affect the mine’s operations. The final review and approval of the Permit 32E renewal is ongoing and is expected to be approved in the first quarter of 2004. Based on our current knowledge of the permitting process in Texas and the nature of these reserves, we believe that there are no matters that would hinder Northwestern Resources’ ability to obtain this permit. Permit 47 is a new permit. The current term for Permit 47 is December 2001 through December 2006.
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The Jewett Mine purchases electric power from the Brazos River Authority and Navasota Valley Electric Cooperative. The mine may be accessed on Farm to Market Road 39.
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.
The Beulah Mine’s primary excavating machines are a dragline with a bucket-capacity of 17 cubic yards, constructed in 1963, which operates in the West Brush Creek area, and a dragline with a bucket-capacity of 84 cubic yards, constructed in 1980, which removes overburden at East Beulah. The Beulah Mine’s facilities consist of a truck dump hopper, primary and secondary crushers, conveyors, train loadout, railroad spur, coal storage bin, and coal stockpile. The support facilities include several maintenance shops, equipment storage buildings, warehouse, employee change houses, and mine office and trailers. These facilities date from 1963 and have been replaced consistent with normal industry practices.
We estimate that the total owned and leased coal reserves at the Beulah Mine were approximately 44.3 million tons at December 31, 2003. 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 44.3 million tons shown for the Beulah Mine in the table above as proven and probable coal reserves, 34.5 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” Of the total reserves shown, approximately 3.5 million tons in the West Brush Creek area and 2.5 million tons at East Beulah are fully permitted at this time. Based on the current estimated production rates of 500,000 and 2.5 million tons respectively, there are roughly seven and one years, respectively, remaining under the current permitted mine plans. The mine is currently awaiting approval of a permit extension that will add six years and 700 acres of permitted reserves to the East Beulah permit. 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.
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Knife River began producing lignite at the Savage Mine in 1958. We purchased the assets of the Savage Mine from Knife River in 2001.
The Savage Mine’s primary excavating machine is a walking dragline with a bucket-capacity of 12 cubic yards. The Savage Mine’s facilities consist of a truck dump, near-pit crushing unit, conveyors, and coal stockpile; support facilities include a shop, warehouse, and mine office. These facilities date from 1958 and have been replaced consistent with normal industry practices. The processing facilities were constructed in 1996. The facilities were modified and upgraded in 2001.
We estimate that the total owned and leased coal reserves at the Savage Mine were approximately 16.9 million tons at December 31, 2003. These reserves were estimated as of January 1, 1999, based principally upon a report prepared by Weir International Mining Consultants, an independent consulting firm, and updated by our engineering staff in 2003. 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 4.3 million tons are fully permitted at this time and 12.6 million tons are not fully permitted but otherwise meet the definition of “coal reserves.” We have chosen not to permit all of the coal reserves in the Savage Mine’s plan because the mine already has sufficient coal in its current permitted mine plan given the current rate of mining and demand for its production through 2017. 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.
Refer to Note 3 to Consolidated Financial Statements for a description of Westmoreland Energy’s properties.
| ITEM 3 - | LEGAL PROCEEDINGS |
We are party to legal proceedings. We have presented the proceedings below based on the name of the Westmoreland entity that is party to the proceeding. We are vigorously contesting each of these proceedings.
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| 1974 Plan Arbitration | |||||
One element of the Company’s heritage health benefit costs is pensions under the 1974 UMWA Retirement Plan (“1974 Plan”). The 1974 Plan is a multiemployer plan under ERISA. Under ERISA, a company that withdraws is liable for its share of the plan’s unfunded liabilities as of the date of withdrawal. We terminated our last covered employee in July 1998 and the 1974 Plan asserted a withdrawal liability claim of $13.8 million against us which ERISA permits to be paid over a period of years with interest. We believed the claim was erroneous and arbitrated. ERISA requires a withdrawing company to pay its withdrawal liability while it contests any liability determinations. We began paying monthly installments of $172,000 (principle and interest) in October 2000 and would have continued to make these payments through September 2007. On March 8, 2004 the 1974 Plan and the Company agreed to settle the pending arbitration based on payment of $7.5 million of the claimed due amount of $13.8 million plus the $4.8 million in interest paid. As a result of the settlement the Company reversed the remaining accrued withdrawal liability of $6.3 million and recognized it as income. In addition, the Company avoids paying approximately $2.1 million annually for the next three years to the 1974 Plan.
| Combined Benefit Fund Litigation | |||||
Under the Coal Act, we are required to provide postretirement medical benefits for certain UMWA miners and their dependents by making premium payments into the benefit plans, including the UMWA Combined Benefit Fund. The amount we pay is a function of the number of individuals for which we must make payment – “assigned beneficiaries” – and the assessment rate. We and many other coal companies are now litigating in the U.S. District Court for the District of Maryland to determine the proper assessment rate.
In 1995, the U.S. District Court for the Northern District of Alabama held that the assessment rate under the Coal Act included the actual amount of money reimbursed to the UMWA Benefit Plans by the Health Care Financing Administration (“HCFA”). The Court’s decision resulted in a lower premium obligation. In 1996, the U.S. Court of Appeals for the 11th Circuit upheld the district court’s decision. The Social Security Administration (“SSA”), which now makes these assessments, proceeded to comply with the decision and applied the assessment which yielded a lower premium to all coal companies.
In 1996, the Trustees of the Combined Fund filed suit in the U.S. District Court for the District of Columbia seeking to have the Alabama decision set aside. In November 2002, the U.S. District Court held that the provisions of the Coal Act that the Alabama court had reviewed were ambiguous and directed the SSA to explain why it had applied the Alabama decision to all coal companies, rather than just the participants in the Alabama litigation. On June 10, 2003, the SSA notified the Court that it could not locate any record that would explain why it decided to apply the 1996 Alabama decision nationwide but assumed that decision was based on fairness and ease of administration for the SSA. After the June 10th letter, the SSA began to use the methodology that resulted in higher assessments for all coal companies except those party to the Alabama litigation. The Trustees of the Combined Fund notified us that we would be subject to higher premiums and assessed a “retroactive premium” that represented the amount that we would have paid if the methodology that yields the higher premium had been used since 1996. The amount of the retroactive premium was $4.7 million, payable over the twelve months commencing October 2003. The net effect of these assessments increased our monthly payments to the Combined Fund from less than $400,000 to $859,000 for the twelve months ending October 2004.
On July 16, 2003, we and other companies with obligations to the Combined Fund filed a complaint in the U.S. District Court for the Northern District of Alabama which sought to prevent the increased assessment and retroactive assessment from taking effect. On September 10, the Trustees of the Combined Fund filed suit in the U.S. District Court for the District of Columbia. The Trustees sought to confirm that all coal companies not party to the 1996 Alabama litigation are obligated to pay the newly calculated, higher premium, as determined by the SSA on June 10, 2003.
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The Trustees of the Combined Fund sought to transfer the Alabama litigation to the District of Columbia. In October 2003, the U.S. District Court for the Northern District of Alabama held that venue was proper in Alabama but transferred the case to the U.S. District Court in Baltimore, Maryland, where the SSA is headquartered. In February 2004, the U.S. District Court for the District of Columbia transferred the Trustees’ suit to Baltimore.
| Purchase Price Adjustment | |||||
We purchased Montana Power’s coal business from its subsidiary Entech in April 2001. The final purchase price is subject to adjustment. Under our Stock Purchase Agreement with Entech, the purchase price is to be adjusted as of the date the transaction closed, to reflect the net assets of the business on the closing date and the net revenues that the business earned between January 1, 2001 and the closing date. In June 2001, Entech proposed adjustments that would increase the purchase price by approximately $9.0 million. In July 2001, we objected to Entech’s adjustments and proposed our own adjustments. Our proposal would result in a substantial decrease in the purchase price. The Stock Purchase Agreement requires that the parties’ disagreements be submitted to an independent accountant for resolution. Because some of our claims involved breaches of the representations and warranties in the Stock Purchase Agreement, we also submitted a timely claim for indemnification.
Litigation in the New York courts ensued. On June 18, 2003, Touch America Holdings, Inc. (formerly Montana Power Company) and Entech LLC (formerly Entech Inc.) filed bankruptcy petitions in the U.S. Bankruptcy Court in Delaware. The bankruptcy code automatically stays pending litigation against Montana Power and Entech and prevents us and others from commencing new actions against them outside the Bankruptcy Court. As a result, the purchase price adjustment litigation is now stayed.
We have filed appropriate proofs of claim with the Bankruptcy Court. We are also evaluating our options, which include (1) seeking relief from the stay, so that we can continue to pursue the purchase price adjustment claim through the independent accountant and in an action at law in the New York courts, and (2) seeking to resolve our claims as part of the bankruptcy proceeding.
| McGreevey Litigation | |||||
In mid-November, 2002, we were served with a complaint – the plaintiffs’ Fourth Amended Complaint – in a case styled McGreevey et al. v. Montana Power Company et al. The complaint was filed on October 4, 2002 in a Montana State court. The plaintiffs filed their first complaint on August 16, 2001. The Fourth Amended Complaint added us as a defendant to a shareholder suit against Montana Power, various officers of Montana Power, the Board of Directors of Montana Power, financial advisors and lawyers representing Montana Power, and the purchasers of some of the businesses formerly owned by Montana Power and Entech. The plaintiffs seek to rescind Montana Power’s sale of its generating, oil and gas, and transmission businesses, and Entech’s sale of its coal business. The Montana Power shareholders contend that they were entitled to vote to approve the sale by Entech to the Company even though they were not shareholders of Entech. Alternatively, they seek to compel the purchasers, including us, to hold these businesses in trust for them. We have filed an answer, affirmative defenses, and a counterclaim against the plaintiffs.
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The litigation has been transferred to the U.S. District Court in Billings, Montana. In December 2003, Montana Power and Entech sought to enforce the bankruptcy code’s automatic stay against the McGreevey plaintiffs. The plaintiffs have consented to a stay of the McGreevey litigation for approximately four months.
The ROVA Project is located in Halifax County, North Carolina and is the County’s largest taxpayer. In 2002, the County hired an independent consultant to review and audit property tax returns for the previous five years. In May 2002, the County advised the ROVA Project that its returns were being scrutinized for potential underpayment and undervaluation of the property subject to tax. The ROVA Project responded that its valuation was consistent with an agreement reached with the County in 1996. On November 5, 2002, the County assessed the ROVA Project $4.6 million for the years 1997 to 2001. The ROVA Project filed a protest. Since that date the County has increased the amount of its claim to $5.3 million, which includes tax years 1996, 2002 and 2003. With penalty and interest, the total amount claimed due by the County is $8.3 million. The ROVA Project Partnership believes its position is meritorious however, it is impossible to predict the outcome. In addition to the amounts assessed, the ROVA Project’s future taxes would increase approximately $600,000 per year, of which Westmoreland Energy could be responsible for up to half.
Niagara Mohawk Power Corporation (“NIMO”) was party to power purchase agreements with independent power producers, including the Rensselaer project, in which we owned an interest. In 1997, the New York Public Service Commission approved NIMO’s plan to terminate or restructure 29 power purchase contracts. The Rensselaer project agreed to terminate its Power Purchase and Supply Agreement after NIMO threatened to seize the project under its power of eminent domain. NIMO and the Rensselaer project executed a settlement agreement in 1998. On February 11, 2003, the North Carolina Department of Revenue notified us that it had disallowed the exclusion of gain from the settlement agreement between NIMO and the Rensselaer project. The State of North Carolina has assessed a current tax of $3.5 million, interest of $1.0 million, and a penalty of $0.9 million. We have filed a protest. The North Carolina Department of Revenue held a hearing on May 28, 2003. In November 2003, we submitted further documentation to the State to support our position and are awaiting their response.
| UMWA Benefits | |||||
Basin Resources, Inc. was a subsidiary of Entech. Until 1995, Basin operated the Golden Eagle mine near Trinidad, Colorado. Basin’s workforce was represented by the UMWA. Basin signed a Basin-specific labor contract with the UMWA in 1993 that expired on January 1, 1998. A group of Basin’s former employees filed suit against the company in the U.S. District Court for the District of Colorado on April 21, 1998. They claimed that they were entitled to lifetime health benefits. Basin argued that, when the contract expired, it was not obligated to continue to provide health benefits. In April 1999, the trial judge granted the former employees’ motion for summary judgment and ordered Basin to reinstate its former health plan and pay covered medical costs incurred by the UMWA and Basin’s former employees. Basin appealed the District Court’s decision to the U.S. Court of Appeals for the Tenth Circuit. We acquired Basin’s stock from Entech in April 2001, after the preceding events had occurred, and we accrued an estimated obligation for Basin’s liabilities as part of our accounting for the 2001 acquisitions.
23
In September 2002, the Court of Appeals reversed the trial court’s award of summary judgment and remanded the matter for trial. The trial took place on January 21, 2003 and on January 23, 2003, a jury decided that the UMWA work force had bargained for and Basin had agreed to provide lifetime health benefits. We have appealed this decision to U.S. Court of the Appeals for the Tenth Circuit.
| Landowner Claim | |||||
In 1998, Basin paid a landowner $48,000 to settle a claim that Basin’s operations had caused subsidence that damaged his home. On March 22, 2001, the landowner filed a second claim, in Las Animas County Court, Colorado, again alleging that Basin’s operations had caused subsidence that damaged his home. Basin contested this claim. In December 2002, a judge of that court determined that subsidence had occurred and awarded the landowner damages of $622,000 plus attorney’s fees. We believe that this award is excessive, in part because the landowner’s own expert placed the cost of repair below $100,000. We also believe that the settlement in the first case bars the second claim. We have appealed the case to the Colorado Intermediate Court of Appeals.
We have received demand letters from the Montana Department of Revenue, as agent for the Minerals Management Service (“MMS”) of the U.S. Department of the Interior, asserting underpayment of royalties allegedly due at the Rosebud Mine. The claims relate to the fees Western Energy receives to transport coal from the contract delivery point to the customer. The DOR has also asserted claims against us based on certain “take or pay” payments Western Energy received when its customers did not require coal. Finally, the DOR has asserted claims against us and our subsidiaries for adjustments for Montana severance taxes, coal resources indemnity trust tax, and coal gross proceeds tax. These assessments are dated September 23 and 24, 2002. The total amount of the claims is approximately $15.5 million, including penalties and interest, which continues to accrue. We continue to receive transportation fees. We expect that the DOR will assert claims for additional underpayment and issue more demand letters until we have completed the appeal process. The appeal process will take several years. In the event of a negative outcome with the DOR and MMS, we believe that certain of our customers are contractually obligated to reimburse us for any claims we pay, plus our legal expenses and we have put them on notice of their obligation.
The MMS also asserted claims that certain fees paid by a customer to Westmoreland Resources to dedicate a coal reserve for its use were part of the price of coal and subject to royalty payments. Westmoreland Resources contested the assessment but, in the process of negotiating the option to acquire additional coal reserves, agreed to pay $1.5 million to settle this claim.
Northwestern Resources and Texas Genco have at various times disputed the interpretation of certain terms of the ALSA. On May 6, 2003, Northwestern Resources filed suit in the District Court of Limestone County, Texas, seeking damages for Texas Genco’s failure to take delivery of lignite in 2002 and for Texas Genco’s purchases of Powder River Basin coal without giving Northwestern Resources its contractual rights of first refusal to supply the Limestone Station. Other claims for damages and prayers for contract interpretation were asserted in the litigation. Also on May 6, 2003, Texas Genco filed a complaint against Northwestern Resources in the District Court of Harris County, Texas, seeking payment of disputed royalties, alleging that it was owed a management fee under the old Lignite Supply Agreement, and requesting a declaratory judgment regarding the interpretation of certain provisions of the ALSA. On January 30, 2004, Northwestern Resources and Texas Genco reached an agreement which resolved these disputes, and agreed to price and tonnage through 2007. The litigation has been dismissed.
24
We and our subsidiaries are party to other legal proceedings that are either not material or not out of the ordinary course of business.
| 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 2003.
25
The following table shows the executive officers of the Company, their ages as of March 1, 2004, positions held and year of election to their present offices. No family relationships exist among them. All of the officers are elected annually by the Board of Directors and serve at the pleasure of the Board of Directors.
| Name | Age | Position | Held Since | |
| Christopher K. Seglem (1) | 57 | Chairman of the Board, | 1996 | |
| President and | 1992 | |||
| Chief Executive Officer | 1993 | |||
| W. Michael Lepchitz (2) | 50 | Vice President, General Counsel | 2000 | |
| and Secretary | 2001 | |||
| Ronald H. Beck (3) | 59 | Vice President - Finance and Treasurer, | 2001 | |
| Acting Chief Financial Officer | ||||
| Thomas G. Durham (4) | 55 | Vice President, Coal Operations | 2000 | |
| Todd A. Myers (5) | 40 | Vice President, Sales and Marketing | 2000 | |
| Douglas P. Kathol (6) | 51 | Vice President, Development | 2003 | |
| (1) | Mr. Seglem was elected President and Chief Operating Officer in June 1992, and a Director of Westmoreland in December 1992. In June 1993, he was elected Chief Executive Officer, at which time he relinquished the position of Chief Operating Officer. In June 1996, he was elected Chairman of the Board. He is a member of the bar of Pennsylvania. |
| (2) | Mr. Lepchitz joined Westmoreland in 1991 as Assistant General Counsel. He was named General Counsel of Westmoreland Energy, Inc. (the predecessor of Westmoreland Energy, LLC) in 1995 and became President of Westmoreland Energy in 1997. In June 2000, Mr. Lepchitz was elected Vice President and General Counsel of Westmoreland Coal Company. In May 2001, he became Corporate Secretary of Westmoreland. He is a member of the bar of Virginia. |
| (3) | Mr. Beck joined Westmoreland in July 2001 as Vice President - Finance and Treasurer. In September 2003, Mr. Beck also began serving as Acting Chief Financial Officer. Prior to joining Westmoreland he was a financial officer at Columbus Energy Corp. from 1985 to 2000, lastly as Vice President and Chief Financial Officer. |
| (4) | Mr. Durham joined Westmoreland as Vice President, Coal Operations in April 2000. For the four years prior to joining Westmoreland, he was a Vice President of NorWest Mine Services, Inc. which provides worldwide consulting services on surface mining and other projects. Mr. Durham has 30 years of surface mine management and operations experience with various mining companies. He became a registered professional engineer in 1976. |
| (5) | Mr. Myers re-joined Westmoreland in January 2000 as Vice President Marketing and Business Development and in 2002 became Vice President Sales and Marketing. He originally joined Westmoreland in 1989 as a Market Analyst and was promoted in 1991 to Manager of the Contract Administration Department. He left Westmoreland in 1994. Between 1994 and 2000, he was Senior Consultant and Manager of the Environmental Consulting Group of a nationally recognized energy consulting firm, specializing in coal markets, independent power development, and environmental regulation. |
| (6) | Mr. Kathol joined Westmoreland in August of 2003 as Vice President, Development. Prior to joining Westmoreland, Mr. Kathol was Senior Vice President and principal with Norwest Corporation (1985 to 2003) a firm that provides worldwide consulting services to the mining and energy industries. Mr. Kathol has held senior financial positions with other mining companies. |
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| ITEM 5 - | MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS |
The following table shows the range of sales prices for the Company’s common stock, par value $2.50 per share (the “Common Stock”), and depositary shares, each representing one quarter of a share of the Company’s Series A Convertible Exchangeable Preferred Stock, $1.00 par value per preferred share (the “Depositary Shares”) for the past two years.
The Common Stock and Depositary Shares are listed for trading on the American Stock Exchange (“AMEX”) and the sales prices below were reported by the AMEX.
| Sales Prices | ||||
| Common Stock | Depositary Shares | |||
| High | Low | High | Low | |
| 2002 | ||||
| First Quarter | $ 15.49 | $ 10.80 | $ 34.00 | $ 28.06 |
| Second Quarter | 16.44 | 12.25 | 36.99 | 32.50 |
| Third Quarter | 13.55 | 8.30 | 35.50 | 28.00 |
| Fourth Quarter | 12.85 | 10.00 | 34.00 | 31.00 |
| 2003 | ||||
| First Quarter | 13.70 | 10.00 | 32.50 | 30.00 |
| Second Quarter | 19.53 | 13.41 | 39.00 | 30.00 |
| Third Quarter | 18.19 | 13.81 | 38.75 | 34.00 |
| Fourth Quarter | 18.25 | 13.29 | 38.50 | 32.00 |
| Number of Holders of Record | |
| Title of Class | (as of December 31, 2003) |
| Common Stock ($2.50 par value) | 1,500 |
| Depositary Shares, each representing | |
| one-quarter share of a share of Series A | |
| Convertible Exchangeable Preferred | |
| Stock | 20 |
We issued the depositary shares on July 19, 1992. Each depositary share represents on-quarter of a share of our Series A Convertible Exchangeable Preferred Stock. We paid quarterly dividends on the depositary shares until the third quarter of 1995, when we suspended dividend payments pursuant to the requirements of Delaware law, described below. We resumed dividends to preferred shareholders on October 1, 2002 as described below. The quarterly dividends which are accumulated through and including January 1, 2004 amount to $15.3 million in the aggregate ($74.62 per preferred share or $18.65 per depositary share). We cannot pay dividends on our common stock until we pay the accumulated preferred dividends in full.
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There are statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which we are incorporated. Under Delaware law, we are permitted to pay preferred stock dividends only: (1) out of surplus, surplus being the amount of shareholders’ equity in excess of the par value of our two classes of stock; or (2) in the event there is no surplus, out of net profits for the fiscal year in which a preferred stock dividend is declared (and/or out of net profits from the preceding fiscal year), but only to the extent that shareholders’ equity exceeds the par value of the preferred stock (which par value was $205,000 at December 31, 2003). We had shareholders’ equity of $26.6 million and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $20.1 million at December 31, 2003.
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 quarterly dividends of $0.15 per depositary share beginning on October 1, 2002, and we increased the dividend to $0.20 per depositary share beginning on October 1, 2003. We have declared a quarterly dividend of $0.20 per depositary share payable on April 1, 2004.
On August 9, 2002, our Board of Directors authorized the repurchase of up to 10% of the outstanding depositary shares on the open market or in privately negotiated transactions with institutional and accredited investors between then and the end of 2004. The timing and amount of depositary shares repurchased will be determined by our management based on its evaluation of our capital resources, the priced of the depositary shares offered to us and other factors. We will convert any acquired depositary shares into shares of Series A Convertible Exchangeable Preferred Stock and retire the preferred shares. We will fund the repurchase program from working capital. Since the commencement of the depositary share purchase program, we have purchased a total of 14,500 depositary shares for an aggregate consideration of $457,000. We have not purchased any depositary shares since the second quarter of 2003.
The successful implementation of the initial phase of our strategic plan returned us to profitability and made it possible for us to pay preferred dividends and purchase depositary shares. These programs reflect our continuing commitment to our preferred shareholders.
Information regarding the Company’s equity compensation plans and the securities authorized for issuance thereunder is incorporated by reference in Item 12 below.
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| ITEM 6 - | SELECTED FINANCIAL DATA |
| 2003 | 2002 | 2001(1) | 2000 | 1999 | ||||||
| (in thousands, except per share data) | ||||||||||
| Consolidated Statements of | ||||||||||
| Operations Information | ||||||||||
| Revenue – Coal | $ | 294,986 | $ | 301,235 | $ | 231,048 | $ | 35,137 | $ | 38,539 |
| – Independent power and other | 15,824 | 14,506 | 15,871 | 32,260 | 34,492 | |||||
| Total revenues | 310,810 | 315,741 | 246,919 | 67,397 | 73,031 | |||||
| Cost and expenses | 303,695 | 296,908 | 233,307 | 60,170 | 62,849 | |||||
| Impairment charges | - | - | - | 4,632 | - | |||||
| Operating income from continuing operations |
7,115 | 18,833 | 13,612 | 2,595 | 10,182 | |||||
| Interest expense | (10,114) | (10,821) | (8,418) | (911) | (1,135) | |||||
| Minority interest | (773) | (800) | (780) | (518) | (854) | |||||
| Interest and other income | 3,121 | 4,128 | 3,229 | 867 | 1,826 | |||||
| Income (loss) before income taxes | ||||||||||
| from continuing operations | (651) | 11,340 | 7,643 | 2,033 | 10,019 | |||||
| Income tax benefit (expense) from continuing operations |
10,971 | 2,368 | (1,228) | (428) | 82 | |||||
| Income from continuing operations | 10,320 | 13,708 | 6,415 | 1,605 | 10,101 | |||||
| Income (loss) from discontinued operations | 2,113 | (3,583) | (1,188) | (1,297) | (1,464) | |||||
| Net income before cumulative effect of | ||||||||||
| change in accounting principle | 12,433 | 10,125 | 5,227 | 308 | 8,637 | |||||
| Cumulative effect of change in | ||||||||||
| accounting principle | 161 | - | - | - | - | |||||
| Net income | 12,594 | 10,125 | 5,227 | 308 | 8,637 | |||||
| Less preferred stock dividend | ||||||||||
| requirements | 1,752 | 1,772 | 1,776 | 1,776 | 2,992 | |||||
| Net income (loss) applicable to | ||||||||||
| common shareholders | $ | 10,842 | $ | 8,353 | $ | 3,451 | $ | (1,468) | $ | 5,645 |
| Net income (loss) per share applicable | ||||||||||
| to common shareholders: | ||||||||||
| Basic | $ | 1.39 | $ | 1.10 | $ | 0.48 | $ | (0.21) | $ | 0.80 |
| Diluted | $ | 1.30 | $ | 1.03 | $ | 0.43 | $ | (0.21) | $ | 0.79 |
| Weighted average number of common | ||||||||||
| shares outstanding: | ||||||||||
| Basic | 7,799 | 7,608 | 7,239 | 7,070 | 7,040 | |||||
| Diluted | 8,338 | 8,147 | 8,000 | 7,070 | 7,146 | |||||
| Balance Sheet Information | ||||||||||
| Working capital (deficit) | $ | 5,555 | $ | 10,143 | $ | 11,346 | $ | (1,557) | $ | 8,886 |
| Net property, plant and equipment | 151,349 | 189,532 | 197,271 | 34,693 | 36,558 | |||||
| Total assets | 457,837 | 471,957 | 466,532 | 139,096 | 142,297 | |||||
| Total debt | 93,469 | 100,157 | 122,910 | - | 1,563 | |||||
| Shareholders’ equity | 33,270 | 18,568 | 10,415 | 3,373 | 3,057 | |||||
| (1) | Effective April 30, 2001, the Company acquired the operating coal business of Montana Power and the coal assets of Knife River Corporation. Refer to Note 2 to the Consolidated Financial Statements for further information. |
29
| ITEM 7 - | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Throughout this Form 10-K, we make statements that are not historical facts or information and that may be deemed “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements include, but are not limited to, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations. For example, words such as “may,” “will,” “should,” “estimates,” “predicts,” “projects,” “potential,” “continue,” “strategy,” “believes,” “anticipates,” “plans,” “expects,” “intends,” and similar expressions are intended to identify forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties and other factors, which may cause our actual results, levels of activity, performance or achievements, or industry results, to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others, the following: general economic and business conditions; health care cost trends; the cost and capacity of the surety bond market; our ability to manage growth and significantly expanded operations; our ability to implement our growth and development strategy; our ability to pay accumulated preferred stock dividends; our ability to retain key senior management; our access to financing; our ability to maintain compliance with debt covenants; our ability to identify new business opportunities; our ability to negotiate new profitable coal contracts and price reopeners and extensions of existing contracts; our ability to maintain satisfactory labor relations; changes in the industry; competition; our ability to utilize our net operating loss carryforwards; our ability to reinvest excess cash at acceptable rates of return; weather conditions; the cost and availability of transportation, including rail transportation; price of fuels other than coal; the cost of coal produced by other countries; the demand for electricity; the effect of regulatory and legal proceedings, including the bankruptcy filing by Touch America Holdings Inc. and Entech Inc.; the claims between the Company and Montana Power; and the other factors discussed in Items 1 and 3 and in this Item 7. As a result of the foregoing and other factors, we can give no assurance as to our future results and achievements. We disclaim any duty to update these statements, even if subsequent events cause our views to change.
| Competitive, economic and industry factors | |||||
We are an energy company. We mine coal, which is used to produce electric power, and we own interests in power-generating plants. We will also begin to earn royalties from the production of coalbed methane gas in 2004. All of our five mines supply baseloaded power plants that comply with all applicable environmental laws, several of these power plants are located adjacent to our mines, and we sell virtually all our coal under long-term contracts. Consequently, our mines enjoy relatively stable demand and pricing compared to competitors who sell more of their production on the spot market.
In partnership with others, we have successfully developed eight independent power projects totaling 866MW of generating capacity. We have sold our interests in five of those projects. We currently own a 50% interest in the ROVA I and II coal-fired plants, which have a total generating capacity of 230MW. We also retain a 4.49% interest in the Fort Lupton Project, which provides peaking power to the local utility. The ROVA Project, which accounted for 96% of our equity in earnings from independent power in 2003, is baseloaded and supplies power pursuant to a long-term contract.
30
While the use of gas for electric power generation has grown in recent years, coal provides approximately 52% of the electricity generated in this country and we expect demand for power to grow at approximately 1% per year. Consequently, we believe demand for our products will grow.
| Sources and uses of revenue and cash | |||||
In 2003, approximately two-thirds of our operating income came from coal operations, and one-third came from independent power projects. The principal uses of revenue were the cost of coal sales, heritage health benefit costs, and selling, general and administrative expenses.
In 2001, in order to finance the purchase of the Rosebud, Jewett, Beulah, and Savage Mines, Westmoreland Mining borrowed $120 million from institutional lenders under a term loan agreement. By the end of 2003, Westmoreland Mining had repaid $31.5 million of that $120 million and deposited an additional $17.4 million into two restricted accounts for the benefit of its lenders. In early March 2004, Westmoreland Mining made arrangements to borrow an additional $35 million from the lenders pursuant to what we call the “add-on” facility. The $20.4 million fixed-rate Series C was drawn immediately and the additional $14.6 million floating rate Series D must be drawn before the end of 2004. The add-on facility will permit Westmoreland Mining to undertake certain significant capital projects in the near term without adversely affecting cash available to the parent.
We may also seek additional equity in 2004 for these purposes.
| Challenges | |||||
Our five principal challenges today are:
| • | inflation in medical costs, which can increase our expense for active employees and heritage health benefit costs; | ||||
| • | bonding issues; | ||||
| • | transitioning from an approach that maximizes the use of our net operating loss carryforwards to one that considers the impact of the alternative minimum tax; | ||||
| • | managing the costs of our operations; and | ||||
| • | addressing the claims for potential taxes asserted by various governmental entities. | ||||
We discuss these issues, as well as the other challenges we face, elsewhere in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, including under “Trends and Uncertainties.”
31
We remain committed to meeting our obligation for accumulated dividends to preferred shareholders. As of January 1, 2004, $15.3 million has accumulated. Dividends of $0.20 per depositary share per quarter are now being paid. The accumulated amount will continue to increase until quarterly dividends of $0.53 per depositary share are paid in full.
Our discussion and analysis of financial condition, results of operations, liquidity and capital resources is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require that we make estimates and judgments. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. Actual results may differ materially from these estimates.
We have made significant judgments and estimates in connection with the following accounting matters. Our senior management has discussed the development, selection and disclosure of the accounting estimates in the section below with the Audit Committee of our Board of Directors.
In connection with our discussion of these critical accounting matters, and in order to reduce repetition, we also use this section to present information related to these judgments and estimates.
| Postretirement Benefits and Pension Obligations | |||||
Our most significant long-term obligation is the obligation to provide postretirement medical benefits, pension benefits, workers’ compensation and pneumoconiosis (black lung) benefits. We provide these benefits to our current and former employees and their dependents.
| Estimates and Judgments | |||||
We estimate the total amount of these obligations with the help of third party professionals using actuarial assumptions and information. Our estimate is sensitive to judgments we make about the discount rate, about the rate of inflation in medical care, about mortality rates, and about the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the “Medicare Reform Act”). We review these estimates and obligations at least annually.
We pay these obligations currently and will in the future although presumably at an eventually declining rate determined by the number of people covered. Under generally accepted accounting principles, we are required to estimate the present value of these obligations. In order to do this, we make a judgment about the discount rate, which is an estimate about the current interest rate at which these obligations could be effectively settled on the date we estimate them. The discount rate used to calculate the present value of these future obligations was 7.25% in 2001, 6.75% in 2002, and 6.25% in 2003. Significant changes to interest rates result in substantial volatility to our financial statements by influencing our estimate of these amounts.
In order to estimate the total cost of our obligation to provide medical benefits, we must make a judgment about the rate of inflation in medical costs. As our estimate of the rate of inflation of medical costs increases, our calculation of the total cost of providing these benefits increases. During 2001, we increased our assumption about this rate to 10%, and we also assumed that the rate would ultimately decline to 5% in 2009 and beyond. If we were to increase our assumption of the ultimate medical inflation rate from 5% to 6%, then all other things being equal, the present value of our postretirement medical cost obligation would increase by approximately $25 million.
32
Our accrual for postretirement medical benefits is also impacted by the mortality rate of the population for which we provide benefits. As people live longer, our costs to provide postretirement medical care increases. However, the number of assigned beneficiaries for our Company under the Coal Act is fixed, since we discontinued our eastern underground operations, and the primary beneficiaries are elderly.
The Medicare Reform Act provides certain prescription drug benefits. We have estimated that the Medicare Reform Act reduced the present value of our future health care obligations by $16.5 million as of December 31, 2003. There is no authoritative guidance on accounting for the Medicare Reform Act, and we may be required to revise our estimate when guidance becomes available.
| Related Information | |||||
The present value of our actuarially determined liability for postretirement medical costs increased approximately $13.2 million between December 31, 2002 and 2003, principally because of an increase in actual costs over prior estimates and for the reasons described above. Actuarial valuations project that our retiree health benefit costs will continue to increase in the near term and then decline to zero over the next approximately sixty years as the number of eligible beneficiaries declines. We incurred cash costs of $20.7 million for postretirement medical costs during 2003 compared to $20.5 million in 2002, and we expect to incur approximately $26 million for these costs in 2004 (including the Combined Fund’s retroactive assessment balance of $3.5 million, which we must pay pending the outcome of that litigation).
We incurred cash costs of $2.1 million for workers’ compensation benefits during 2003 compared to $2.8 million in 2002. We expect to incur fewer cash costs for workers’ compensation benefits in 2004 and expect that amount to steadily decline to zero over the next approximately eighteen years. We anticipate that these costs will decline because we are no longer self-insured for workers’ compensation benefits and have had no new claimants since 1995.
We do not pay black lung benefits directly. These benefits are paid from a trust that we established. The trust is overfunded by $6.2 million as of December 31, 2003. We do not expect to be required to make additional contributions to the trust.
The Coal Act, passed in 1992, established three benefit plans. First, the statute merged the UMWA 1950 and 1974 Plans into the Combined Fund. The Combined Fund provides benefits to a completely closed pool of beneficiaries, retirees who were actually receiving benefits from either the 1950 or 1974 Plan as of July 20, 1992. The Coal Act requires the benefits provided to this group to remain substantially the same as provided by the 1950 and 1974 Plans as of January 1, 1992. This group is essentially Medicare eligible and the Combined Fund serves as a Medicare supplement. Second, the Coal Act requires individual employer plans (IEP) established in prior collective bargaining agreements to be maintained and requires the level of benefits to be substantially the same as beneficiaries received as of January 1, 1992. The statutorily required IEP applies to retirees meeting age and service requirements as of February 1, 1993 and who actually retired before September 30, 1994. Third, the Coal Act establishes the 1992 UMWA Benefit Plan to serve three distinct populations:
33
| • | 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 goes out of business | ||||
| • | New spouses or new dependants of retirees in the Combined Fund | ||||
We maintain an IEP for our own retirees and the premiums we pay cover a portion of the retired miners whose previous employers have gone out of business. In addition to these Coal Act requirements, we continue to provide similar benefits under another IEP to a smaller group of former UMWA employees who retired under the Company’s last collective bargaining agreement which ended in 1998. This plan is known as the 93 Plan.
As noted above, we expect that the Medicare Reform Act will reduce our prescription drug costs. The Medicare Reform Act provides a prescription drug benefit under Medicare as well as a Federal subsidy, starting in 2006 so long as an employer maintains qualifying health plans that provide prescription drug benefits. We currently estimate that the Medicare Reform Act will reduce our retiree medical costs by approximately $2.5 million in 2006 and annually thereafter until total drug costs begin to decline.
| Asset Retirement Obligations, Reclamation Costs and Reserve Estimates | |||||
Asset retirement obligations primarily relate to the closure of mines and the reclamation of land upon cessation of mining. We account for reclamation costs, along with other costs related to mine closure, in accordance with Statement of Financial Accounting Standards No. 143 – Asset Retirement Obligations (“SFAS No. 143”), which we adopted on January 1, 2003. This statement requires us to recognize the fair value of an asset retirement obligation in the period in which we incur that obligation. We capitalize the present value of our estimated asset retirement costs as part of the carrying amount of our long-lived assets.
The liability, “Asset retirement obligations,” represents our estimate of the present value of the cost of closing our mines and reclaiming land that has been disturbed by mining. This liability increases as land is mined and decreases as reclamation work is performed and cash expended. The asset, “Property, plant and equipment – capitalized asset retirement costs,” remains constant until new liabilities are incurred or old liabilities are re-estimated. We estimate the future costs of reclamation using standards for mine reclamation that have been established by the government agencies that regulate our operations as well as our own experience in performing reclamation activities. These estimates may change. Developments in our mining program also affect this estimate by influencing the timing of reclamation expenditures.
Adopting SFAS No. 143 significantly affected our financial statements. See the Summary of Significant Accounting Policies to our consolidated financial statements, which includes a discussion of the effect on our financial statements of adopting SFAS No. 143. However, the adoption of SFAS No. 143 did not affect our cash costs, because the annual cash requirements for reclamation activities are the same using SFAS No. 143 and the units-of-production accrual method, the accounting method we used prior to adopting SFAS No. 143.
We amortize our acquisition costs, development costs, capitalized asset retirement costs and some plant and equipment using the units-of-production method and estimates of recoverable proven and probable reserves. We review these estimates on a regular basis and adjust them to reflect our current mining plans. The rate at which we record depletion also depends on the estimates of our reserves. If the estimates of recoverable proven and probable reserves decline, the rate at which we record depletion increases. Such a decline in reserves may result from geological conditions, coal quality, effects of governmental, environmental and tax regulations, and assumptions about future prices and future operating costs.
34
| Deferred Income Taxes | |||||
| Estimates and Judgments | |||||
Our net income is sensitive to estimates we make about our ability to use our Federal net operating loss carryforwards, or NOLs.
As of December 31, 2003, we had approximately $180 million of NOLs. These NOLs expire at various dates through 2023. When we have taxable income, we can use our NOLs to shield that income from regular U.S. Federal income tax. Our ability to use our NOLs thus depends on all the factors that determine taxable income, including operational factors, such as new coal sales, and non-operational factors, such as increases in heritage health benefit costs. Under Federal tax law, our ability to use our NOLs would be limited if we had a “change of ownership” within the meaning of the Federal tax code.
Our NOLs are one of our deferred income tax assets. We have reduced our deferred income tax assets by a valuation allowance. The valuation allowance is primarily an estimate of the deferred tax assets that may not be realized in future periods. On a quarterly and annual basis, we estimate how much of our NOLs we will be able to use to shield future taxable income and make corresponding adjustments in the valuation allowance.
If we increase our estimated utilization of NOLs, we decrease the valuation allowance and increase our net deferred income tax assets and recognize an income tax benefit in earnings. If we decrease our estimated utilization of NOLs, we increase the valuation allowance and decrease our net deferred income tax assets and increase income tax expense. These changes can materially affect our net income and our assets. In 2003, for example, we reduced the valuation allowance by $7.8 million, in part because we signed a new coal supply agreement and because we negotiated improved terms of an existing coal supply agreement. We also made other adjustments in our net deferred tax assets. As a result of these estimates and adjustments and changes in temporary differences between book and tax accounting, our net deferred income tax assets increased from $65.1 million at December 31, 2002 to $75.8 million at December 31, 2003, and we recognized income tax benefit from continuing operations of $11.0 million.
| Related Information | |||||
Our NOLs are important to our strategy. And under the federal tax laws, there are two types of NOLs, regular NOLs and alternative minimum tax, or AMT, NOLs. NOLs can offset our future taxable income, permit us to avoid payment of regular Federal income tax and thereby increase our cash flow and return from profitable investments (as compared to the return a tax-paying entity would receive that cannot shield its income from federal income taxation). However, regular NOLs will not shield our income from AMT.
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Under the federal tax laws, there are two types of taxable income, regular taxable income and Alternative Minimum Taxable Income, or AMTI. To determine AMTI, items such as percentage depletion are added to our regular taxable income. We have significant percentage depletion because of our mining activities. We are subject to AMT at a 20% rate. As of December 31, 2003, we had AMT net operating loss carryforwards of approximately $35 million reduced from $60 million as of December 31, 2001. Only 90% of AMTI can be shielded each year by AMT NOLs. Any AMT paid is available as a credit against future regular Federal income tax, and the credits do not expire. Based upon our estimates of our future taxable income, we expect to fully utilize our remaining AMT NOLs in 2005 and begin paying the full 20% AMT in 2006. We may owe more than $5 million per year in AMT until we fully utilize our regular NOLs.
As a strategic matter, we may face choices between business strategies intended to reduce AMT and strategies that increase the use of our regular NOLs. Some of these may involve decisions about business activities that generate AMTI, and many of these choices will require us to make judgments about matters that will arise in the future and that are therefore inherently uncertain.
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The following table presents information about our contractual obligations and commitments as of December 31, 2003. Some of the figures below are estimates. We discuss these obligations and commitments elsewhere in this filing.
| Payments Due by Period (in thousands of dollars) |
||||||
| Contractual Obligations and Commitments |
Total | 2004 | 2005 | 2006 | 2007 | After |
| Westmoreland Mining term debt (1) | 88,500 | 10,300 | 10,300 | 11,300 | 12,000 | 44,600 |
| Westmoreland Coal Company revolving debt |
500 | - | 500 | - | - | - |
| Other debt | 4,469 | 1,295 | 1,374 | 695 | 625 | 480 |
| Operating leases | 5,594 | 2,753 | 1,356 | 867 | 618 | - |
| Heritage Health Benefit/ Pension: |
||||||
| Undiscounted obligations: | ||||||
| Workers’ compensation | 9,478 | 2,016 | 2,000 | 1,800 | 1,600 | 2,062 |
| 1974 UMWA pension | 250 (2) | 250 | - | - | - | - |
| Discounted obligations: | ||||||
| Combined Benefit Fund (Multiemployer) |
39,780 (3) | 8,311 | 4,783 | 4,516 | 4,254 | 17,916 |
| Postretirement medical | 237,554 (4) | 17,367 | 18,206 | 17,446 | 18,005 | 166,530 |
| Qualified pension benefits | 47,777 (5) | 456 | 597 | 832 | 1,118 | 44,774 |
| SERP benefits | 1,963 (6) | 76 | 74 | 71 | 69 | 1,673 |
| Pneumoconiosis | 21,961 (7) | 2,500 | 2,500 | 2,500 | 2,500 | 11,961 |
| Reclamation costs | 306,668 (8) | 5,757 | 4,902 | 4,296 | 4,024 | 287,689 |
| Preferred dividends | 15,303 (9) | 1,744 (10) | 1,744 (10) | 1,744 (10) | 1,744 (10) | 1,744 (10) per year |
| (1) | At December 31, 2003, Westmoreland Mining had deposited $17.5 million in two restricted accounts as collateral against these obligations. |
| (2) | We have settled the 1974 UMWA pension obligation, as discussed in Item 3 - Legal Proceedings. |
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| (3) | Except for retroactive premium assessments of approximately $3.5 million that we are contesting, we have not accrued the present value of this obligation, because this plan is a multiemployer plan. We expense our premium payments when due. |
| (4) | The table presents our estimate of our gross benefit obligation. The accrued liability, net of the unrecognized net actuarial loss and the unrecognized net transition obligation, was $127.2 million as of December 31, 2003. |
| (5) | The fair value of plan assets at December 31, 2003 was $32.8 million. Pension benefits will be paid from these assets. |
| (6) | The table presents our estimate of our gross benefit obligation. The accrued liability, net of the unrecognized net actuarial gain and an unrecognized prior service cost, was $2.2 million as of December 31, 2003. The plan was unfunded at December 31, 2003. |
| (7) | The fair value of plan assets at December 31, 2003 was $28.2 million. Pneumoconiosis benefits will be paid from these assets. |
| (8) | The table presents our estimate of our gross cost of final reclamation. The accrued liability of $123.3 million as of December 31, 2003 will increase in present value as acres are disturbed in mining operations and as mine closures draw nearer. The accrued liability reflects the present value of contractual obligations of our customers and Washington Group, the contract miner at the Absaloka Mine, to perform reclamation; we estimate that the gross amount of their obligations is $25.4 million. The table also does not reflect $52.8 million, the amount held in escrow as of December 31, 2003 from contributions by customers for reclamation of the Rosebud Mine. We estimate that the present value of our net expense for final reclamation - that is, the costs of final reclamation that are not the contractual responsibilities of others - is $45.2 million. |
| (9) | Represents quarterly dividends that are accumulated through and including January 1, 2004. |
| (10) | As provided in the Certificate of Designation establishing the Series A Preferred Stock, the holders of the Series A Preferred Stock are entitled to receive dividends "when, as and if declared by the Board of Directors out of funds of the Corporation legally available therefore." In general, dividends that are not paid cumulate, as provided in the Certificate of Designation. |
Our growth and development strategy is founded on the ownership and operation of profitable physical assets. We strive to identify assets that are low-cost producers and environmental leaders and that supply customers who share our orientation for low-cost production and our environmental concern. We believe that we will be more likely to achieve success in niche markets. Our goal is to acquire stable, long-term earnings. We will use our NOLs to shield that income from regular U.S. Federal income tax. Our acquisitions of the four coal operations in 2001 reflect the implementation of this strategy.
Examples of our current development efforts include the following:
| • | In 2003, property we own in Southern Colorado was leased and development of coalbed methane gas commenced. Twelve wells were drilled by year end and in early 2004 the wells were completed and production began. | ||||
| • | In 2001, as part of our transaction with Knife River, we acquired rights to develop the lignite deposits at Gascoyne, North Dakota. Our subsidiary, Westmoreland Power, Inc., has joined with MDU Resources Group, Inc. to pursue development of a baseloaded lignite-fired power plant near Gascoyne as part of the State of North Dakota’s Lignite Vision 21 (“LV-21”) program. LV-21 is a partnership between North Dakota and the Lignite Energy Council (“LEC”) that is administered by the North Dakota Industrial Commission (“NDIC”). Westmoreland Power and MDU executed a joint development agreement in 2001, and we each own half of the venture that is seeking to develop the power plant. In September 2001, NDIC awarded the Westmoreland/MDU joint venture up to $10 million in matching funds to finance feasibility and technical studies. In January 2003, as a result of these studies, we and MDU sought additional support from NDIC to study the feasibility of substituting a 250 MW or 175 MW power plant for the 500 MW plant that had originally been proposed. NDIC awarded the funds sought, and we and MDU completed studies of generation technology, and lignite mining issues in 2003. Air quality evaluation will be completed in 2004. | ||||
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An existing source of future income and cash flow relates to the Caballo Mine in Campbell County, Wyoming. In connection with the 2001 acquisitions, we acquired the stock of Horizon Coal Services, Inc. Horizon’s only asset is a royalty interest in coal reserves located at the Caballo Mine, which is owned by another company. The royalty of $.10 per ton covers the mining of 225 million tons of coal, making the gross royalty amount $22.5 million. The latest mine plan projects that mining of coal subject to the royalty will begin in 2007.
Another source of potential future income may involve ROVA. LG&E Power Inc. (“LPI”) has informed us that LPI may be interested in selling all of its independent power operations, including its 50% interest in the partnership that owns the ROVA Project. LPI has initiated a bid process to identify potential purchasers. Westmoreland Energy has certain rights under its partnership agreement with LPI to acquire LPI’s 50% interest in the ROVA Project.
As discussed in the Overview section above, we believe that our recent add-on term debt facility substantially improves our near term liquidity. In addition, even though the requirements of Westmoreland Mining’s basic term loan agreement, including debt service requirements, restrict our access to some of Westmoreland Mining’s cash, Westmoreland Mining itself generates significant liquidity. As discussed in more detail in the Liquidity Outlook section below, we expect to achieve increasing cash from operations in 2004, offset by higher capital expenditures at our mines that will reduce free cash flow.
Cash provided by operating activities was $24.8 million in 2003, $32.4 million in 2002 and $28.4 million in 2001. Cash from operations in 2003 compared to 2002 declined primarily because we had less operating income because of the anticipated change in the pricing structure at the Jewett Mine. The coal supply agreement changed from a cost-plus fees contract to a market based contract in July of 2002. The decline in our cash from operations was affected by an increase in our deferred tax assets, gains from the sale of DTA, and a net increase in our other assets. The net change in assets and liabilities was $16.3 million in 2003 compared to $15.0 million in 2002, resulting from higher non-cash expenses for pension and postretirement medical obligations. Also, cash from operations in 2002 benefited by approximately $1.1 million from a favorable judgment in a dispute with the U.S. Army concerning a power project in Fort Drum, New York, in which we owned an interest. Working capital was $5.6 million at December 31, 2003 compared to $10.1 million at December 31, 2002. The change resulted primarily from a $2.9 million reduction in the current portion of our deferred income tax assets and an increase in the current portion of our postretirement medical costs, mostly attributable to the accrual of the retroactive premiums assessed by the Combined Fund.
We used $17.3 million of cash in investing activities in 2003, $3.7 million in 2002 and $151.3 million in 2001. Cash used in investing activities in 2003 included $13.2 million of additions to property, plant and equipment for mine equipment and leases for coal reserves. Cash used in investing activities in 2003 also includes $11.0 million that we deposited in restricted accounts, pursuant to our term loan agreement and as collateral for our bonds. During 2003, net proceeds from sales of assets of $7.0 million included $4.5 million cash received from the sale of DTA and $1.4 million received from the sale of land and mineral rights in Colorado. In 2002, additions to property and equipment using cash totaled $7.3 million, and we received $3.6 million from the Absaloka Mine’s mining contractor to settle a dispute regarding repair of the dragline at that mine. Also during 2002, we deposited $6.4 million into restricted cash accounts for debt service, security deposits and reclamation deposit accounts. Those deposits were offset by the $6.0 million refund of collateral we received from the UMWA. In 2001, we used $162.7 million of cash in investing activities to purchase the Rosebud, Jewett, Beulah, and Savage mines. Other additions to our property, plant and equipment totaled $5.4 million in 2001. Cash provided by investing activities in 2001 included $16.0 million in proceeds from the sale of our interests in three independent power projects.
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We used $8.1 million of cash in financing activities in 2003, including $5.2 million for the net repayment of long-term debt and $1.5 million for the net repayment of revolving debt. Cash used in financing activities in 2002 primarily represented repayment of long-term debt of $13.8 million and the net repayment of revolving debt of $9.0 million. Cash provided by financing activities for 2001 totaled $113.9 million, mainly from the proceeds of long-term and revolving debt used in the 2001 acquisitions. Dividends paid to Westmoreland Resources’ 20% shareholder in 2003, 2002 and 2001 were $1.0 million, $1.2 million and $1.1 million, respectively.
Consolidated cash and cash equivalents at December 31, 2003 totaled $9.3 million (including $4.1 million at Westmoreland Mining, $4.2 million at Westmoreland Resources, and $1.5 million at our captive insurance subsidiary). At December 31, 2002, cash and cash equivalents totaled $9.8 million (including $5.1 million at Westmoreland Mining, $4.7 million at Westmoreland Resources, and $0.6 million at the captive insurance subsidiary). The cash at Westmoreland Mining is available to us through quarterly distributions, as described below. The cash at Westmoreland Resources is available to us through dividends. In addition, we had restricted cash and bond collateral, which were not classified as cash or cash equivalents, of $25.0 million at December 31, 2003 and $17.3 million at December 31, 2002. The restricted cash at December 31, 2003 included $17.4 million in Westmoreland Mining’s accounts. Our reclamation, workers’ compensation and postretirement medical cost obligation bonds were collateralized by interest-bearing cash deposits of $7.6 million, which amount we have classified as a non-current asset. In addition, we have reclamation deposits of $52.8 million, which we received from customers of the Rosebud Mine to pay for reclamation. We also have $5.0 million in interest-bearing debt reserve accounts for the ROVA Project. This cash is restricted as to its use and is classified as part of our investment in independent power projects.
In early March 2004, Westmoreland Mining entered into the add-on term debt facility. This facility will make $35 million available to us. The add-on facility will permit Westmoreland Mining to undertake certain significant capital projects in the near term without adversely affecting cash available at the parent. Although the terms of the add-on facility permit Westmoreland Mining to distribute this $35 million to Westmoreland Coal Company, the original term loan agreement, which financed our acquisition of the Rosebud, Jewett, Beulah, and Savage Mines, continues to restrict Westmoreland Mining’s ability to make distributions to Westmoreland Coal Company from ongoing operations. Until Westmoreland Mining has fully paid the original acquisition debt, which is scheduled for December 31, 2008, Westmoreland Mining may only pay Westmoreland Coal Company a management fee and distribute to Westmoreland Coal Company 75% of Westmoreland Mining’s surplus cash flow. Westmoreland Mining is depositing the remaining 25% into an account that will fund the $30 million balloon payment due December 31, 2008. At the same time that Westmoreland Mining entered into the add-on facility, it also extended its revolving credit facility to 2007 and reduced the amount of the facility to $12 million. Westmoreland Mining reduced the amount of the revolving facility to better align its capacity to its expected usage and borrowing base.
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As of December 31, 2003, Westmoreland Coal Company had $9.5 million of its $10.0 million revolving line of credit available to borrow. Westmoreland Coal Company is seeking to increase its revolving credit facility from $10 to $14 million and extend that facility for one year, from 2005 to 2006. We may also seek additional equity to finance our growth and development strategy and for general corporate needs.
| Significant Anticipated Variances between 2003 and 2004 | |||||
We anticipate that the following events and developments, which we expect will occur in 2004 but which did not occur in 2003, and the following events and developments, which we expect will not occur in 2004 but which did occur in 2003, will affect our liquidity and our net income.
We anticipate that our coal revenues will be higher, principally because of increased sales from the Absaloka and Rosebud Mines, partially offset by decreased sales from the Jewett Mine. We anticipate that our cost of coal sales will increase commensurate with the increase in production, and because of higher near term costs at the Jewett Mine. In the fourth quarter of 2003, operations at the Jewett Mine encountered an area where the stripping ratio – the ratio between the volume of overburden to the volume of the coal – was higher.
We anticipate that capital expenditures related to our mining activities will be higher in 2004 than in 2003. We expect that most of the increase in 2004 will be associated with mine development at the Jewett Mine, which is necessary to improve mining conditions.
The settlement with the 1974 Plan permitted us to reverse an accrued liability and recognize $6.3 million of income in 2003. This is a non-recurring item, but we will also avoid payments of approximately $2.1 million per year in each of the next three and one-half years.
In 2003, we received $4.5 million upon the sale of our interest in DTA, $1.4 million from North Central’s sale of surface and mineral rights, and $300,000 in bonus payments from North Central’s lease of coalbed methane rights. We do not anticipate having significant asset sales in 2004.
In 2003, we did not receive royalties from sales of coalbed methane. We anticipate that we will receive royalties from sales of coalbed methane in 2004.
In 2003, we received a $582,000 distribution from the Fort Lupton Project. We call this a “catch-up” distribution because most of it related to periods prior to 2003. We may receive a relatively small quarterly distribution from Ft. Lupton in 2004.
We sold our interest in DTA effective June 30, 2003. We were incurring losses from DTA at an annual rate of about $2 million, and our share of those losses in 2003 was about $1 million. We will not have losses from DTA in 2004.
Arbitration of the profit component of the price reopener with the owners of Colstrip Units 1&2 took place in the first week of March 2004. We expect that the arbitration will result in a price increase, retroactive to 2001, and that we will receive a lump-sum payment in 2004 for the retroactive piece.
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We anticipate that our interest income will be higher in 2004 than it was in 2003 because of continued deposits to Westmoreland Mining restricted accounts. We anticipate higher interest costs in 2004 because of the additional $20.4 million in fixed rate borrowed as of March 2004.
We accrued the entire amount of the Combined Fund’s retroactive assessment in 2003. Our cash cost will increase in 2004 as compared with 2003 as we pay this assessment. We are challenging this assessment, as discussed in Item 3 – Legal Proceedings.
During the next eighteen months, we plan to implement a common, corporate-wide enterprise resource planning system (IT system) to enhance our reporting and analysis capability. The initial investment is expected to be approximately $3 million but is also expected to deliver an acceptable return on investment through improved efficiencies and reduced costs associated with our current, separate systems.
We anticipate that the expense associated with the 2000 Performance Unit Plan will be lower in 2004 than it was in 2003. In 2000, we adopted a long-term incentive plan to promote the successful implementation of our strategic plan and link the compensation of our key managers to the appreciation in the price of our common stock. The value of the performance units awarded in 2000 was based on the absolute increase in market value of our common stock over the period July 1, 2000 to June 30, 2003. Because the value of our common stock appreciated $14.72 per share over that period, the value of the performance units at the end of the performance period was $6.4 million. This obligation is being paid out over time and may be paid in cash or stock. The Board’s Compensation & Benefits Committee also awarded performance units in 2001 and 2002. The value of the 2001 and 2002 awards is based on the appreciation of our common stock compared to that of our peers, and the value of these awards is capped. The potential maximum value of the performance units awarded in 2001 and 2002 is $2.9 million and $2.5 million, respectively. Because stockholders had approved a Long-Term Stock Incentive Plan at our 2002 Annual Meeting, we were able to use stock options as the sole vehicle for the 2003 long-term incentive program.
We have three defined benefit pension plans for full-time employees. We were not required to make any contributions to those plans in 2003. However, we will be required to contribute $1.7 million to the plans in 2004, and we may be required to make additional contributions in future years unless the return on the plans’ investments materially improves or the plans’ funding requirements change.
| Significant Factors Affecting Our Liquidity | |||||
The matters discussed above focus on anticipated differences between 2003 and 2004. It will be readily apparent that a number of non-recurring events significantly influenced our 2003 results. Our operational performance, our financial results, and our liquidity may also be affected by all of the other matters discussed in this Annual Report on Form 10-K, including the legal proceedings discussed in Item 3 and the matters discussed in this Management’s Discussion and Analysis of Financial Condition and Results of Operations. Primarily because of our size and the multitude of issues related to our transition from an eastern underground producer of coal, to a western niche surface producer with significant reliance on independent power operations,we have been subject to the impact of many matters beyond our control. For all of the foregoing reasons, and while we anticipate that we will be profitable in 2004, we cannot project our overall level of profitability.
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We do not have any off-balance sheet arrangements within the meaning of the rules of the Securities and Exchange Commission.
Coal Operations. We sold about 1.7 million more tons of coal in 2003 than we did in 2002, but our coal revenues decreased $6.3 million. Revenues declined because, for part of 2002, the Jewett Mine benefited from a “cost-plus fees” pricing structure in its contract with Texas Genco. We sold more tons at all of our mines in 2003 than we did in 2002, with the exception of the Beulah Mine, which was adversely affected by a longer than expected major maintenance outage at the Coyote Station. In addition, the Rosebud Mine was adversely affected by an unscheduled outage at the Colstrip Station. Costs, as a percentage of revenues, increased to 77% in 2003 compared to 75% in 2002, again largely as a result of the lower average sales price in 2003 at the Jewett Mine. Also, the implementation of SFAS No. 143 increased non-cash accretion costs at all mines for future reclamation activities and reduced margins in 2003.
The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods:
| Year Ended | |||||
| 2003 | 2002 | Change | |||
| Revenues – thousands | $ | 294,986 | $ | 301,235 | (2)% |
| Volumes – millions of equivalent coal tons | 27.8 | 26.1 | 7% | ||
| Cost of sales – thousands | $ | 228,433 | $ | 226,707 | 1% |
Depreciation, depletion and amortization increased to $12.6 million in 2003 compared to $11.5 million in 2002 due to capital expenditures and increased depreciation resulting from the increase in production levels.
Independent Power. Our equity in earnings from independent power operations increased from $14.5 million in 2002 to $15.8 million in 2003. During 2003 and 2002, the ROVA Project produced 1,653,000 and 1,639,000 megawatt hours, respectively, and achieved average capacity factors of 90% and 89%, respectively. Also, we recognized $582,000 in equity in earnings in 2003 from our 4.49% interest in the Ft. Lupton project, most of which was retroactive.
Costs and Expenses. Selling and administrative expenses increased from $31.7 million in 2002 to $33.4 million in 2003. Contributing to the increase were higher heritage health benefit costs and a higher compensation expense for long-term employee performance incentives. Heritage health benefit costs were $29.9 million in 2003 compared to $26.9 million in 2002. Five factors contributed to the increase:
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| • | The Combined Fund assessed the $4.7 million retroactive premium discussed above. | ||||
| • | We incurred an additional $2.3 million expense for postretirement medical obligations, principally because of a change in the discount rate and inflation in medical costs. | ||||
| • | We incurred an additional $2.5 million expense resulting from negative actuarial valuation adjustments for our workers’ compensation and black lung obligations. | ||||
| • | We eliminated $6.3 million in previously recognized obligations to the UMWA 1974 Pension Plan. | ||||
| • | We incurred increased legal fees associated with coal contract negotiations and litigation. | ||||
A redesign of our health care plans for active employees in 2003 and aggressive management of medical expenses reduced our health care costs by promoting better employee “consumerism” and increasing employees’ premium payments.
Long-term incentive compensation increased from $1.0 million in 2002 to $2.5 million in 2003. This expense was entirely attributable to the 2000 Performance Unit Plan, described above. This expense is a non-cash expense until it is paid. As permitted by the plan, we paid about 20% of the expense, $750,000 in cash and $375,000 in shares of common stock in 2003, leaving an obligation of $5.3 million as of December 31, 2003. Absent the impact of heritage health benefit costs and long-term compensation expense, selling, and administrative expenses in 2003 were consistent with those in 2002.
Interest expense was $10.1 million and $10.8 million for 2003 and 2002, respectively. The decrease was mainly due to the continued repayment of Westmoreland Mining’s debt. Interest income decreased in 2003 because of lower rates.
Other income in 2002 includes a $1.1 million gain in connection with the favorable judgment in the dispute with the U.S. Army.
Terminal Operations. As discussed in Note 4 to the Consolidated Financial Statements, effective June 30, 2003, we sold our interest in DTA and recognized a pre-tax gain of approximately $4.5 million. Our consolidated financial statements for 2003 and earlier periods reflect DTA as discontinued operations. Our share of operating losses from DTA was approximately $1.0 million for the six months we owned it in 2003 compared to $2.1 million related to a full year’s ownership in 2002. During 2002, we expensed as a non-cash impairment charge our remaining investment of $3.7 million in DTA as a result of continuing losses and an agreement by one of the terminal’s other owners to sell its interest for a loss.
Cumulative Effect of Change in Accounting Principle. We adopted SFAS No. 143 during first quarter 2003, as described in the section on “Critical Accounting Policies” above. The cumulative effect of the change was a gain of $161,000, net of tax expense of $108,000. We also reduced our recorded liability for mine reclamation from $159 million to $115 million as of January 1, 2003 and reduced the net book value of our property, plant and equipment from $189 million to $145 million as a result of adopting this standard.
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Coal Operations. The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods:
| Year Ended | |||||
| 2002 | 2001 | Change | |||
| Revenues – thousands | $ | 301,235 | $ | 231,048 | 30% |
| Volumes – millions of equivalent coal tons | 26.1 | 20.5 | 27% | ||
| Cost of sales – thousands | $ | 226,707 | $ | 177,304 | 28% |
Depreciation, depletion and amortization increased to $11.5 million in 2002 compared to $9.2 million in 2001 due to capital expenditures and a full year of coal production from the Rosebud, Jewett, Beulah, and Savage Mines.
Independent Power. Equity in earnings from the independent power operations was $14.5 million in 2002 compared to $15.9 million in 2001. Three projects contributed $1.3 million in earnings in 2001 before we sold them in March 2001. During 2002 and 2001, the ROVA Project produced 1,639,000 and 1,668,000 megawatt hours, respectively, and achieved average capacity factors of 89% and 90%, respectively. The decrease in 2002 was attributable to a small increase in the number of forced outage days for repairs.
Terminal Operations. Our share of losses from DTA was $2.1 million in 2002 compared to $1.9 million in 2001, principally because of reduced demand in foreign countries for U.S. coal and our obligation to pay our share of DTA’s expenses. We took an impairment charge during the third quarter of 2002 in an amount equal to the book value of our remaining investment in DTA: $3.7 million. This was a non-cash charge. We took this charge in part because of the terms pursuant to which one of our partners had agreed to sell its interest in DTA. This charge did not reduce our obligation to pay our share of DTA’s operating expenses. We sold our interest in DTA effective June 30, 2003.
Costs and Expenses. Selling and administrative expenses were $31.7 million for 2002 compared to $22.6 million in 2001. The amounts for 2002 and 2001 include $18.4 million and $11.6 million, respectively, incurred by the four mines acquired in 2001. Partially offsetting the 2002 increase was lower non-cash compensation expense for long-term employee performance incentives, with an expense of $1.0 million in 2002 compared to an expense of $3.2 million during 2001. The overall increase in selling and administrative expenses in 2002 is also due to higher legal costs related primarily to Westmoreland Resources’ dispute with Washington Group and an adverse judgment, with associated legal costs totaling $1.4 million, in the Basin landowner case described in Item 3, to annual salary increases, and to the addition of employees associated with our growth. Medical claims under our self-insured plan for active employees were also higher in 2002. 2001 benefited from a reduction of approximately $500,000 in the estimated liability for reclamation of a site we previously operated in Virginia while 2002 had a $300,000 additional benefit when we transferred that site to another operator.
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Heritage health benefit costs increased to $26.9 million in 2002 compared to $23.8 million in 2001, reflecting increased costs for the postretirement medical plans as actuarially determined, despite a decrease in payments made to the Combined Fund.
During 2002, we recognized a $1.1 million gain in connection with a dispute with the U.S. Army.
Interest expense was $10.8 million and $8.4 million for 2002 and 2001, respectively. The increase was mainly due to the acquisition financing obtained during the second quarter of 2001, despite repayment of $22.8 million term debt of the acquisition financing during 2002. Interest income decreased in 2002 because of lower rates.
As a result of our acquisitions, we recognized a $55.6 million deferred income tax asset in April 2001. This assumes that a portion of previously unrecognized NOLs will be utilized because we projected that we would generate taxable income in the future. The deferred asset increased to $65.1 million as of December 31, 2002 from $57.1 million at December 31, 2001 because of temporary differences (such as accruals for pension and reclamation expense, which are not deductible for tax purposes until paid) arising during the intervening period and because of a reduction of the deferred income tax valuation allowance discussed above. Deferred tax assets are comprised of both a current and long-term portion. When taxable income is generated, the deferred tax asset relating to our NOLs is reduced and a deferred tax expense (non-cash) is recognized, although no regular Federal income taxes are paid. Income tax benefit for 2002 represents a current income tax obligation for State income taxes, and the utilization of a portion of our NOLs, net of the impact of changes in deferred tax assets and liabilities.
Other Comprehensive Income. Total other comprehensive loss in 2002 was $3.4 million (net of income taxes of $2.3 million), primarily due to the recognition of an additional minimum pension liability of $3.3 million. This additional minimum liability was required to be recorded due to the underfunded status of our pension obligations. The remaining other comprehensive loss of $88,000 (net of income taxes of $59,000) recognized during 2002 represents the change in the unrealized loss on an interest rate swap agreement on ROVA’s debt caused by changes in market interest rates during the period. This compares to other comprehensive loss relating to this arrangement of $1.7 million (net of income taxes of $1.1 million) for 2001.
In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities (“FIN 46R”), which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. FIN 46R replaces FASB Interpretation No. 46, Consolidation of Variable Interest Entities, which was issued in January 2003. We do not have interests in any variable interest entities and, therefore, FIN 46R will not affect us.
FASB Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, was issued in May 2003. This Statement establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The Statement also includes required disclosures for financial instruments within its scope. The Statement was effective for us for instruments entered into or modified after May 31, 2003 and otherwise will be effective as of January 1, 2004, except for mandatorily redeemable financial instruments. For certain mandatorily redeemable financial instruments, the Statement will be effective for us of January 1, 2005. The effective date has been deferred indefinitely for certain other types of mandatorily redeemable financial instruments. We currently do not have any financial instruments that are within the scope of this Statement.
46
In addition to the trends and uncertainties described in Items 1 and 3 of this Annual Report on Form 10-K and elsewhere in this Management’s Discussion and Analysis of Results of Operations and Financial Condition, we are subject to the trends and uncertainties set forth below.
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 the cost of mining at particular mines for varying lengths of time and have a significant impact on our operating results. These conditions or events have included:
| • | unplanned equipment failures and the need to repair and maintain our capital equipment, including our draglines; | ||||
| • | geological conditions, such as variations in the quality of the coal produced from a particular seam, variations in the thickness of coal seams, and variations in the amounts of rock and other natural materials that overlie the coal that we are mining; and | ||||
| • | weather conditions. | ||||
We face risk due to potential disputes and expiration of our coal supply agreements. Our contract disputes with Texas Genco have been addressed through 2007 under our recent settlement agreement, but differences may occur as to the interpretation of various contract provisions after 2007. We have settled the cost component under the Colstrip 1&2 price reopener and have concluded arbitration proceedings related to the profit component. The arbitrators’ decision is pending and may or may not meet or exceed our profit expectations. Expiring contracts in the near term include Westmoreland Resources’ contract with Midwest Energy Resources Company at the end of 2004 and Dakota Westmoreland’s contract with the Heskett Station at the end of 2005.
As a general matter, the Company’s mines are dedicated to supply a relatively small number of customer plants. Interruptions in the operations of our primary customer plants pose risk due to limited alternate coal sales outlets. Events causing the discontinuation of operations at any one of our primary customer plants or causing a negative modification to any one of our primary coal sales contracts could result in material consequences to the Company.
We are a party to the legal proceedings described in Item 3 of this Annual Report on Form 10-K. Some of these proceedings, including the dispute with Halifax County, North Carolina, could require us to pay significant sums to various parties. Halifax County asserts that the ROVA Project owes $8.3 million in back taxes, penalty and interest. If the assessment is upheld, in addition to the amounts assessed, the ROVA Project’s future taxes would increase approximately $600,000 per year, of which we would be responsible for half.
47
The McGreevey litigation challenges our 2001 transaction with Entech in which we acquired the Rosebud and Jewett mines and other assets. Although we believe our position in this case is meritorious, the litigation is in a very preliminary stage, and there can be no assurance about the outcome. We would be materially and adversely affected by a decision that required us to surrender ownership of the Rosebud and Jewett mines without compensating us fairly.
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, and at the end of 2003, we employed 918 people. This growth has placed significant demands on our management as well as our financial and operational resources and systems. Among other things, we inherited systems developed by Entech and Knife River for their operations. We expect to begin deploying an enterprise resource planning system throughout our company in 2004. Although we expect that this system will be expensive, we also expect that it will improve our ability to manage our operations. To manage our expanded operations and growth effectively, we must maintain and enhance our financial and accounting systems, our safety programs, and our other operational 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. We cannot assure you that the deployment of our enterprise resource planning system will be successful or that we will be able to attract and retain the personnel we need to manage our increasingly large and complex operations.
We describe our growth and development strategy above. We regularly seek opportunities to make additional strategic acquisitions, to expand existing businesses, to develop new operations and to enter related businesses. We consider potential acquisition opportunities as they are identified, but we may not be able to consummate any particular acquisition.
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, and we may not find suitable acquisition candidates at acceptable prices. Our current or future acquisition and development efforts may not be successful, and we may not be able to complete any acquisition or project on terms that are favorable to us. Acquisitions and the development of projects involve risks, including difficulties in integrating acquired and new operations, diversions of management resources, debt incurred in financing such activities and unanticipated problems and liabilities. Any of these risks could have a material adverse effect upon our business, financial condition and results of operations.
48
As of December 31, 2003, our total indebtedness was approximately $93.5 million, which included Westmoreland Mining’s obligations under the term loan agreement. In March 2004, Westmoreland Mining made arrangements to borrow an additional $35 million through an add-on facility, $20.4 million of which was drawn immediately and $14.6 million of which must be drawn in the fourth quarter of 2004. All of this money is distributable to WCC without restriction. We may also incur additional indebtedness in the future.
Westmoreland Mining’s underlying term loan agreement restricts its ability to distribute cash to Westmoreland Coal Company through 2008 and limits the types of transactions that Westmoreland Mining and its subsidiaries can engage in with Westmoreland Coal Company and our other subsidiaries. After payment of principal and interest, 25% of Westmoreland Mining’s surplus cash flow is dedicated to an account that will fund the final payment of its acquisition debt due on December 31, 2008. Westmoreland Mining has pledged or mortgaged substantially all of its assets and the assets of the Rosebud, Jewett, Beulah, and Savage Mines as security for its indebtedness. In addition, Westmoreland Mining must comply with financial ratios specified in the agreement. Failure to comply with these covenants could result in an event of default which, if not cured or waived, could have a material adverse effect on us.
The degree to which we are leveraged could have important consequences, including:
| • | reducing the availability of the cash flow to fund working capital, capital expenditures or other general corporate uses; | ||||
| • | increasing our vulnerability to general adverse economic and industry conditions; | ||||
| • | limiting our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements; and | ||||
| • | limiting our flexibility in planning for, or reacting to, changes in our business and in the industry. | ||||
If 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. These alternative measures may not be successful and may not permit us or Westmoreland Mining to meet scheduled debt service obligations. In the absence of such operating results and resources, we or Westmoreland Mining could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet debt service and other obligations. 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.
Bonding capacity and insurance costs continue to challenge us and our industry. We are required to post surety bonds under SMCRA and other mining laws to ensure that reclamation will be performed, and we are also required to post bonds to secure our obligations under the Coal Act. Many participants in the coal industry have been informed by their insurance companies that the insurance companies no longer will provide surety bonds without collateral. We may be required to post additional collateral for our bonds in the future. Depending on the amount that our insurers require, we may not be able to provide cash collateral. If we were unable to provide cash collateral, we may seek to provide a letter of credit or other assurance of payment. We may not be able to obtain letters of credit on satisfactory terms, if at all, and letters of credit may be significantly more costly to us than surety bonds. If we or Westmoreland Mining fail to maintain statutorily-required bonds, we and Westmoreland Mining may be in default under our agreements with our respective lenders. A default under these agreements would have a material and adverse effect on us. The failure to maintain bonds could itself have a material and adverse effect on us by disrupting our mining operations.
49
Our insurance costs have increased and may continue to increase. We have been able to address a portion of these costs by organizing Westmoreland Risk Management and retaining a portion of the risk associated with our operations. However, Westmoreland Risk Management has limited capacity and has not been able to protect us completely from the increases in rates for property and casualty insurance since September 11, 2001.
Our ability to receive payment for the coal we sell depends on the creditworthiness of our customers. In general, the creditworthiness of certain of our customers has declined. Because the plants that we supply are baseloaded, we believe that we are protected from a portion of the credit risk associated with this decline. For example, on September 14, 2003, NorthWestern Corporation, a 15% owner of Colstrip Units 3&4, filed for bankruptcy protection. On September 23, 2003, NorthWestern Corporation defaulted on its obligations to make payments to the Rosebud Mine. In late October, the bankruptcy court entered an order approving Western Energy as a “critical vendor” and permitting NorthWestern Corporation to pay all of the amounts claimed by Western Energy at that time, and thereafter NorthWestern Corporation has continued to make timely payments. However, NorthWestern’s bankruptcy is illustrative of the pressures affecting the energy industry generally.
The coal industry is highly competitive and we compete with many producers who are larger and better capitalized than we are. We compete principally on price, quality and transportation costs of coal with other coal producers of various sizes. We have a transportation advantage where our mines are located adjacent to our customers’ power plants, or where, as with the Absaloka Mine, we are closer than our competitors to our customers.
Our coal also competes with other energy sources in the production of electricity. Factors such as the price of natural gas and the cost of environmental compliance are major considerations in the decision to operate or build and bring on line substantial new coal-fired generation. The price of natural gas has been volatile over the past year (ranging from a high of $18.85 per MMBTU in February 2003 to a low of $3.99 per MMBTU in October 2003 and increasing to $6.04 as of January 28, 2004) (Henry-Hub Spot) making the relative price stability in the coal market a significant contributor to renewed interest in constructing new, environmentally sound coal-fired generation.
The ROVA Project generates electricity directly and sell it on a wholesale, long-term contract basis to utilities under rates established in power purchase agreements and approved by regulatory agencies. The independent power industry has grown rapidly over the past twenty years, accelerating in the 1990‘s due, in part, to electric utility deregulation initiatives. The principal sources of competition in this market for additional capacity include traditional regulated utilities seeking to maximize utilization of existing capacity, unregulated subsidiaries of regulated utilities, energy brokers and traders, energy service companies in the business of developing, operating, and marketing energy-producing projects, equipment suppliers and other non-utility generators like our subsidiaries. Competition in this industry is substantially based on price. The lowest cost generating units will be the most competitive in the market place and will run more frequently.
50
Throughout the last several years the electrical generation industry has suffered several disruptions, notably the breakdown of deregulation in California, episodic failure of the transmission system in the eastern U.S. and Canada and an oversupply of natural gas generation capacity. As a consequence, interest in building new coal-fired generation has increased. Many new generating facilities, including our potential LV-21 project, have been publicly announced. We anticipate that, as the economy grows, the demand for power will also grow and interest in new generating capacity and transmission should reemerge.
At the national and state level, the debate continues about deregulation of electricity and the creation of competitive markets for wholesale and retail sale of electricity. System reliability and transmission issues, including wheeling power from one system to another and system constraints (insufficient transmission line capacity to add more electricity), are among the factors being analyzed, and the pace at which these problems are solved will affect how quickly competitive power markets may become a reality. We cannot predict how the market for coal, the independent power business, or the energy industry as a whole might be affected by this debate.
During the mid-1970s and early 1980s, a growing coal market and increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in added production capacity throughout the industry, all of which led to increased competition and lower coal prices. Increases in coal prices similarly could encourage the development of expanded capacity by new or existing coal producers. Any overcapacity could reduce coal prices in the future.
Coal contains impurities, including sulfur, mercury and other elements or compounds, many of which are released into the air when coal is burned. Stricter environmental regulations of emissions from coal-fired electric generating plants could increase the costs us using coal, thereby, reducing demand for coal as a fuel source and the volume of our coal sales. Stricter regulations could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future.
On January 30, 2004, EPA published two major draft rules concerning the regulation of mercury, sulfur dioxide and nitrogen oxide emissions: (1) Proposed National Emission Standards for Hazardous Air Pollutants (Mercury); and (2) the Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone (Interstate Air Quality Rule, or “IAQR”). These draft rules effectively overshadow the Bush Administration’s Clear Skies Initiative and for the affected states, the IAQR replaces EPA’s State Implementation Plan Call.
EPA proposes to regulate for the first time emissions of mercury by electrical generating units, in one of three ways: (1) a rigid plant-by-plant approach (commonly referred to as MACT, “Maximum Available Control Technology”) whereby power plants would have to meet emission standards determined by the rank of coal burned, by 2008; (2) a pure cap-and-trade approach modeled on Title IV of the Clean Air Act and the sulfur dioxide emissions allowance trading program; or (3) a combination of a MACT and cap-and-trade.
51
The Interstate Air Quality Rule is also based on the Clean Air Act. EPA proposes to use a cap-and trade program (utilizing and modeled on the Acid Rain Program) to further reduce emissions of sulfur dioxide and nitrogen oxide in 29 states and the District of Columbia, primarily states in the eastern part of the country. We have operations or customers in states covered by these regulations, and the EPA’s sulfur dioxide proposal could result in national impacts by utilizing the existing Title IV sulfur dioxide allowance market. Air quality in each state is affected by both emissions emanating from activities in that state as well as emissions transported from adjacent states. The draft rule proposes to regulate both.
EPA is accepting comments on the IAQR until March 30, 2004 and on the mercury rules until April 30, 2004. We are currently assessing the potential implications of these rules for our operations. At this time, we cannot predict the effect of these initiatives on us.
The ROVA Project currently utilizes state-of-the-art emission control technologies and has consistently been rated among the cleanest coal-fired power plants in the country. The ROVA Project is also evaluating its strategies for complying with these proposals, should they be adopted.
The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change which is intended to limit or capture emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emissions targets for developed nations. The United States declined to sign the treaty. President Bush believed that the treaty severely limited the ability of the United States to compete in the global marketplace. On December 2, 2003, Russia announced its decision not to sign the Kyoto Accord stating that the treaty limited Russia’s economic growth. With the Russian decision not to sign, the treaty must be renegotiated or it is effectively terminated. Although the specific emissions targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. If the Kyoto Protocol or other comprehensive legislation focusing on greenhouse gas emissions is enacted by the United States, it could have the effect of restricting the use of coal. Other efforts to reduce emissions of greenhouse gases and federal initiatives to encourage the use of natural gas also may affect the use of coal as an energy source.
Environmental initiatives by the States may affect our operations. For example, Texas has passed regulations requiring all fossil fuel-fired generating facilities in the state to reduce nitrogen oxide emissions to 0.165 pounds per million Btu on an annual average basis beginning in May 2003. This standard may be met by the application of new technology, fuel characteristics, or emission credits. Texas Genco may assert that the Texas nitrogen oxide regulations impact lignite usage at the Limestone Station. Other states are evaluating various strategies for improving air quality and reducing emissions. Passage of other state specific environmental laws may further affect our operations. We are monitoring events and issues to evaluate the effects of any new environmental law or regulations.
52
We accrue for the costs of current mine disturbance and of final mine closure. Estimates of our gross reclamation and mine-closing liabilities, which are based upon permit requirements and our experience, were $307 million (with a present value of $123 million) at December 31, 2003. A significant portion of these costs are the financial responsibility of our customers, or have been funded by our customers and the Absaloka Mine’s mining contractor. Our customers have secured a portion of their obligations by posting bonds in the amount of $50 million and funding reclamation escrow accounts in the amount of approximately $54 million, in each case at December 31, 2003, but our obligations will be funded from future operations. Our future results could be affected by our reclamation obligations.
We provide various long-term employee benefits under the Coal Act and contracts and to our current and former employees. We accrue amounts for these obligations. Our accruals are estimated based on assumptions that are described above. However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated.
In January 2001, the United States Department of Labor amended the regulations implementing the federal black lung laws to give greater weight to the opinion of a claimant’s treating physician, expand the definition of black lung disease and limit the amount of medical evidence that can be submitted by claimants and respondents. The amendments also alter administrative procedures for the adjudication of claims, which, according to the Department of Labor, results in streamlined procedures that are less formal, less adversarial and easier for participants to understand. These and other changes to the federal black lung regulations could increase our exposure to black lung benefits liabilities.
In recent years, legislation on black lung reform has been introduced but not enacted in Congress. It is possible that this legislation will be reintroduced for consideration by Congress. If any of the proposals included in this or similar legislation is passed, the number of claimants who are awarded benefits could significantly increase. Any such changes in black lung legislation, if approved, may adversely affect our business, financial condition and results of operations.
Our equity in earnings from independent power could be adversely affected if a scheduled outage at ROVA I lasts longer than we anticipate. ROVA I is currently scheduled to be out of service for 42 days for major maintenance in 2004. If that maintenance uncovers matters beyond those anticipated, the outage may be prolonged beyond the 42-day period. ROVA I’s contract with Virginia Power is structured so that our equity in earnings from independent power will not be adversely affected by a 42-day outage for major maintenance this year, but a prolonged outage could adversely affect our equity in earnings from independent power.
53
Our coal sales may be adversely affected by unscheduled outages at the power plants we supply. We cannot anticipate if or when unscheduled outages may occur.
Under several of our existing coal supply agreements, our mines bear the cost of the gasoline, lubricants and other petroleum products, electricity, and other materials and supplies necessary to operate their draglines and other mobile equipment. The prices of certain of these commodities have increased in the last year, and continued escalation of these costs could affect our profitability.
The coal mines we own incur capital expenditures for the equipment necessary to maintain operations and need to make large investments in development costs to expand mining operations into new areas of each mine. The actual costs could exceed estimates and infringe upon our available cash.
The loss of key senior management personnel could adversely affect us. We depend on the continued services and performance of senior management and other key personnel, particularly Christopher K. Seglem, Chairman of the Board, President and Chief Executive Officer. We do not have “key person” life insurance policies. The unexpected loss of any of our executive officers or other key employees could harm our business.
| ITEM 7A – | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Company is exposed to market risk, including the effects of changes in commodity prices as discussed below.
The Company, through its subsidiaries WRI and WML, produces and sells coal to third parties from coal mining operations in Montana, Texas and North Dakota and through its subsidiary, WELLC, produces and sells electricity and steam to third parties from its independent power projects located in North Carolina and Colorado. Nearly all of the Company’s coal production and all of its electricity and steam production are sold through long-term contracts with customers. These long-term contracts serve to minimize the Company’s exposure to changes in commodity prices although some of the Company’s contracts are adjusted periodically based upon market prices. The Company has not entered into derivative contracts to manage its exposure to changes in commodity prices, and was not a party to any such contracts at December 31, 2003.
54
The Company and its subsidiaries are subject to interest rate risk on its debt obligations. Long-term debt obligations have both fixed and variable interest rates, and the Company’s revolving line of credit has a variable rate of interest indexed to either the prime rate or LIBOR. Interest rates on these instruments approximate current market rates as of December 31, 2003. Based on the balances outstanding as of December 31, 2003, a one percent change in the prime interest rate or LIBOR would increase interest expense by $10,000 on an annual basis. The Company’s heritage health benefit costs are also impacted by interest rate changes because its pension, pneumoconiosis and post-retirement medical benefit obligations are recorded on a discounted basis.
55
| ITEM 8 - | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
| Index to Financial Statements Page | Page |
| Consolidated Balance Sheets | 57 |
| Consolidated Statements of Operations | 59 |
| Consolidated Statements of Shareholders’ Equity and Comprehensive Income | 61 |
| Consolidated Statements of Cash Flows | 62 |
| Summary of Significant Accounting Policies | 63 |
| Notes to Consolidated Financial Statements | 69 |
56
| December 31, | 2003 | 2002 | |||
| (in thousands) | |||||
| Assets | |||||
| Current assets: | |||||
| Cash and cash equivalents | $ | 9,267 | $ | 9,845 | |
| Receivables: | |||||
| Trade | 24,414 | 20,962 | |||
| Other | 4,465 | 7,249 | |||
| 28,879 | 28,211 | ||||
| Inventories | 14,289 | 14,018 | |||
| Deferred overburden removal costs | 9,559 | 5,741 | |||
| Restricted cash | 8,751 | 8,497 | |||
| Deferred income taxes | 12,921 | 15,831 | |||
| Other current assets | 4,468 | 6,765 | |||
| Total current assets | 88,134 | 88,908 | |||
| Property, plant and equipment: | |||||
| Land and mineral rights | 20,740 | 53,314 | |||
| Capitalized asset retirement costs | 104,036 | - | |||
| Plant and equipment | 93,880 | 197,759 | |||
| 218,656 | 251,073 | ||||
| Less accumulated depreciation and depletion | 67,307 | 61,541 | |||
| Net property, plant and equipment | 151,349 | 189,532 | |||
| Deferred income taxes | 62,866 | 49,253 | |||
| Investment in independent power projects | 38,487 | 33,407 | |||
| Excess of trust assets over pneumoconiosis benefit | |||||
| obligation | 6,234 | 7,665 | |||
| Restricted cash and bond collateral | 16,218 | 8,790 | |||
| Advance coal royalties | 4,013 | 4,639 | |||
| Deferred overburden removal costs | 3,095 | 4,607 | |||
| Reclamation deposits | 52,786 | 49,484 | |||
| Contractual third party reclamation obligations | 23,065 | 23,235 | |||
| Other assets | 11,590 | 12,437 | |||
| Total Assets | $ | 457,837 | $ | 471,957 | |
See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.
(Continued)
57
| December 31, | 2003 | 2002 | |||
| (in thousands) | |||||
| Liabilities and Shareholders' Equity | |||||
| Current liabilities: | |||||
| Current installments of long-term debt | $ | 11,595 | $ | 8,852 | |
| Accounts payable and accrued expenses: | |||||
| Trade | 26,559 | 27,070 | |||
| Income taxes | - | 594 | |||
| Production taxes | 16,127 | 14,273 | |||
| Workers' compensation | 2,016 | 2,335 | |||
| Postretirement medical costs | 20,275 | 12,787 | |||
| 1974 UMWA Pension Plan obligations | 250 | 1,473 | |||
| Asset retirement obligations | 5,757 | 11,381 | |||
| Total current liabilities | 82,579 | 78,765 | |||
| Long-term debt, less current installments | 81,874 | 91,305 | |||
| Workers' compensation, less current portion | 7,462 | 8,405 | |||
| Postretirement medical costs, less current | |||||
| portion | 110,493 | 104,336 | |||
| Pension and SERP costs | 9,008 | 4,341 | |||
| 1974 UMWA Pension Plan obligations, less current | |||||
| portion | - | 6,562 | |||
| Asset retirement obligations, less current portion | 117,586 | 148,410 | |||
| Other liabilities | 11,269 | 6,732 | |||
| Minority interest | 4,296 | 4,533 | |||
| Commitments and contingent liabilities | |||||
| Shareholders' equity | |||||
| Preferred stock of $1.00 par value | |||||
| Authorized 5,000,000 shares; | |||||
| Issued and outstanding 205,083 shares at | |||||
| December 31, 2003 and 206,833 shares at December 31, 2002 |
205 | 207 | |||
| Common stock of $2.50 par value | |||||
| Authorized 20,000,000 shares; | |||||
| Issued and outstanding 7,957,166 shares at | |||||
| December 31, 2003 and 7,711,379 shares | |||||
| at December 31, 2002 | 19,893 | 19,278 | |||
| Other paid-in capital | 72,825 | 70,908 | |||
| Accumulated other comprehensive loss | (4,948) | (5,101) | |||
| Accumulated deficit | (54,705) | (66,724) | |||
| Total shareholders' equity | 33,270 | 18,568 | |||
| Total Liabilities and Shareholders' Equity | $ | 457,837 | $ | 471,957 | |
See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.
58
| Years Ended December 31, | 2003 | 2002 | 2001 | |||||
| (in thousands except per share data) | ||||||||
| Revenues: | ||||||||
| Coal | $ | 294,986 | $ | 301,235 | $ | 231,048 | ||
| Independent power projects - equity in earnings | 15,824 | 14,506 | 15,871 | |||||
| 310,810 | 315,741 | 246,919 | ||||||
| Cost and expenses: | ||||||||
| Cost of sales - coal | 228,433 | 226,707 | 177,304 | |||||
| Depreciation, depletion and amortization | 12,599 | 11,539 | 9,165 | |||||
| Selling and administrative | 33,386 | 31,732 | 22,625 | |||||
| Heritage health benefit costs | 29,922 | 26,921 | 23,773 | |||||
| Loss (gain) on sales of assets | (645) | 9 | 440 | |||||
| 303,695 | 296,908 | 233,307 | ||||||
| Operating income from continuing operations | 7,115 | 18,833 | 13,612 | |||||
| Other income (expense): | ||||||||
| Interest expense | (10,114) | (10,821) | (8,418) | |||||
| Interest income | 1,952 | 2,117 | 2,657 | |||||
| Minority interest | (773) | (800) | (780) | |||||
| Other income | 1,169 | 2,011 | 572 | |||||
| (7,766) | (7,493) | (5,969) | ||||||
| Income
(loss) from continuing operations before income taxes and cumulative effect of change in accounting principle |
(651) | 11,340 | 7,643 | |||||
| Income tax benefit (expense) from continuing operations |
10,971 | 2,368 | (1,228) | |||||
| Net income from continuing operations before cumulative effect of change in accounting principle |
10,320 | 13,708 | 6,415 | |||||
| Discontinued operations: | ||||||||
| Loss from operations of discontinued terminal segment (including impairment charge in 2002 of $3,712) |
(988) | (5,971) | (1,980) | |||||
| Gain on sale of discontinued terminal segment | 4,509 | - | - | |||||
| Income tax benefit (expense) | (1,408) | 2,388 | 792 | |||||
| Income (loss) from discontinued operations | 2,113 | (3,583) | (1,188) | |||||
| Net income before cumulative effect of change in accounting principle |
12,433 | 10,125 | 5,227 | |||||
| Cumulative effect of change in accounting principle, net of income tax expense of $108 |
161 | - | - | |||||
| Net income | 12,594 | 10,125 | 5,227 | |||||
| Less preferred stock dividend requirements | 1,752 | 1,772 | 1,776 | |||||
| Net income applicable to common shareholders |
$ | 10,842 | $ | 8,353 | $ | 3,451 | ||
(Continued)
59
| Years Ended December 31, | 2003 | 2002 | 2001 | |||||
| (in thousand except per share data) | ||||||||
| Net income per share applicable to common shareholders before cumulative effect of change in accounting principle: |
||||||||
| Basic | $ | 1.37 | $ | 1.10 | $ | 0.48 | ||
| Diluted | $ | 1.28 | $ | 1.03 | $ | 0.43 | ||
| Net income per share applicable to common shareholders from cumulative effect of change in accounting principle: |
||||||||
| Basic and diluted | $ | 0.02 | $ | - | $ | - | ||
| Net
income per share applicable to common shareholders: |
||||||||
| Basic | $ | 1.39 | $ | 1.10 | $ | 0.48 | ||
| Diluted | $ | 1.30 | $ | 1.03 | $ | 0.43 | ||
| Pro forma
amounts assuming the change in accounting principle is applied retroactively: |
||||||||
| Net income applicable to common shareholders | $ | 10,681 | $ | 8,200 | $ | 3,367 | ||
| Net income per share applicable to
common shareholders: |
||||||||
| Basic | $ | 1.37 | $ | 1.08 | $ | 0.47 | ||
| Diluted | $ | 1.28 | $ | 1.01 | $ | 0.42 | ||
| Weighted average number of common
shares outstanding - basic |
7,799 | 7,608 | 7,239 | |||||
| Weighted average number of common
shares outstanding - diluted |
8,338 | 8,147 | 8,000 | |||||
See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.
60
| Class A Convertible Exchangeable Preferred Stock | Common Stock | Other Paid-In Capital | Accumulated Other Comprehensive Loss | Accumulated Deficit | Total Shareholders’ Equity | |||||||
| (in thousands) | ||||||||||||
| Balance at December 31, 2000 (208,708 preferred and 7,069,663 common shares outstanding) |
$ 209 | $ 17,674 | $ 67,318 | $ - | $ (81,828) | $ 3,373 | ||||||
| Common stock issued as | ||||||||||||
| compensation (74,108 shares) | - | 185 | 865 | - | - | 1,050 | ||||||
| Common stock options exercised | ||||||||||||
| (371,450 shares) | - | 928 | 551 | - | - | 1,479 | ||||||
| Tax benefit of stock option exercises |
- | - | 989 | - | - | 989 | ||||||
| Net income | - | - | - | - | 5,227 | 5,227 | ||||||
| Net unrealized change in interest | ||||||||||||
| rate swap agreement, net of | ||||||||||||
| taxes of $1,135 | - | - | - | (1,703) | - | (1,703) | ||||||
| Comprehensive income | 3,524 | |||||||||||
| Balance at December 31, 2001 (208,708 preferred and 7,515,221 common shares outstanding) |
209 | 18,787 | 69,723 | (1,703) | (76,601) | 10,415 | ||||||
| Common stock issued as | ||||||||||||
| compensation (118,258 shares) | - | 296 | 1,128 | - | - | 1,424 | ||||||
| Common stock options exercised | ||||||||||||
| (77,900 shares) | - | 195 | 139 | - | - | 334 | ||||||
| Repurchase and retirement of | ||||||||||||
| preferred shares (1,875 shares) | (2) | - | (242) | - | - | (244) | ||||||
| Dividends declared | - | - | - | - | (248) | (248) | ||||||
| Tax benefit of stock option exercises |
- | - | 160 | - | - | 160 | ||||||
| Net income | - | - | - | - | 10,125 | 10,125 | ||||||
| Minimum pension liability, net of | ||||||||||||
| taxes of $2,207 | - | - | - | (3,310) | - | (3,310) | ||||||
| Net unrealized change in interest | ||||||||||||
| rate swap agreement, net of | ||||||||||||
| taxes of $59 | - | - | - | (88) | - | (88) | ||||||
| Comprehensive income | 6,727 | |||||||||||
| Balance at December 31, 2002 (206,833 preferred and 7,711,379 common shares outstanding) |
207 | 19,278 | 70,908 | (5,101) | (66,724) | 18,568 | ||||||
| Common stock issued as | ||||||||||||
| compensation (131,087 shares) | - | 327 | 1,524 | - | - | 1,851 | ||||||
| Common stock options exercised | ||||||||||||
| (114,700 shares) | - | 288 | 120 | - | - | 408 | ||||||
| Repurchase and retirement of | ||||||||||||
| preferred shares (1,750 shares) | (2) | - | (211) | - | - | (213) | ||||||
| Dividends declared | - | - | - | - | (575) | (575) | ||||||
| Tax benefit of stock option exercises |
- | - | 484 | - | - | 484 | ||||||
| Net income | - | - | - | - | 12,594 | 12,594 | ||||||
| Minimum pension liability, net of | ||||||||||||
| taxes of $488 | - | - | - | (732) | - | (732) | ||||||
| Net unrealized change in interest | ||||||||||||
| rate swap agreement, net of | ||||||||||||
| taxes of $590 | - | - | - | 885 | - | 885 | ||||||
| Comprehensive income | 12,747 | |||||||||||
| Balance at December 31, 2003 | ||||||||||||
| (205,083 preferred and | ||||||||||||
| 7,957,166 common shares | ||||||||||||
| outstanding) | $ 205 | $ 19,893 | $ 72,825 | $ (4,948) | $ (54,705) | $ 33,270 | ||||||
See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.
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| Years Ended December 31, | 2003 | 2002 | 2001 | |||
| (in thousands) | ||||||
| Cash flows from operating activities: | ||||||
| Net income | $ | 12,594 | $ | 10,125 | $ | 5,227 |
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||
| Equity in earnings of independent power projects | (15,824) | (14,506) | (15,871) | |||
| Cash distributions from independent power projects | 11,629 | 9,718 | 18,426 | |||
| Deferred income tax benefit | (9,731) | (5,656) | (472) | |||
| Depreciation, depletion and amortization | 12,599 | 11,539 | 9,165 | |||
| Stock compensation expense | 1,851 | 1,424 | 1,050 | |||
| Impairment charges | - | 3,712 | - | |||
| Losses (gains) on sales of assets | (5,154) | 9 | 440 | |||
| Minority interest | 773 | 800 | 780 | |||
| Cumulative effect of change in accounting principle | (269) | - | - | |||
| Other | - | 263 | 352 | |||
| Changes in assets and liabilities: | ||||||
| Receivables, net | (668) | 15,273 | (5,429) | |||
| Inventories | (271) | (270) | (456) | |||
| Excess of trust assets over pneumoconiosis
benefit obligation |
1,431 | (680) | (178) | |||
| Accounts payable and accrued expenses | 1,343 | (369) | 13,049 | |||
| Income taxes payable | (594) | 537 | 57 | |||
| Accrual for workers’ compensation | (1,262) | (2,301) | (2,295) | |||
| Accrual for postretirement medical costs | 13,645 | 6,030 | 4,728 | |||
| 1974 UMWA Pension Plan obligations | (7,785) | (1,374) | (1,279) | |||
| Other assets and liabilities | 10,447 | (1,840) | 1,141 | |||
| Net cash provided by operating activities | 24,754 | 32,434 | 28,435 | |||
| Cash flows from investing activities: | ||||||
| Additions to property, plant and equipment | (13,240) | (7,323) | (5,433) | |||
| Cash paid for acquisitions | - | - | (162,700) | |||
| Reimbursement from mine operator | - | 3,600 | - | |||
| Change in restricted cash and bond collateral | (10,984) | (424) | 794 | |||
| Net proceeds from sales of assets | 6,970 | 476 | 16,014 | |||
| Net cash used in investing activities | (17,254) | (3,671) | (151,325) | |||
| Cash flows from financing activities: | ||||||
| Proceeds from long-term debt, net of debt issuance costs |
9,373 | - | 114,604 | |||
| Repayment of long-term debt | (14,561) | (13,753) | (12,053) | |||
| Net borrowings (repayments) of revolving lines of credit, net |
(1,500) | (9,000) | 11,000 | |||
| Repurchase of preferred shares | (213) | (244) | - | |||
| Dividends paid to minority shareholders of subsidiary | (1,010) | (1,240) | (1,100) | |||
| Exercise of stock options | 408 | 334 | 1,479 | |||
| Dividends on preferred shares | (575) | (248) | - | |||
| Net cash provided by (used in) financing activities | (8,078) | (24,151) | 113,930 | |||
| Net increase (decrease) in cash and cash equivalents | (578) | 4,612 | (8,960) | |||
| Cash and cash equivalents, beginning of year | 9,845 | 5,233 | 14,193 | |||
| Cash and cash equivalents, end of year | $ | 9,267 | $ | 9,845 | $ | 5,233 |
| Supplemental disclosures of cash flow information: | ||||||
| Cash paid during the year for: | ||||||
| Interest | $ | 9,814 | $ | 10,176 | $ | 8,340 |
| Income taxes | 737 | 886 | 1,209 | |||
See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.
62
The consolidated financial statements of Westmoreland Coal Company (the “Company”) include the accounts of the Company and its majority-owned subsidiaries, after elimination of intercompany balances and transactions. The Company uses the equity method of accounting for entities where its ownership is between 20% and 50% and for partnerships and joint ventures in which less than a controlling interest is held.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.
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, 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 are carried at cost and include expenditures for new facilities and those expenditures that substantially increase the productive lives of existing plant and equipment. Maintenance and repair costs are expensed as incurred. Mineral rights and development costs are depleted based upon estimated recoverable proven and probable reserves. Plant and equipment are depreciated on a units-of-production or straight-line basis over the assets’ estimated useful lives, ranging from 3 to 40 years. The Company assesses the carrying value of its property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing estimated undiscounted cash flows expected to be generated from such assets with their net book value. If net book value exceeds estimated cash flows, the asset is written down to fair value. When an asset is retired or sold, its cost and related accumulated depreciation and depletion are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss. Fully depreciated plant and equipment still in use are not eliminated from the accounts.
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Royalty payments made to lessors under terms of mineral lease agreements that are recoupable against future production are deferred. They are charged to expense as the leased coal reserves are mined.
The cost of removing overburden in advance of coal extraction, net of amounts reimbursed by customers, is deferred and charged to expense when the coal is produced.
Until June 30, 2002, the Company was reimbursed for all operating expenses at the Jewett Mine on a current basis under the cost-plus-fees contract with its customer. Beginning July 1, 2002, the contract changed to a market-based, fixed price per ton arrangement. At that date, in compliance with its accounting policy, the Company began deferring the cost of overburden removal in advance of coal extraction until such time that the underlying coal is produced and sold. The amount to be deferred was originally based on the number of tons of exposed coal in the active pits at each period end. In order to better estimate deferred stripping expenses and achieve a proper matching of expenses with the revenues from tons sold, a change in the engineering estimates was made in 2003 to measure overburden removed above all in-pit tons, not just exposed tons. The impact of this change was an increase of $2.4 million in deferred overburden removal costs. Prior to 2003, the measurement of overburden removed above in-pit tons was not available. Therefore, the potential impact, if any, on prior periods is not determinable. The change has been reflected as a change in estimate during 2003.
The Company is self-insured for workers’ compensation claims incurred prior to 1996 and for federal and state pneumoconiosis benefits for former employees. Workers’ compensation claims incurred after January 1, 1996 are covered by a third party insurance provider.
The liabilities for workers’ compensation claims and pneumoconiosis benefits are actuarially determined estimates of the ultimate losses incurred based on the Company’s experience, and include a provision for incurred but not reported losses. Adjustments to the probable ultimate liabilities are made annually based on subsequent developments and experience and are included in operations as incurred.
Certain of the Company’s customers have either agreed to reimburse the Company for reclamation expenditures as they are incurred or have pre-funded a portion of the expected reclamation costs. These funds will serve as sources for use in final reclamation activities. The total reclamation deposit of $52.8 million at December 31, 2003 consists of $11.7 million of cash and cash equivalents and $41.1 million of Federal agency bonds. The Company has the intent and ability to hold these securities to maturity, and, therefore, accounts for them as held-to-maturity securities. Held-to-maturity securities are recorded at amortized cost, adjusted for the amortization or accretion of premiums or discounts calculated on the effective interest method. Interest income is recognized when earned. In addition, the Company has recognized $23.1 million as contractual third party reclamation obligations, representing the present value of obligations of certain customers and a contract miner.
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The amortized cost, gross unrealized holding losses and fair value of held-to-maturity securities at December 31, 2003 are as follows (in thousands):
| Amortized cost | $ | 41,091 |
| Gross unrealized holding gains | 64 | |
| Gross unrealized holding losses | (854) | |
| Fair value | $ | 40,301 |
Maturities of held-to-maturity securities are as follows at December 31, 2003 (in thousands):
| Amortized Cost | Fair Value | |||
| Due in five years or less | $ | 17,580 | $ | 17,482 |
| Due after five years to ten years | 15,847 | 15,369 | ||
| Due in more than ten years | 7,664 | 7,450 | ||
| $ | 41,091 | $ | 40,301 | |
The Company accounts for health care and life insurance benefits provided for current and certain retired employees and their dependents by accruing the cost of such benefits over the service lives of employees. The Company is amortizing its transition obligation, for past service costs relating to these benefits, over twenty years. Unrecognized actuarial gains and losses are amortized over the estimated average remaining service period for active employee plans and over the estimated average remaining life for retiree plans. For UMWA represented union employees who retired prior to 1976, the Company provides similar medical and life insurance benefits by making payments to a multiemployer union trust fund. The Company expenses such payments when they become due.
The Company recognizes coal sales revenue at the time title passes to the customer in accordance with the terms of the underlying sales agreements.
On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”), a required new method of accounting for mine reclamation costs. Prior to the adoption of SFAS No. 143, reclamation costs were accrued on an undiscounted, units-of-production basis. SFAS No. 143 requires entities to record the fair value of asset retirement obligations using the present value of projected future cash flows, with an equivalent amount recorded as basis in the related long-lived asset. An accretion cost, representing the increase over time in the present value of the liability, is recorded each period and the capitalized cost is depreciated over the useful life of the related asset. As reclamation work is performed or liabilities are otherwise settled, the recorded amount of the liability is reduced.
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Changes in the Company’s asset retirement obligations from January 1, 2003 to December 31, 2003 (in thousands) were:
| Asset retirement obligation - January 1, 2003 | $ | 115,033 |
| Accretion | 7,815 | |
| Settlements (final reclamation performed) | (3,109) | |
| Gains on settlements | (265) | |
| Changes due to amount and timing of reclamation activities |
3,869 | |
| Asset retirement obligation - December 31, 2003 | $ | 123,343 |
As a result of the adoption of SFAS No. 143, in the first quarter of 2003 the Company recorded a gain of $161,000, net of tax expense of $108,000, for the cumulative effect of the change in accounting principle. The Company also reduced its recorded liability for mine reclamation from $159 million to $115 million as of January 1, 2003 and reduced the net book value of its property, plant and equipment from $189 million to $145 million on its Consolidated Balance Sheets as a result of the change from undiscounted to present values.
The Company accounts for deferred income taxes using the asset and liability method. Deferred tax liabilities and assets are recognized for the expected future tax consequences of events that have been reflected in the Company’s financial statements based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities, as well as operating loss and tax credit carryforwards, using enacted tax rates in effect in the years in which the differences are expected to reverse.
The Company is party to an interest rate swap agreement on the long-term debt at the Roanoke Valley I independent power project through a subsidiary which is accounted for under the equity method of accounting. In accordance with generally accepted accounting principles, the Company has reflected the difference between its 50% share of the fair value of this interest rate swap agreement and its carrying value as a separate component of shareholders’ equity. The swap agreement exchanged variable interest rates on debt for a fixed rate. Because market interest rates have declined below those provided for in the swap agreement, the fair value of the swap agreement has decreased. The change in current interest rates, net of income tax impacts, is a component of the Company’s total comprehensive income. If interest rates remain at their current levels, the Company will recognize its share of the loss in future periods as a reduction in equity in earnings of independent power projects.
During 2003 and 2002, the Company recognized an additional minimum pension liability as a result of the accumulated pension benefit obligation exceeding the fair value of pension plan assets at these dates. This additional minimum liability, net of income tax effect, is shown as a separate component of shareholders’ equity.
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The Company applies the intrinsic-value-based method of accounting prescribed by Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations, to account for its stock options. Under this method, compensation expense is recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123, Accounting for Stock-Based Compensation, established accounting and disclosure requirements using a fair-value-based method of accounting for stock-based employee compensation plans. As allowed under SFAS No. 123, the Company has elected to continue to apply the intrinsic-value-based method of accounting described above, and has adopted only the disclosure requirements of SFAS No. 123. The following table illustrates the effect on net income and net income per share as if the compensation cost for the Company’s stock options had been determined based on the fair value at the grant dates consistent with SFAS No. 123:
| 2003 | 2002 | 2001 | ||||
| (in thousands, except per share data) | ||||||
| Net income applicable to common shareholders: |
||||||
| As reported | $ | 10,842 | $ | 8,353 | $ | 3,451 |
| Pro forma | $ | 10,067 | $ | 6,698 | $ | 1,986 |
| Income per share applicable to common shareholders: |
||||||
| As reported, basic | $ | 1.39 | $ | 1.10 | $ | .48 |
| Pro forma, basic | $ | 1.29 | $ | .88 | $ | .26 |
| As reported, diluted | $ | 1.30 | $ | 1.03 | $ | .43 |
| Pro forma, diluted | $ | 1.21 | $ | .82 | $ | .25 |
The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for options granted in 2003, 2002 and 2001. The weighted average fair value of options granted in 2003, 2002 and 2001 was $11.88, $13.92 and $17.58, respectively.
| Options Granted | Dividend Yield | Volatility | Risk-Free Rate | Expected Life |
| 2003 | None | 100% | 4.17% | 10 years |
| 2002 | None | 229% | 5.04% | 10 years |
| 2001 | None | 272% | 5.14% | 10 years |
Basic earnings per share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share are determined on the same basis except that the weighted average shares outstanding are increased to include additional shares for the assumed exercise of stock options, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options were exercised and that the proceeds from such exercises were used to acquire shares of common stock at the average market price during the reporting period.
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The following table provides a reconciliation of the number of shares used to calculate basic and diluted earnings per share (EPS):
| 2003 | 2002 | 2001 | |
| Weighted average number of common shares outstanding: | (in thousands of shares) | ||
| Basic | 7,799 | 7,608 | 7,239 |
| Effect of dilutive instruments | 539 | 539 | 761 |
| Diluted | 8,338 | 8,147 | 8,000 |
| Number of shares not included in dilutive EPS that would have been antidilutive because the exercise or conversion price was greater than the average market price of the common shares. | 374 | 309 | 113 |
Certain prior year amounts have been reclassified to conform to the current year presentation.
In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003), Consolidated of Variable Interest Entities (“FIN 46R”), which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. FIN 46R replaces FASB Interpretation No. 46, Consolidation of Variable Interest Entities, which was issued in January 2003, The Company does not have interests in any variable interest entities and, therefore, will not be impacted by FIN 46R.
FASB Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, was issued in May 2003. This statement establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The statement also includes required disclosures for financial instruments within its scope. For the Company, the statement was effective for instruments entered into or modified after May 31, 2003 and otherwise will be effective as of January 1, 2004, except for mandatorily redeemable financial instruments. For certain mandatorily redeemable financial instruments, the statement will be effective for the Company of January 1, 2005. The effective date has been deferred indefinitely for certain other types of mandatorily redeemable financial instruments. The Company currently does not have any financial instruments that are within the scope of this statement.
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The Company’s current principal activities, all conducted within the United States, are: (i) the production and sale of coal from surface mines in Montana, North Dakota and Texas; and (ii) the development, ownership and management of interests in cogeneration and other non-regulated independent power plants. Prior to the sale of the Company’s interest in Dominion Terminal Associates (“DTA”), which was effective as of June 30, 2003, the Company was also engaged in the leasing of capacity at that coal storage and vessel loading facility. As described in Note 4, the Company’s share of DTA’s activities has been classified as discontinued operations in the Consolidated Statements of Operations.
On April 30, 2001 and May 11, 2001, respectively, the Company, through its wholly owned subsidiary Westmoreland Mining LLC (“WML”), completed the acquisitions of the coal business of Entech, Inc. (“Entech”), a wholly-owned subsidiary of the Montana Power Company (“Montana Power”) for approximately $136 million, and the coal operations of Knife River Corporation (“Knife River”) for approximately $27 million. The acquisitions were effective April 30, 2001. WML is a special purpose Delaware limited liability company formed on December 4, 2000 for the purpose of facilitating the financing of these acquisitions and operating the Rosebud, Jewett, Beulah and Savage mines. The results of operations relating to the acquisitions have been included in the Company’s consolidated financial statements beginning on May 1, 2001.
In the Entech, transaction, WML acquired the stock of Western Energy Company (“WECO”), which owns and operates the Rosebud Mine located in the Northern Powder River Basin, and Northwestern Resources Co. (“NWR”), which owns and operates the Jewett Mine in central Texas. In addition, the Company acquired the stock of three entities that were not engaged in active operations: Basin Resources, Inc.; Horizon Coal Services, Inc. (“Horizon”); and North Central Energy Company.
The final purchase price for the acquisition of Entech’s coal business is subject to adjustment pursuant to the terms of the Stock Purchase Agreement dated as of September 15, 2000 (the “Purchase Agreement”) between the Company and Entech. See further discussion of the status of the purchase price adjustment in Note 14.
The acquisitions were funded with $39 million in cash and borrowings of $125 million ($120 million term debt and $5 million revolving line of credit) by WML as described in Note 5.
Westmoreland Energy, LLC (“WELLC”), a wholly owned subsidiary of the Company, holds general and limited partner interests in partnerships which were formed to develop and own cogeneration and other non-regulated independent power plants. Equity interests in these partnerships range from 4.49 percent to 50 percent. As of December 31, 2003, WELLC held interests in three operating projects as listed and described in the summary below. The lenders to these projects have recourse only against these projects and the income and revenues therefrom. The debt agreements contain various restrictive covenants including restrictions on making cash distributions to the partners, with which the partnerships are in compliance. The type of restrictions on making cash distributions to the partners vary from one project lender to another.
69
| Project | Ft. Lupton | Roanoke Valley I |
Roanoke Valley II |
| Location: | Ft. Lupton, Colorado | Weldon, North Carolina |
Weldon, North Carolina |
| Gross Megawatt Capacity: | 290 MW | 180 MW | 50 MW |
| WELLC Equity Ownership: | 4.49% | 50.0% | 50.0% |
| Electricity Purchaser: | Public Service of Colorado | Dominion Virginia Power | Dominion Virginia Power |
| Steam Host: | Rocky Mtn. Produce, Ltd | Patch Rubber Company | Patch Rubber Company |
| Fuel Type: | Natural Gas | Coal | Coal |
| Fuel Supplier: | Thermo Fuels, Inc. | TECO Coal/ CONSOL | TECO Coal/ CONSOL |
| Commercial Operation Date: | 1994 | 1994 | 1995 |
The following is a summary of aggregated financial information for all investments owned by WELLC which are accounted for under the equity method:
| Balance Sheets | ||||
| December 31, | 2003 | 2002 | ||
| (in thousands) | ||||
| Assets | ||||
| Current assets | $ | 38,549 | $ | 40,282 |
| Property, plant and equipment, net | 246,796 | 255,364 | ||
| Other assets | 25,267 | 25,171 | ||
| Total assets | $ | 310,612 | $ | 320,817 |
| Liabilities and equity | ||||
| Current liabilities | $ | 29,884 | $ | 29,500 |
| Long-term debt and other liabilities | 209,979 | 231,922 | ||
| Equity | 70,749 | 59,395 | ||
| Total liabilities and equity | $ | 310,612 | $ | 320,817 |
| WELLC’s share of equity | $ | 38,487 | $ | 33,407 |
| Income Statements | ||||||
| For years ended December 31, | 2003 | 2002 | 2001 | |||
| (in thousands) | ||||||
| Revenues | $ | 110,673 | $ | 110,075 | $ | 124,946 |
| Operating income | 45,918 | 46,731 | 72,209 | |||
| Net income | 30,446 | 28,935 | 33,003 | |||
| WELLC’s share of earnings | $ | 15,242 | $ | 14,506 | $ | 15,871 |
70
WELLC performs asset management services for the partnerships and has recognized related revenues of $258,000, $258,000 and $267,000 for the years ended December 31, 2003, 2002 and 2001, respectively. Management fees, net of related costs, are recorded as other income when the service is performed.
Prior to June 30, 2003, the Company had a 20% interest in DTA, a partnership which operates a coal-storage and vessel-loading facility in Newport News, Virginia. Due to declining export business, the Company’s original investment in DTA was written down from $17.6 million to $5.5 million in 1998. The Company’s loss from operations at DTA in more recent years was the revenue received from the lease of its facilities and throughput, net of its share of the expenses incurred attributable to the terminal’s operations. The Company recognized a further non-cash impairment charge equal to the remaining book value of its investment in DTA during the third quarter of 2002 as a result of the terminal’s continuing operating losses and the terms of an agreement by one of the terminal’s other owners to dispose of its interest in DTA, but the Company continued to share in cash operating expenses and recognize losses until the sale of its own interest was completed.
Effective June 30, 2003, a subsidiary of Dominion Resources, Inc. purchased for $10.5 million the Company’s 20% partnership interest in DTA and its industrial revenue bonds. Under the terms of the Purchase and Sale Agreement, the Company guaranteed throughput at the terminal for a period of three years from the effective date of the sale. To secure the throughput commitment, $6.0 million of the purchase price was deposited into an escrow account as collateral for a stand-by letter of credit for the benefit of the purchaser. The Company does not expect to be able to deliver the minimum throughput. The Company also provided customary representations and warranties. The Company has guaranteed its obligations under the Purchase and Sale Agreement for a period of five years.
With the closing of this transaction the Company no longer incurs DTA-related operating losses, which were $1.0 million, $2.1 million and $1.9 million in 2003, 2002 and 2001, respectively. The Company also recognized a $4.5 million pretax gain in the second quarter of 2003.
As a result of the sale of the Company’s investment, the financial results relating to DTA have been presented as Discontinued Operations in the accompanying Consolidated Statements of Operations. The basic income (loss) per share from these discontinued operations, including the gain on sale, were $.27, ($.47) and ($.16) for the years ended December 31, 2003, 2002 and 2001, respectively. The diluted income (loss) per share from these discontinued operations was $.25, ($.47) and ($.16) per share for 2003, 2002 and 2001, respectively.
71
The amounts outstanding at December 31, 2003 and 2002 under the Company’s lines of credit and long-term debt consist of the following:
| 2003 | 2002 | |||
| (in thousands) | ||||
| WML revolving line of credit | $ | - | $ | 1,500 |
| WML term debt | 88,500 | 96,300 | ||
| Corporate revolving line of credit | 500 | 500 | ||
| Other term debt | 4,469 | 1,857 | ||
| 93,469 | 100,157 | |||
| Less current portion | (11,595) | (8,852) | ||
| $ | 81,874 | $ | 91,305 | |
As of December 31, 2003, WML had a $20 million revolving credit facility with PNC Bank, National Association (“PNC”), as Agent, and three participating banks which has been replaced by a new facility described below. The interest rate was either PNC’s Base Rate plus 1.60% or Euro-Rate plus 3.10%, at WML’s option.
On March 8, 2004, WML entered into an amended $12 million revolving facility (the “Facility”) solely with PNC which expires on April 27, 2007. The interest rate is either PNC’s Base Rate plus 1.50% or Euro-Rate plus 3.00%, at WML’s option. In addition, a commitment fee of ½ of 1% of the average unused portion of the available credit is payable quarterly. The amount available under the Facility is based upon, and any outstanding amounts are secured by, eligible accounts receivable.
In 2001, WML borrowed $120 million from a group of institutions using PNC Capital Markets, Inc. as lead arranger to fund the acquisitions described in Note 2. The borrowings consisted of $20 million in variable-rate Series A Notes and $100 million in fixed-rate Series B Notes. The Series A Notes were repaid in full on June 30, 2002. The Series B Notes bear interest at a rate of 9.39% and require quarterly principal and interest payments from September 2002 to December 2008, when the remaining outstanding balance of $30.0 million is due. The Series B Notes are secured by assets of WML.
Both the revolving line of credit and the term notes contain various covenants which limit WML or its subsidiaries’ ability to merge or consolidate with another entity, dispose of assets, pay dividends, or change the nature of business operations. WML is also required to maintain certain financial ratios as defined in the agreements. Further, pursuant to these agreements any purchase price adjustment from the Montana Power transaction which is paid to WML must be used to repay any amounts outstanding under the Facility and in certain circumstances fund a debt service reserve account. As of December 31, 2003, WML was in compliance with such covenants.
Under the terms of the Series B Notes, WML is required to maintain a debt service reserve account equal to the principal and interest payments and certain fees scheduled to become due within the next six months. In addition, 25% of any “Surplus Cash Flow” (as such term is defined in the agreement) is applied to a prepayment account for repayment of the final $30 million of indebtedness and 75% of any Surplus Cash Flow is available to WML. WML may distribute such Surplus Cash Flow to the Company so long as no Event of Default or Potential Event of Default under the term loan agreement exists or is likely to result from the distribution. The quarterly distribution is in addition to a quarterly $500,000 management fee that WML pays the Company. At December 31, 2003, WML had funded $8.8 million in the debt service reserve account, which could be used for principal and interest payments, and $8.7 million in the long-term prepayment account. Those funds have been classified as restricted cash in the consolidated balance sheet.
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On March 8, 2004, WML amended its term debt to borrow an additional $35 million in $20.4 million Series C Notes and $14.6 million Series D Notes. The Series C Notes were drawn immediately and the Series D Notes will be borrowed after seven months but no later than December 31, 2004. Both notes require quarterly interest payments with principal payments beginning March 31, 2009 and final payment on December 31, 2011. The Series C Notes bear interest at a fixed rate of 6.85%, and the Series D Notes have a variable rate based upon LIBOR plus 2.90%. The new notes are secured by assets of WML and require the same covenants and financial ratios, as amended, as the Series A and B Notes.
The Company has a $10.0 million revolving credit agreement with First Interstate Bank. Interest is payable monthly at the Bank’s prime rate plus 1% (5.00% at December 31, 2003). The Company is required to maintain certain financial ratios. The revolving credit agreement is collateralized by the Company’s stock in WRI, 100% of the common stock of Horizon, and the dragline located at WRI’s Absaloka Mine in Big Horn County, Montana. The expiration date is January 24, 2005.
Other term debt consists of notes payable assumed in the 2001 acquisitions, certain notes payable related to the purchase of real property, and capital lease obligations for mining equipment. These obligations expire at various dates through 2009 and bear interest at a weighted-average rate of 5.65%.
The maturities of all long-term debt and the revolving credit facilities outstanding at December 31, 2003 are (in thousands):
| 2004 | $ | 11,595 |
| 2005 | 12,174 | |
| 2006 | 11,995 | |
| 2007 | 12,625 | |
| 2008 | 44,980 | |
| Thereafter | 100 | |
| $ | 93,469 | |
The Company was self-insured for workers’ compensation benefits prior to and through December 31, 1995. Beginning in 1996, the Company purchased third party insurance for new workers’ compensation claims. Based on updated actuarial and claims data, $834,000, $449,000, and $642,000 were charged to operations in 2003, 2002 and 2001, respectively. The cash payments for workers’ compensation benefits were $2.1 million, $2.8 million and $2.9 million in 2003, 2002 and 2001, respectively.
The Company was required to obtain surety bonds in connection with its self-insured workers’ compensation plan. The Company’s surety bond underwriters required collateral for such bonding. As of December 31, 2003 and 2002, $4.4 million and $4.0 million respectively, were held in the collateral accounts.
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The Company is self-insured for federal and state pneumoconiosis benefits for former employees and has established an independent trust to pay these benefits.
The following table sets forth the funded status of the Company’s obligation:
| December 31, | 2003 | 2002 | ||
| (in thousands) | ||||
| Actuarial present value of benefit obligation: | ||||
| Expected claims from terminated employees | $ | 1,593 | $ | 2,330 |
| Claimants | 20,368 | 20,454 | ||
| Total present value of benefit obligation | 21,961 | 22,784 | ||
| Plan assets at fair value, primarily government-backed | ||||
| securities | 28,195 | 30,449 | ||
| Excess of trust assets over pneumoconiosis benefit | ||||
| obligations | $ | 6,234 | $ | 7,665 |
The discount rates used in determining the accumulated pneumoconiosis benefit as of December 31, 2003 and 2002 were 6.25% and 6.75%, respectively.
The Company and its subsidiaries provide certain health care and life insurance benefits for retired employees and their dependents either voluntarily or as a result of the Coal Act. Substantially all of the Company’s current employees may also become eligible for these benefits if certain age and service requirements are met at the time of termination or retirement as specified in the plan document. The majority of these benefits are provided through self-insured programs. The Company adopted Statement of Financial Accounting Standards No. 106 – Employers’ Accounting for Postretirement Benefits Other than Pensions (SFAS 106) effective January 1, 1993 and elected to amortize its unrecognized, unfunded accumulated postretirement benefit obligation over a 20-year period.
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The following table sets forth the actuarial present value of postretirement medical and life insurance benefit obligations and amounts recognized in the Company’s financial statements:
| December 31, | 2003 | 2002 | ||
| (in thousands) | ||||
| Assumptions: | ||||
| Discount rate | 6.25% | 6.75% | ||
| Change in benefit obligation: | ||||
| Net benefit obligation at beginning of year | $ | 223,478 | $ | 205,564 |
| Service cost | 446 | 400 | ||
| Interest cost | 15,693 | 14,989 | ||
| Plan amendments | (667) | - | ||
| Plan participant contributions | 81 | 67 | ||
| Actuarial loss | 13,253 | 18,882 | ||
| Gross benefits paid | (14,730) | (16,424) | ||
| Net benefit obligation at end of year | 237,554 | 223,478 | ||
| Change in plan assets: | ||||
| Employer contributions | 14,649 | 16,357 | ||
| Plan participant contributions | 81 | 67 | ||
| Gross benefits paid | (14,730) | (16,424) | ||
| Fair value of plan assets at end of year | - | - | ||
| Funded status at end of year | (237,554) | (223,478) | ||
| Unrecognized net actuarial loss | 73,407 | 65,353 | ||
| Unrecognized net transition obligation | 36,902 | 41,002 | ||
| Net amount recognized at end of year | $ | (127,245) | $ | (117,123) |
The components of net periodic postretirement benefit cost are as follows:
| Year ended December 31, | 2003 | 2002 | 2001 | |||
| (in thousands) | ||||||
| Assumptions: | ||||||
| Discount rate | 6.75% | 7.25% | 7.50% | |||
| Components of net periodic benefit cost: | ||||||
| Service cost | $ | 446 | $ | 400 | $ | 227 |
| Interest cost | 15,693 | 14,989 | 12,327 | |||
| Amortization of: | ||||||
| Transition obligation | 4,100 | 4,100 | 4,100 | |||
| Actuarial loss | 4,532 | 2,899 | 861 | |||
| Total net periodic benefit cost | $ | 24,771 | $ | 22,388 | $ | 17,515 |
Of the total net periodic benefit cost, $23.4 million, $21.1 million and $16.7 million, relates to the Company’s former eastern mining operations and is included in heritage health benefit costs in 2003, 2002 and 2001, respectively. The remainder of $1.4 million, $1.3 million and $0.8 million, respectively, relates to current operations.
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| Sensitivity of retiree
welfare results (in thousands): |
||
| Effect of a one percentage point increase in assumed ultimate health care cost trend |
||
| - - on total service and interest cost components | $ | 1,658 |
| - - on postretirement benefit obligation | $ | 25,318 |
| Effect of a one percentage point decrease in | ||
| assumed ultimate health care cost trend | ||
| - - on total service and interest cost components | $ | (1,401) |
| - - on postretirement benefit obligation | $ | (21,514) |
The health care cost trend assumed on covered charges was 8.50%, 9.25% and 10.0% for 2003, 2002 and 2001, respectively, decreasing to an ultimate trend of 5.0% in 2009 and beyond.
In December 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the “Act”) became law in the United States. The Act introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare benefit. Currently, the Company does not believe it will need to amend its plan to benefit from Medicare benefit provided under the Act. The Company has reflected the estimated impact of the Act as a $16.5 million reduction in the present value of the accumulated post-retirement benefit obligation as of December 31, 2003. However, the impact of the Act is not reflected in the net periodic benefit cost for 2003. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require the Company to change previously reported information.
Based on the same assumptions used in measuring the Company’s benefit obligation at December 31, 2003, the Company expects to pay benefits in each year 2004-2008 of $17.4 million, $18.2 million, $17.4 million, $18.0 million and $18.2 million, respectively. The aggregate benefits expected to be paid in the five-years from 2009-2013 are $92.5 million.
The Company makes payments to the Combined Benefit Fund (“CBF”), which is a multiemployer health plan neither controlled nor administered by the Company. The CBF is designed to pay benefits to UMWA workers (and dependents) who retired prior to 1976. The Company is required by the Coal Act to make monthly premium payments into the CBF. These payments are based on the number of beneficiaries assigned to the Company, the Company’s UMWA employees who retired prior to 1976 and the Company’s pro-rata assigned share of UMWA retirees whose companies are no longer in business. The net present value of the Company’s future cash payments is estimated to be approximately $39.8 million at December 31, 2003. The Company expenses payments to the CBF when they are due. Payments are generally made on the due date. Payments in 2003, 2002 and 2001 were $5.3 million, $5.2 million and $5.7 million, respectively. See Note 14 to the Consolidated Financial Statements for additional information.
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The Company provides defined benefit pension plans for its full-time employees. Benefits are generally based on years of service and the employee’s average annual compensation for the highest five continuous years of employment as specified in the plan agreement. The Company’s funding policy is to contribute annually the minimum amount prescribed, as specified by applicable regulations. Prior service costs and actuarial gains and losses are amortized over plan participants’ expected future period of service using the straight-line method.
Effective January 1, 1992, the Company adopted the Westmoreland Coal Company Supplemental Executive Retirement Plan (“SERP”). The SERP is an unfunded non-qualified deferred compensation plan which provides benefits to certain employees that are not eligible under the Company’s defined benefit pension plan beyond the maximum limits imposed by the Employee Retirement Income Security Act (“ERISA”) and the Internal Revenue Code.
The following table provides a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the periods ended December 31, 2003 and 2002 and the amounts recognized in the Company’s financial statements for both the defined benefit pension and SERP Plans:
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| Qualified Pension Benefits | SERP Benefits | |||||||
| December 31, | 2003 | 2002 | 2003 | 2002 | ||||
| (in thousands) | ||||||||
| Assumptions: | ||||||||
| Discount rate | 6.25% | 6.75% | 6.25% | 6.75% | ||||
| Expected return on plan assets | 8.50% | 9.00% | 8.50% | 9.00% | ||||
| Rate of compensation increase | 4.50% | 4.50% | 5.00% | 5.00% | ||||
| Change in benefit obligation: | ||||||||
| Net benefit obligation at beginning of year | $ | 41,366 | $ | 33,544 | $ | 2,626 | $ | 1,503 |
| Service cost | 2,138 | 1,943 | 59 | 76 | ||||
| Interest cost | 2,839 | 2,556 | 127 | 170 | ||||
| Actuarial (gain) loss | 2,638 | 3,513 | (773) | 953 | ||||
| Gross benefits paid | (1,204) | (190) | (76) | (76) | ||||
| Net benefit obligation at end of year | 47,777 | 41,366 | 1,963 | 2,626 | ||||
| Change in plan assets: | ||||||||
| Fair value of plan assets at beginning of year | 30,147 | 33,593 | - | - | ||||
| Actual return on plan assets | 3,905 | (3,334) | - | - | ||||
| Employer contributions | - | 78 | 76 | 76 | ||||
| Gross benefits paid | (1,204) | (190) | (76) | (76) | ||||
| Fair value of plan assets at end of year | 32,848 | 30,147 | - | - | ||||
| Funded status at end of year | (14,929) | (11,219) | (1,963) | (2,626) | ||||
| Unrecognized net actuarial (gain) loss | 14,659 | 14,271 | (310) | 532 | ||||
| Unrecognized prior service cost | 105 | 154 | 75 | 74 | ||||
| Unrecognized net transition asset | (4) | (10) | - | - | ||||
| Net amount recognized at end of year | (169) | 3,196 | (2,198) | (2,020) | ||||
| Amounts recognized in the accompanying balance sheet consist of: | ||||||||
| Accrued benefit cost | (169) | 3,196 | (2,198) | (2,020) | ||||
| Minimum pension liability | (6,717) | (5,517) | - | - | ||||
| Net amount recognized at end of year | $ | (6,886) | $ | (2,321) | $ | (2,198) | $ | (2,020) |
The components of net periodic pension cost (benefit) are as follows:
| Qualified Pension Benefits | SERP Benefits | |||||||||||
| Year ended December 31, | 2003 | 2002 | 2001 | 2003 | 2002 | 2001 | ||||||
| (in thousands) | ||||||||||||
| Assumptions: | ||||||||||||
| Discount rate | 6.75% | 7.25% | 7.50% | 6.75% | 7.25% | 7.50% | ||||||
| Expected return on plan assets | 8.50% | 9.00% | 9.00% | N/A | N/A | N/A | ||||||
| Rate of compensation increase | 4.50% | 4.50% | 4.50% | 5.00% | 5.00% | 5.00% | ||||||
| Components of net periodic benefit cost | ||||||||||||
| Service cost | $ | 2,139 | $ | 1,943 | $ | 1,238 | $ | 59 | $ | 76 | $ | 52 |
| Interest cost | 2,839 | 2,556 | 1,551 | 127 | 170 | 105 | ||||||
| Expected return on assets | (2,393) | (2,975) | (2,275) | - | - | - | ||||||
| Amortization of: | ||||||||||||
| Transition asset | (6) | (6) | (6) | - | - | - | ||||||
| Prior service cost | 50 | 50 | 42 | 84 | 76 | 116 | ||||||
| Actuarial (gain) loss | 803 | 97 | - | (16) | 22 | (40) | ||||||
| Total net periodic pension cost | $ | 3,432 | $ | 1,665 | $ | 550 | $ | 254 | $ | 344 | $ | 233 |
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The weighted-average asset allocation of the Company’s qualified pension trusts at December 31, 2003 and 2002 was as follows:
| Allocation of Plan Assets at December 31 |
||||
| Asset Category | 2003 | 2002 | Target Allocation | |
| Cash and equivalents | -% | 11% | 0%-25% | |
| Equity securities | 70% | 51% | 40%-75% | |
| Debt securities | 29% | 38% | 0%-50% | |
| Other | 1% | -% | 0%-10% | |
| Total | 100% | 100% | ||
The Company’s investment goals are to maximize returns subject to specific risk management policies. Its risk management policies permit investments in mutual funds, and prohibit direct investments in debt and equity securities and derivative financial instruments. The Company addresses diversification by the use of mutual fund investments whose underlying investments are in domestic and international fixed income securities and domestic and international equity securities. These mutual funds are readily marketable and can be sold to fund benefit payment obligations as they become payable.
The Company expects to contribute $1.7 million to its qualified pension plans and $76,000 to its SERP in 2004.
The benefits expected to be paid in each year 2004-2008 are $532,000, $670,000, $903,000, $1.2 million and $1.6 million, respectively. The aggregate benefits expected to be paid in the five years from 2009-2013 are $14.0 million. The expected benefits are based on the same assumptions used to measure the company’s benefit obligation at December 31 and include estimated future employee service.
The Company was required under the 1993 Wage Agreement to pay amounts based on hours worked or tons processed (depending on the source of the coal) in the form of contributions to the 1974 UMWA Pension Plan with respect to UMWA represented employees. The 1974 UMWA Pension Plan is a multiemployer plan under ERISA.
Under the Multiemployer Pension Plan Act (“MPPA”), a company contributing to a multiemployer plan is liable for its share of unfunded vested liabilities upon withdrawal from the plan. That withdrawal occurred for the Company with the cessation of eastern mining operations, its only operations at that time which utilized UMWA employees.. In 1996, the Company recorded its withdrawal liability, which was estimated by the 1974 UMWA Pension Plan at $13.8 million. The Company disputed the amount of this obligation through arbitration. In accordance with MPPA, the Company amortized this withdrawal liability, with interest, during the arbitration process by making payments of approximately $172,500 per month. The final phase of the arbitration was scheduled for April 2004. On March 8, 2004, the Company reached a settlement agreement with the 1974 UMWA Pension Plan whereby its obligation was considered fully repaid after making the monthly payment in February 2004. As a result, the Company reduced the recorded amount of its obligation and reduced the amount of its heritage health benefit costs for 2003 by $6.3 million. No further contributions will be required.
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Income tax expense (benefit) attributable to income (loss) before income taxes consists of:
| 2003 | 2002 | 2001 | ||||||||
| (in thousands) | ||||||||||
| Current: | ||||||||||
| Federal | $ | 25 | $ | - | $ | - | ||||
| State | 251 | 900 | 908 | |||||||
| 276 | 900 | 908 | ||||||||
| Deferred: | ||||||||||
| Federal | (9,599) | (5,605) | (120) | |||||||
| State | (132) | (51) | (352) | |||||||
| (9,731) | (5,656) | (472) | ||||||||
| Income tax expense (benefit) | $ | (9,455) | $ | (4,756) | $ | 436 | ||||
Income tax expense (benefit) attributable to income (loss) before income taxes differed from the amounts computed by applying the statutory Federal income tax rate of 34% to pretax income as a result of the following:
| 2003 | 2002 | 2001 | ||||
| (in thousands) | ||||||
| Computed tax expense (benefit) at statutory rate | $ | 1,067 | $ | 1,825 | $ | 1,925 |
| Increase (decrease) in tax expense resulting from: | ||||||
| Tax depletion in excess of book | (2,865) | (3,399) | (2,412) | |||
| Minority interest adjustment | 263 | 272 | 265 | |||
| State income taxes, net | 78 | 720 | 842 | |||
| Change in valuation allowance | ||||||
| relating to Federal income taxes | (7,768) | (4,149) | - | |||
| Other, net | (230) | (25) | (184) | |||
| Income tax expense (benefit) | $ | (9,455) | $ | (4,756) | $ | 436 |
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The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2003 and 2002 are presented below:
| 2003 | 2002 | |||
| Deferred tax assets: | (in thousands) | |||
| Federal net operating loss carryforwards | $ | 61,326 | $ | 58,874 |
| State net operating loss carryforwards | 6,160 | 6,035 | ||
| Alternative minimum tax credit carryforwards | 2,632 | 2,608 | ||
| Accruals for the following: | ||||
| Workers' compensation | 3,791 | 4,296 | ||
| Postretirement benefit and pension obligations | 49,601 | 43,336 | ||
| Asset retirement obligations | 13,397 | 7,532 | ||
| 1974 UMWA pension plan obligation | 100 | 3,214 | ||
| Other accruals | 5,273 | 4,722 | ||
| Total gross deferred assets | 142,280 | 130,617 | ||
| Less valuation allowance | (25,058) | (32,574) | ||
| Net deferred tax assets | 117,222 | 98,043 | ||
| Deferred tax liabilities: | ||||
| Investment in independent power projects | $ | (12,273) | $ | (14,964) |
| Plant and equipment, differences due to depreciation and amortization |
(26,668) | (14,929) | ||
| Excess of trust assets over pneumoconiosis benefit obligation | (2,494) | (3,066) | ||
| Total gross deferred tax liabilities | (41,435) | (32,959) | ||
| Net deferred tax asset | $ | 75,787 | $ | 65,084 |
The net deferred tax asset is presented on the consolidated balance sheets at December 31, as follows:
| 2003 | 2002 | |||
| (in thousands) | ||||
| Deferred income tax assets - current | $ | 12,921 | $ | 15,831 |
| Deferred income tax assets - long-term | 62,866 | 49,253 | ||
| $ | 75,787 | $ | 65,084 | |
An income tax benefit of $484,000, $160,000 and $989,000 related to the exercise of stock options during 2003, 2002 and 2001, respectively, was added to other paid-in capital.
As of December 31, 2003, a minimum of $180.4 million of future taxable income will be necessary to enable the Company to fully utilize the net operating loss carryforwards and realize gross deferred tax assets of $142.3 million. As of December 31, 2003, the Company has available Federal net operating loss carryforwards to reduce future taxable income which expires as follows:
| Expiration Date | Regular Tax | |
| (in thousands) | ||
| 2010 | $ | 45,809 |
| 2011 | 36,479 | |
| 2012 | 449 | |
| 2018 | 531 | |
| 2019 | 88,429 | |
| after 2019 | 8,673 | |
| Total | $ | 180,370 |
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Current tax expense results from Federal Alternative Minimum Tax and estimated state income taxes. The deferred income tax benefit recorded for 2003 included a benefit of $7.8 million due to a reduction in the deferred income tax asset valuation allowance as a result of an increase in the amount of Federal net operating loss carryforwards the Company expects to use prior to their expiration through 2019. The increase in the expected amount of Federal net operating losses to be used in future years is primarily a result of an extension of an existing coal sales contract entered into during 2003, the agreement reached with the customer of the Company’s Jewett Mine providing certainty of volumes and pricing through 2007 and the settlement of the withdrawal liability issue with the 1974 UMWA Retirement Plan. The terms of the extended contract call for deliveries of 1.5 to 2.5 million tons per year from 2004 through 2008. In addition, the deferred income tax benefit for 2003 reflects the generation of additional deferred tax assets during the period due to temporary differences related to the timing of book expenses versus tax deductions. The deferred income tax benefit recorded for 2002 included a benefit of $4.1 million for a reduction in the valuation allowance as a result of anticipated increased use of future net operating loss carryforwards.
The Company has alternative minimum tax credit carryforwards of $2.6 million which are available indefinitely to offset future Federal taxes payable. For Alternative Minimum Tax purposes, the Company has net operating loss carryforwards of approximately $34.8 million as of December 31, 2003. As of December 31, 2003, the Company also has available an estimated $14.1 million in net operating loss carryforwards in Colorado to reduce future taxable income.
Each depositary share represents one-quarter of a share of Westmoreland’s Series A Convertible Exchangeable Preferred Stock. Dividends at a rate of 8.5% per annum were previously paid quarterly but were last suspended in the third quarter of 1995 pursuant to the requirements of Delaware law, described below, as a result of recognition of net losses, the violation of certain bank covenants, and a subsequent shareholders’ deficit. The full amount of the quarterly dividend is $2.125 per preferred share or $0.53 per depositary share. Westmoreland commenced a partial payment of dividends to preferred shareholders on October 1, 2002 as described below. The quarterly dividends which are accumulated but unpaid through and including January 1, 2004 amount to $15.3 million in the aggregate ($74.62 per preferred share or $18.65 per depositary share). Common stock dividends may not be declared until the preferred stock dividends that are accumulated but unpaid are made current.
There are statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which Westmoreland is incorporated. Under Delaware law, Westmoreland is permitted to pay preferred stock dividends only: (1) out of surplus, surplus being the amount of shareholders’ equity in excess of the par value of Westmoreland’s two classes of stock; or (2) in the event there is no surplus, out of net profits for the fiscal year in which a preferred stock dividend is declared (and/or out of net profits from the preceding fiscal year), but only to the extent that shareholders’ equity exceeds the par value of the preferred stock (which par value was $205,000 at December 31, 2003). The Company had shareholders’ equity of $33.3 million and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $20.1 million at December 31, 2003.
The Board of Directors regularly reviews the subjects of current preferred stock dividends and the accumulated unpaid preferred stock dividends, and is committed to meeting its obligations to the preferred shareholders in a manner consistent with the best interests of all shareholders. Quarterly dividends of $0.15 per depositary share were commenced beginning October 1, 2002 and increased to $0.20 per depositary share beginning October 1, 2003.
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On August 9, 2002 Westmoreland’s Board of Directors authorized the repurchase of up to 10% of the outstanding depositary shares on the open market or in privately negotiated transactions with institutional and accredited investors between then and the end of 2004. The timing and amount of depositary shares repurchased will be determined by the Company’s management based on its evaluation of the Company’s capital resources, the price of the depositary shares offered to the Company and other factors. Any acquired shares will be converted into shares of Series A Convertible Exchangeable Preferred Stock and retired. The repurchase program will be funded from working capital which may be currently available, or become available to the Company. Since the commencement of the depositary share purchase program, Westmoreland has purchased a total of 14,500 depositary shares for aggregate consideration of $457,000, including 7,000 shares purchased in 2003 for $213,000.
As of December 31, 2003, the Company had options outstanding from four shareholder-approved Incentive Stock Option (“ISOs”) Plans for employees and three Incentive Stock Option Plans for directors.
The employee plans provide for the granting of ISO’s, non-qualified options under certain circumstances, stock appreciation rights and restricted stock. ISO’s generally vest over two years, expire ten years from the date of grant, and may not have an option price that is less than the market value of the stock on the date of grant. The maximum number of shares that could be issued or granted under these plans is 1,550,000, and as of December 31, 2003, 193,806 shares are available for future issue or grant.
The non-employee director plans generally allow the grant of options for 20,000 shares when elected or appointed, and options for 10,000 shares after each annual meeting. Beginning in 2003, rather than the grant of 10,000 options, each non-employee director was granted $30,000 worth of common shares which are restricted for one year from the date of grant. The maximum number of shares that could be issued or granted under these plans is 900,000, and as of December 31, 2003, 44,832 shares are available for future issue or grant.
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Information for 2003, 2002 and 2001 with respect to both the employee and director Plans is as follows:
| Issue Price Range | Stock Option Shares | Weighted Average Exercise Price | |
| Outstanding at December 31, 2000 | $ 2.63-20.00 | 1,174,800 | $ 3.64 |
| Granted in 2001 | 12.04-8.19 | 145,500 | 17.58 |
| Exercised in 2001 | 2.81-8.75 | (371,450) | 3.99 |
| Expired or forfeited in 2001 | 2.63-20.00 | (56,500) | 5.53 |
| Outstanding at December 31, 2001 | 2.63-18.19 | 892,350 | 5.51 |
| Granted in 2002 | 12.86-15.31 | 183,600 | 13.93 |
| Exercised in 2002 | 2.63-12.38 | (77,900) | 4.28 |
| Outstanding at December 31, 2002 | 2.63-18.19 | 998,050 | 7.17 |
| Granted in 2003 | 10.48-18.08 | 189,350 | 17.08 |
| Exercised in 2003 | 2.81-12.86 | (114,700) | 3.56 |
| Expired or forfeited in 2003 | 12.86-18.19 | (23,300) | 15.11 |
| Outstanding at December 31, 2003 | $ 2.63-18.19 | 1,049,400 | $ 9.22 |
Information about stock options outstanding as of December 31, 2003 is as follows:
| Range of Exercise Price | Number Outstanding | Weighted- Average Remaining Contractual Life (Years) | Weighted- Average Exercise Price |
Number Exercisable | Weighted- Average Exercise Price |
| $2.63 - 5.00 | 520,100 | 4.9 | $ 2.92 | 502,600 | $ 2.91 |
| 5.01-10.00 | 40,000 | 6.9 | 7.41 | 30,000 | 7.41 |
| 10.01-15.00 | 125,635 | 8.4 | 12.35 | 63,435 | 12.56 |
| 15.01-18.19 | 363,665 | 8.7 | 17.36 | 98,465 | 17.50 |
| $2.63-18.19 | 1,049,400 | 6.7 | $9.22 | 694,500 | $ 6.06 |
The Company’s operations have been classified into two segments: coal and independent power operations. The coal segment includes the production and sale of coal from Montana, North Dakota and Texas. The independent power operations include the ownership of interests in cogeneration and other non-regulated independent power plants. The “Corporate” classification noted in the tables represents all costs not otherwise classified, including corporate office charges, heritage health benefit costs and business development expenses. Summarized financial information by segment for 2003, 2002 and 2001 is as follows:
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| Coal | Independent Power | Corporate | Total | |||||
| (in thousands) | ||||||||
| Revenues: | ||||||||
| Coal | $ | 294,986 | $ | - | $ | - | $ | 294,986 |
| Equity in earnings | - | 15,824 | - | 15,824 | ||||
| 294,986 | 15,824 | - | 310,810 | |||||
| Costs and expenses: | ||||||||
| Cost of sales – coal | 228,433 | - | - | 228,433 | ||||
| Depreciation, depletion | ||||||||
| and amortization | 12,451 | 22 | 126 | 12,599 | ||||
| Selling and administrative | 23,626 | 1,013 | 8,747 | 33,386 | ||||
| Heritage health benefit | ||||||||
| costs | - | - | 29,922 | 29,922 | ||||
| Gain on sales of assets | (194) | - | (451) | (645) | ||||
| Operating income (loss) from continuing operations |
$ | 30,670 | $ | 14,789 | $ | (38,344) | $ | 7,115 |
| Capital expenditures | $ | 13,110 | $ | 1 | $ | 129 | $ | 13,240 |
| Property, plant and | ||||||||
| equipment (net) | $ | 150,887 | $ | 48 | $ | 414 | $ | 151,349 |
| Coal | Independent Power | Corporate | Total | |||||
| (in thousands) | ||||||||
| Revenues: | ||||||||
| Coal | $ | 301,235 | $ | - | $ | - | $ | 301,235 |
| Equity in earnings | - | 14,506 | - | 14,506 | ||||
| 301,235 | 14,506 | - | 315,741 | |||||
| Costs and expenses: | ||||||||
| Cost of sales – coal | 226,707 | - | - | 226,707 | ||||
| Depreciation, depletion | ||||||||
| and amortization | 11,430 | 13 | 96 | 11,539 | ||||
| Selling and administrative | 23,058 | 939 | 8,251 | 32,248 | ||||
| Heritage health benefit | ||||||||
| costs | - | - | 26,921 | 26,921 | ||||
| Doubtful account recoveries | (516) | - | - | (516) | ||||
| Loss on sales of assets | 9 | - | - | 9 | ||||
| Operating income (loss) from continuing operations |
$ | 40,547 | $ | 13,554 | $ | (35,268) | $ | 18,833 |
| Capital expenditures | $ | 7,196 | $ | 45 | $ | 82 | $ | 7,323 |
| Property, plant and | ||||||||
| equipment (net) | $ | 188,154 | $ | 69 | $ | 1,309 | $ | 189,532 |
85
| Coal | Independent Power | Corporate | Total | |||||
| (in thousands) | ||||||||
| Revenues: | ||||||||
| Coal | $ | 231,048 | $ | - | $ | - | $ | 231,048 |
| Equity in earnings | - | 15,871 | - | 15,871 | ||||
| 231,048 | 15,871 | - | 246,919 | |||||
| Costs and expenses: | ||||||||
| Cost of sales – coal | 177,304 | - | - | 177,304 | ||||
| Depreciation, depletion | ||||||||
| and amortization | 9,124 | 11 | 30 | 9,165 | ||||
| Selling and administrative | 13,184 | 376 | 9,511 | 23,071 | ||||
| Heritage health benefit | ||||||||
| costs | - | - | 23,773 | 23,773 | ||||
| Doubtful account recoveries | (428) | - | (18) | (446) | ||||
| Loss on sales of assets | - | 440 | - | 440 | ||||
| Operating income (loss) from continuing operations |
$ | 31,864 | $ | 15,044 | $ | (33,296) | $ | 13,612 |
| Capital expenditures | $ | 5,388 | $ | 4 | $ | 41 | $ | 5,433 |
| Property, plant and | ||||||||
| equipment (net) | $ | 195,968 | $ | 45 | $ | 1,258 | $ | 197,271 |
The Company derives its coal revenues from a few key customers. The customers from which more than 10% of total revenue has been derived and the percentage of total revenue is summarized as follows:
| 2003 | 2002 | 2001 | |
| (in thousands) | |||
| Customer A | $ 99,688 | $ 119,658 | $ 92,626 |
| Customer B | 70,431 | 64,007 | 46,104 |
| Percentage of total revenue | 55% | 58% | 56% |
As of December 31, 2003 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 $306.7 million. with a present value of $123.3 million, and that the Company is financially responsible for reclamation obligations with a present value of $45.2 million. The contractual third party reclamation obligations of certain customers and a contract mine operator are discussed below. The amount of the Company’s bonds exceeds the amount of its share of estimated final reclamation obligations as of December 31, 2003.
86
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, 2003, the value of those funds, classified as reclamation deposits on the Consolidated Balance Sheets, was $51.1 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 to satisfy the contract provisions. The balance in that account was $1.7 million and the present value of that customer’s obligation was $6.3 million as of December 31, 2003 and is classified as contractual third party reclamation obligations on the Consolidated Balance Sheets.
Also at the Rosebud Mine, all of the owners of the Colstrip Station are contractually required to reimburse the Company for contemporaneous reclamation costs as they are incurred. As of December 31, 2003, the total amount of such costs outstanding was $7.3 million, which amount is included in other receivables on the Consolidated Balance Sheets.
At the Jewett Mine, the customer is contractually responsible for all post-production reclamation obligations and has provided a $50.0 million corporate guarantee to the Railroad Commission of Texas to assure performance of such final reclamation. The present value of the customer’s obligation was $12.8 million as of December 31, 2003, which is classified as contractual third party reclamation obligations on the Consolidated Balance Sheets.
At the Absaloka Mine, the contract miner, Washington Group International (“WGI”), is obligated to perform the vast majority of all reclamation activities, including all final backfilling, regrading and seeding. Westmoreland Resources Inc. (“WRI”) owns the Absaloka Mine, and Westmoreland owns 80% of WRI. WRI has a maximum financial responsibility for these activities of $1.7 million, which amount is being pre-funded through annual installment payments of $113,000 through 2005. Once the contract miner has performed its final reclamation obligations, WRI will be responsible for site maintenance and monitoring until final bond release. To assure compliance, and as part of a settlement of several outstanding issues in 2002, the contract miner has established an escrow account into which 6.5% of every contract mining invoice payment is being deposited. The balance as of December 31, 2003 was $1.5 million which includes WRI’s 2003 annual installment of $113,000. The present value of the contract miner’s reclamation obligation was $6.3 million as of December 31, 2003, and is classified as contractual third party reclamation obligations on the Consolidated Balance Sheets.
The Company has received demand letters from the Montana Department of Revenue (“DOR”), as agent for the Minerals Management Service (“MMS”) of the U.S. Department of the Interior, asserting underpayment of certain royalties allegedly due at the Rosebud Mine. The claims relate to the fees the Company receives to transport coal from the contract delivery point to the customer, certain “take or pay” payments the Company received when its customers did not require coal, and adjustments for certain taxes. The total amount of the claims is approximately $15.5 million, including penalties and interest, which continues to accrue. The Company continues to receive transportation fees and expects DOR to assert claims for additional underpayment and to issue more demand letters until the appeal process is completed. The Company believes that the DOR/MMS claims are improper and is vigorously contesting them. The appeal process will take several years. In the event of a negative outcome with DOR and MMS, the Company believes that certain of the Company’s customers are contractually obligated to reimburse the Company for any claims paid plus legal expenses.
87
The Company was subject to certain financial ratio tests specified in a Contingent Promissory Note (the “Note”) executed in conjunction with an agreement with the UMWA Health and Retirement Funds (the “Master Agreement”) and others, which facilitated the Company’s discharge from Chapter 11 Bankruptcy in 1998. The Note was originally scheduled to terminate on January 1, 2005. On August 11, 2003, the Company reached an agreement with the above Funds, whereby, in exchange for a one-time payment of $225,000, the financial ratio tests, the Note, and a related security agreement were terminated. The Company will continue to be obligated to meet certain other covenants through the expiration of the Master Agreement on January 1, 2005.
The final purchase price for the Company’s 2001 acquisition of the coal business of Entech LLC is subject to a final adjustment. Pursuant to the terms of the Stock Purchase Agreement, certain adjustments to the purchase price were to be made as of the date the transaction closed to reflect the net assets of the acquired operations on the closing date and the net revenues that those operations had earned between January 1, 2001 and the closing date. In June 2001, Entech submitted proposed adjustments that would have increased the purchase price by approximately $9.0 million. In July 2001, the Company objected to Entech’s adjustments and submitted its own adjustments which would result in a substantial decrease in the original purchase price. The Stock Purchase Agreement requires that the parties’ disagreements be submitted to an independent accountant for resolution. The Company also submitted a timely claim for indemnification by Entech.
Litigation in the New York courts ensued. On June 18, 2003, Touch America Holdings, Inc. (formerly Montana Power Company) and Entech LLC (formerly Entech Inc., and together with Touch America Holdings, Inc., “the Debtors,”) filed bankruptcy petitions in the United States Bankruptcy Court in Delaware. As a result, the automatic stay provisions of the Bankruptcy Code prevent any pending action from proceeding or any new actions from being filed against the Debtors. The Company’s pending litigation involving the purchase price adjustment is now stayed. The Company filed appropriate proofs of claim.
The Company is currently evaluating its options for proceeding, which include (1) seeking relief from the stay, so that it can continue to pursue its purchase price adjustment claims through the independent accountant and in an action at law in the New York courts, and (2) seeking to resolve its claims as part of the bankruptcy proceeding.
The ROVA project is located in Halifax County, North Carolina and is the County’s largest taxpayer. In 2002, the County hired an independent consultant to review and audit the property tax returns for the previous five years. In May 2002, the County advised the ROVA project that its returns were being scrutinized for potential underpayment due to undervaluation of property subject to tax. ROVA responded to the County that its valuation was consistent with a preconstruction agreement reached with the County in 1996. In late 2002, the ROVA projects received notice of an assessment of $4.6 million for the years 1997 to 2001. The ROVA Project filed a protest. Since that date the County has increased the amount of its claim to $5.3 million, which includes tax years 1996, 2002 and 2003. With penalty and interest, the total amount claimed due by the County is $8.3 million. The ROVA Project Partnership believes its position is meritorious, however, it is impossible to predict the outcome. If the assessment is upheld, in addition to the amounts assessed, the ROVA Project’s future taxes would increase by approximately $600,000 per year, of which we would be responsible for half.
88
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. On February 11, 2003, the North Carolina Department of Revenue notified us that it had disallowed the exclusion of gain from the settlement agreement between NIMO and the Rensselaer project. The State of North Carolina has assessed a current tax of $3.5 million, interest of $1.0 million, and a penalty of $0.9 million. We have filed a protest. The North Carolina Department of Revenue held a hearing on May 28, 2003. In November 2003, the Company submitted further documentation to the State to support its position and is awaiting their response.
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. Plaintiffs filed their first complaint on August 16, 2001. This was the Plaintiffs’ Fourth Amendment Complaint which added Westmoreland as a defendant to a shareholder suit against Montana Power Company, various officers of Montana Power Company, the Board of Directors of Montana Power Company, financial advisors and lawyers representing Montana Power 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 the shareholders 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.
The litigation has been transferred to the U.S. District Court in Billings, Montana. In December 2003, Montana Power and Entech sought to enforce the bankruptcy code’s automatic stay against the McGreevey plaintiffs. The plaintiffs have consented to a stay of the McGreevey litigation for approximately four months.
89
The Company makes monthly premium payments to the UMWA Combined Benefit Fund (“CBF”), a multiemployer health plan neither controlled nor administered by the Company. The previous amount of the monthly premiums was less than $400,000 and is recalculated each October. In 1996, a Federal Court ordered a decrease in the premiums charged by the CBF as a result of a finding that the formula being used by the government to determine reimbursement for health benefits under the Coal Act had been discontinued and that the actual amounts received by the CBF should be used instead. In connection with a separate case brought by the CBF, the Trustees of the CBF obtained notice of a premium increase on June 10, 2003 for beneficiaries assigned to companies under the Coal Act from the Social Security Administration (“SSA”). The CBF seeks to impose the increase retroactively to 1995 and has imposed a retroactive “catch-up” premium equal to the entire amount alleged to be due for the period from 1995 through October 2003, payable over the twelve months commencing October 2003. The net effect of these assessments increased the Company’s monthly payments to the CBF to $859,000 for the twelve months ending September 2004. The Company has commenced paying the higher monthly invoices while it vigorously pursues its legal remedies. As of December 31, 2003, the Company has accrued the remaining retroactive portion of the CBF premiums totaling $3.5 million.
The Company is a party to other claims and lawsuits with respect to various matters in the normal course of business. The ultimate outcome of these matters is not expected to have a material adverse effect on the Company’s financial condition, results of operations or liquidity.
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 $24.2 million, $25.5 million and $21.7 million in 2003, 2002 and 2001, respectively.
The Company has operating lease commitments expiring at various dates, primarily for real property and equipment. Rental expense under operating leases during 2003, 2002 and 2001 totaled $2.9 million, $4.3 million and $3.2 million, respectively. Minimum future rental obligations existing under these leases at December 31, 2003 are as follows (in thousands):
| Lease Obligations | |
| 2004 | $ 2,753 |
| 2005 | 1,356 |
| 2006 | 867 |
| 2007 | 618 |
| 2008 and thereafter | - |
The following table presents estimated total sales tonnage under existing long-term contracts for the next five years from the Company’s existing mining operations. The prices for all future tonnage are subject to revision and adjustments based upon market prices, certain indices and/or cost recovery.
| Projected Sales Tonnage Under | |
| Existing Long-Term Contracts | |
| (in millions of tons) | |
| 2004 | 29.6 |
| 2005 | 28.8 |
| 2006 | 28.3 |
| 2007 | 27.8 |
| 2008 | 22.3 |
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The tonnages in the table above represent estimated sales tonnage under existing, signed contracts and generally exclude pending or anticipated contract renewals or new contracts. These projections reflect customers’ scheduled major plant outages, if known.
As discussed in Note 2, WML was formed for the purpose of facilitating the financing of the acquisitions completed effective April 30, 2001. The line of credit and existing term notes entered into by WML for that purpose restrict the cash and other assets available for distribution or dividend to the parent company or other entities in the consolidated group. See Note 5 for a more detailed discussion of the restrictions and the amount of cash that is available for general use. Due to the recognition of a $55.6 million deferred tax asset in purchase accounting relating primarily to Westmoreland Coal Company’s net operating loss carryforwards, WML’s basis in property, plant and equipment is higher than that recognized in Westmoreland’s consolidated financial statements.
During the years ended December 31, 2003, 2003 and 2001, WML paid dividends and management fees to Westmoreland of $14.7 million, $14.9 million and $5.3 million, respectively.
The following are the condensed consolidated financial statements of WML and its subsidiaries as of and for the years ended December 31, 2003 and 2002 (in thousands):
| Condensed Consolidated Balance Sheets | ||||
| December 31, | ||||
| 2003 | 2002 | |||
| Cash and cash equivalents | $ | 4,053 | $ | 5,113 |
| Accounts receivable, net | 19,452 | 18,090 | ||
| Restricted cash | 17,427 | 12,883 | ||
| Deferred overburden removal costs | 12,654 | 10,348 | ||
| Other current assets | 17,868 | 19,580 | ||
| Property, plant and equipment, net | 168,788 | 208,639 | ||
| Deferred tax assets | - | 1,571 | ||
| Reclamation deposits | 52,786 | 49,484 | ||
| Contractual third party reclamation obligations | 19,843 | 23,448 | ||
| Other assets | 8,128 | 9,800 | ||
| Total Assets | $ | 320,999 | $ | 358,956 |
| Current portion of long-term debt | $ | 11,595 | $ | 8,852 |
| Accounts payable and accrued expenses | 31,187 | 30,715 | ||
| Payable to parent | 23,018 | 19,164 | ||
| Line of credit | - | 1,500 | ||
| Long-term debt, less current portion | 81,374 | 89,305 | ||
| Deferred tax liabilities | 114 | - | ||
| Asset retirement obligations | 115,852 | 152,967 | ||
| Other liabilities | 11,874 | 7,691 | ||
| Member’s equity | 45,985 | 48,762 | ||
| Total Liabilities and Member’s Equity | $ | 320,999 | $ | 358,956 |
91
| Condensed Consolidated Statement of Operations | ||||
| Year Ended December 31, | ||||
| 2003 | 2002 | |||
| Coal revenues | $ | 245,871 | $ | 256,363 |
| Cost of sales – coal | (186,855) | (189,274) | ||
| Depreciation and amortization expense | (14,478) | (14,516) | ||
| Selling and administrative expense | (20,627) | (18,440) | ||
| Management fees to parent | (2,000) | (2,000) | ||
| Operating income | 21,911 | 32,133 | ||
| Interest expense | (9,371) | (10,012) | ||
| Interest and other income | 1,995 | 2,154 | ||
| Income before income taxes and cumulative effect of change in accounting principle |
14,535 | 24,275 | ||
| Income tax expense | (5,020) | (9,239) | ||
| Net income before cumulative effect of change in accounting principle |
$ | 9,515 | $ | 15,036 |
| Cumulative effect of change in accounting principle |
358 | - | ||
| Net income | $ | 9,873 | $ | 15,036 |
| Condensed Consolidated Statements of Cash Flows | ||||
| Year Ended December 31, | ||||
| 2003 | 2002 | |||
| Net income | $ | 9,873 | $ | 15,036 |
| Depreciation and amortization expense | 14,478 | 14,516 | ||
| Deferred income tax expense (benefit) | 1,685 | (1,169) | ||
| Cumulative effect of change in accounting principle | (358) | - | ||
| Changes in operating assets and liabilities | 12,233 | 20,456 | ||
| Cash provided by operating activities | 37,911 | 48,839 | ||
| Fixed asset additions | (12,760) | (7,286) | ||
| Increase in restricted cash | (7,846) | (4,512) | ||
| Proceeds from asset sales | 973 | 610 | ||
| Cash used in investing activities | (19,633) | (11,188) | ||
| Proceeds from borrowings of long-term debt, net | 4,590 | - | ||
| Repayment of long-term debt | (9,778) | (13,753) | ||
| Borrowings (repayments) under line of credit, net | (1,500) | (6,500) | ||
| Dividends to parent | (12,650) | (12,909) | ||
| Cash used in financing activities | (19,338) | (33,162) | ||
| Net increase in cash and cash equivalents | (1,060) | 4,489 | ||
| Cash and cash equivalents, beginning of year | 5,113 | 624 | ||
| Cash and cash equivalents, end of year | $ | 4,053 | $ | 5,113 |
WRI has a coal mining contract with WGI, its 20% stockholder. Mining costs incurred under the contract were $20.5 million, $18.0 million and $21.5 million in 2003, 2002 and 2001, respectively.
92
The quarterly data presented below reflect the reclassification of discontinued operations identified during the fourth quarter of 2003 and as a result differ from those previously filed. Summarized quarterly financial data for 2003 and 2002 are as follows:
| Three Months Ended | ||||||||
| March 31 | June 30 | Sept. 30 | Dec. 31 | |||||
| (in thousands except per share data) | ||||||||
| 2003 | ||||||||
| Revenues | $ | 78,284 | $ | 70,455 | $ | 83,291 | $ | 78,780 |
| Costs and expenses | 75,775 | 73,585 | 84,025 | 70,310 | ||||
| Operating income (loss) from | ||||||||
| continuing operations | 2,509 | (3,130) | (734) | 8,470 | ||||
| Income (loss) from continuing | ||||||||
| operations before income taxes and cumulative effect of |
||||||||
| change in accounting principle | 605 | (4,941) | (2,948) | 6,633 | ||||
| Income tax (expense) benefit from | ||||||||
| continuing operations | 910 | 3,459 | 4,228 | 2,374 | ||||
| Income (loss) from discontinued operations |
(184) | 2,306 | (9) | - | ||||
| Cumulative effect of change in accounting principle |
161 | - | - | - | ||||
| Net income | 1,492 | 824 | 1,272 | 9,006 | ||||
| Less preferred stock dividend | ||||||||
| requirements | (440) | (440) | (436) | (436) | ||||
| Net income applicable to common | ||||||||
| shareholders | $ | 1,052 | $ | 384 | $ | 836 | $ | 8,570 |
| Income per share applicable to common shareholders: |
||||||||
| Basic | $ | 0.14 | $ | 0.05 | $ | 0.11 | $ | 1.08 |
| Diluted | $ | 0.13 | $ | 0.05 | $ | 0.10 | $ | 1.02 |
| Weighted average number of common and common equivalent shares outstanding: |
||||||||
| Basic | 7,728 | 7,762 | 7,805 | 7,899 | ||||
| Diluted | 8,223 | 8,331 | 8,378 | 8,426 | ||||
| Three Months Ended | ||||||||
| March 31 | June 30 | Sept. 30 | Dec. 31 | |||||
| (in thousands except per share data) | ||||||||
| 2002 | ||||||||
| Revenues | $ | 83,213 | $ | 83,683 | $ | 75,280 | $ | 73,565 |
| Costs and expenses | 77,367 | 78,601 | 70,865 | 70,075 | ||||
| Operating income (loss) | 5,846 | 5,082 | 4,415 | 3,490 | ||||
| Income (loss) from continuing | ||||||||
| operations before income taxes | 3,462 | 3,188 | 3,619 | 1,071 | ||||
| Income tax (expense) benefit | (802) | (512) | 1,212 | 2,470 | ||||
| Loss from discontinued operations | (329) | (376) | (2,572) | (306) | ||||
| Net income (loss) | 2,331 | 2,300 | 2,259 | 3,235 | ||||
| Less preferred stock dividend | ||||||||
| requirements | (444) | (444) | (444) | (440) | ||||
| Income applicable to common | ||||||||
| shareholders | $ | 1,887 | $ | 1,856 | $ | 1,815 | $ | 2,795 |
| Income per share applicable to common shareholders: |
||||||||
| Basic | $ | 0.25 | $ | 0.24 | $ | 0.24 | $ | 0.36 |
| Diluted | $ | 0.23 | $ | 0.23 | $ | 0.22 | $ | 0.34 |
| Weighted average number of common and common equivalent shares outstanding: |
||||||||
| Basic | 7,531 | 7,584 | 7,638 | 7,677 | ||||
| Diluted | 8,103 | 8,159 | 8,146 | 8,172 | ||||
93
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, 2003 and 2002, 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, 2003. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Westmoreland Coal Company and subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.
As discussed in the Summary of Significant Accounting Policies to the Consolidated Financial Statements, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003.
KPMG LLP
Denver, Colorado
February 20, 2004, except as to Notes 5 and 9,
which are as of March 8, 2004
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| ITEM 9 - | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
This item is not applicable.
| ITEM 9A - | CONTROLS AND PROCEDURES |
The Company’s management, with the participation of the Company’s chief executive officer and chief financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) as of December 31, 2003. Based on this evaluation, the Company’s chief executive officer and chief financial officer concluded that, as of December 31, 2003, the Company’s disclosure controls and procedures were (1) designed to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to the Company’s chief executive officer and chief financial officer by others within those entities, particularly during the period in which this report was being prepared, and (2) effective, in that they provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
No change in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
| ITEM 10 - | DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT |
| ITEM 11 - | EXECUTIVE COMPENSATION |
| ITEM 12 - | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
| ITEM 13 - | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS |
For Items 10-13, inclusive, except for information concerning executive officers of Westmoreland included as an unnumbered item in Part I above, reference is hereby made to Westmoreland’s definitive proxy statement to be filed in accordance with Regulation 14A pursuant to Section 14(a) of the Securities Exchange Act of 1934, which is incorporated herein by reference thereto.
| ITEM 14 - | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
Reference is hereby made to Westmoreland’s definitive proxy statement to be filed in accordance with Regulation 14A pursuant to Section 14(a) of the Securities Exchange Act of 1934, which is incorporated herein by reference thereto.
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| ITEM 15 - | EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K |
| a) 1. | The financial statements filed herewith are the Consolidated Balance Sheets of the Company and subsidiaries as of December 31, 2003 and December 31, 2002, 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, 2003 together with the Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements, which are contained in Item 8. |
| 2. | The following financial statement schedule is filed herewith:
Schedule II - Valuation Accounts |
| 3. | The following exhibits are filed herewith as required by Item 601 of Regulation S-K: |
| (2) | Plan of acquisition, reorganization, arrangement, liquidation or succession | ||
| (a) | Westmoreland's Plan of Reorganization was confirmed by an order of the United States Bankruptcy Court for the District of Delaware on December 16, 1994, and upon complying with the conditions of the order, Westmoreland emerged from bankruptcy on December 22, 1994. A copy of the confirmed Plan of Reorganization was filed as an Exhibit to Westmoreland's Report on Form 8-K filed December 30, 1994, which is incorporated herein by reference thereto (SEC File #001-11155). | ||
| (3) | (a) | Articles of Incorporation: Restated Certificate of Incorporation, filed with the Office of the Secretary of State of Delaware on February 21, 1995 and filed as Exhibit 3(a) to Westmoreland's 10-K for 1994 which Exhibit is incorporated herein by reference (SEC File #001-11155). | |
| (b) | Bylaws, as amended on June 18, 1999, and filed as Exhibit (3)(b) to Westmoreland's Report on Form 8-K filed June 21, 1999, which exhibit is incorporated herein by reference (SEC File #001-11155). | ||
| (4) | Instruments defining the rights of security holders | ||
| (a) | Certificate of Designation of Series A Convertible Exchangeable Preferred Stock of the Company defining the rights of holders of such stock, filed July 8, 1992 as an amendment to the Company's Certificate of Incorporation, and filed as Exhibit 3(a) to Westmoreland's Form 10-K for 1992, which Exhibit is incorporated herein by reference (SEC File #001-11155). | ||
| (b) | Form of Indenture between Westmoreland and Fidelity Bank, National Association, as Trustee relating to the Exchange Debentures. Reference is hereby made to Exhibit 4.1 to Form S-2 Registration No. 33-47872 filed May 13, 1992, and Amendments 1 through 4 thereto, which Exhibit is incorporated herein by reference. | ||
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| (c) | Form of Exchange Debenture. Reference is hereby made to Exhibit 4.2 to Form S-2 Registration No. 33-47872 filed May 13, 1992, and Amendments 1 through 4 thereto, which Exhibit is incorporated herein by reference. | ||
| (d) | Form of Deposit Agreement among Westmoreland, First Chicago Trust Company of New York, as Depository and the holders from time to time of the Depository Receipts. Reference is hereby made to Exhibit 4.3 to Form S-2 Registration No. 33-47872 filed May 13, 1992, and Amendments 1 through 4 thereto, which Exhibit is incorporated herein by reference. | ||
| (e) | Form of Certificate of Designation for the Series A Convertible Exchangeable Preferred Stock. Reference is hereby made to Exhibit 4.4 to Form S-2 Registration No. 33-47872 filed May 13, 1992, and Amendments 1 through 4 thereto, which Exhibit is incorporated herein by reference. | ||
| (f) | Specimen certificate representing the common stock of Westmoreland, filed as Exhibit 4(c) to Westmoreland's Registration Statement on Form S-2, Registration No. 33-1950, filed December 4, 1985, is hereby incorporated by reference. | ||
| (g) | Specimen certificate representing the Preferred Stock. Reference is hereby made to Exhibit 4.6 to Form S-2 Registration No. 33-47872 filed May 13, 1992, and Amendments 1 through 4 thereto, which Exhibit is incorporated herein by reference. | ||
| (h) | Form of Depository Receipt. Reference is hereby made to Exhibit 4.7 to Form S-2 Registration No. 33-47872 filed May 13, 1992, and Amendments 1 through 4 thereto, which Exhibit is incorporated herein by reference. | ||
| (i) | Amended and Restated Rights Agreement, dated as of February 7, 2003, between Westmoreland Coal Company and EquiServe Trust Company, N.A. Reference is hereby made to Exhibit 4.1 to Westmoreland's Form 8-K filed February 7, 2003, which Exhibit is incorporated herein by reference (SEC File #001-11155). | ||
| (j) | In accordance with paragraph (b)(4)(iii) of Item 601 of Regulation S-K, Westmoreland hereby agrees to furnish to the Commission, upon request, copies of all other long-term debt instruments. | ||
| (10) | Material Contracts | ||
| (a) | Westmoreland Coal Company 1985 Incentive Stock Option and Stock Appreciation Rights Plan is incorporated herein by reference to Exhibit 10(d) to Westmoreland's Annual Report on Form 10-K for 1984 (SEC File #0-752). | ||
| (b) | In 1990, the Board of Directors established an Executive Severance Policy for certain executive officers, which provides a severance award in the event of termination of employment. The description of the Executive Severance Policy is incorporated herein by reference to Westmoreland's Definitive Schedule 14A filed April 20, 2000 (SEC File #001-11155). | ||
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| (c) | Westmoreland Coal Company 1991 Non-Qualified Stock Option Plan for Non-Employee Directors is incorporated herein by reference to Exhibit 10(i) to Westmoreland's Annual Report on Form 10-K for 1990 (SEC File #0-752). |
| (d) | Effective January 1, 1992, the Board of Directors established a Supplemental Executive Retirement Plan ("SERP") for certain executive officers and other key individuals, to supplement Westmoreland's Retirement Plan by not being limited to certain Internal Revenue Code limitations is incorporated herein by reference to Exhibit 10(d) to Westmoreland's Annual Report on Form 10-K for 2000 (SEC File #001-11155). | ||
| (e) | Amended Coal Lease Agreement between Westmoreland Resources, Inc. and Crow Tribe of Indians, dated November 26, 1974, as further amended in 1982, is incorporated herein by reference to Exhibit (10)(a) to Westmoreland's Quarterly Report on Form 10-Q for the quarter ended March 31, 1992 (SEC File #0-752). | ||
| (f) | Westmoreland Coal Company 1995 Long-Term Incentive Stock Plan is incorporated herein by reference to Appendix 3 to Westmoreland's Definitive Schedule 14A filed April 28, 1995 (SEC File #0-752). | ||
| (g) | Master Agreement, dated as of January 4, 1999 between Westmoreland Coal Company, Westmoreland Resources, Inc., Westmoreland Energy, Inc., Westmoreland Terminal Company, and Westmoreland Coal Sales Company, the UMWA 1992 Benefit Plan and its Trustees, the UMWA Combined Benefit Fund and its Trustees, the UMWA 1974 Pension Trust and its Trustees, the United Mine Workers of America, and the Official Committee of Equity Security Holders in the chapter 11 case of Westmoreland Coal and its official members is incorporated herein by reference to Exhibit No. 99.2 to Westmoreland's Form 8-K filed on February 5, 1999 (SEC File #001-11155). | ||
| (h) | Contingent Promissory Note between Westmoreland Coal Company, Westmoreland Resources, Inc., Westmoreland Energy, Inc., Westmoreland Coal Sales Company, and Westmoreland Terminal Company and the UMWA Combined Benefit Fund and the UMWA 1992 Benefit Plan is incorporated herein by reference to Exhibit No. 99.3 to Westmoreland's Form 8-K filed on February 5, 1999 (SEC File #001-11155). | ||
| (i) | Westmoreland Coal Company 1996 Directors' Stock Incentive Plan is incorporated herein by reference to Exhibit 10(i) to Westmoreland's Annual Report on Form 10-K for year ended December 31, 2000 (SEC File #001-11155). | ||
| (j) | Westmoreland Coal Company 2000 Nonemployee Directors' Stock Incentive Plan is incorporated herein by reference to Exhibit 10(j) to Westmoreland's Annual Report on Form 10-K for year ended December 31, 2000 (SEC File #001-11155). | ||
| (k) | Westmoreland Coal Company 2000 Long-Term Incentive Stock Plan is incorporated herein by reference to Annex A to Westmoreland's Definitive Schedule 14A filed April 20, 2000 (SEC File #001-11155). |
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| (l) | Westmoreland Coal Company 2001 Directors Compensation Plan is incorporated herein by reference to Westmoreland's Form S-8 filed March 12, 2001 (SEC File #001-11155). |
| (m) | Amended and Restated Coal Supply Agreement dated August 24, 1998, by and among The Montana Power Company, Puget Sound Energy, Inc., The Washington Water Power Company, Portland General Electric Company, PacifiCorp and Western Energy Company is incorporated herein by reference to Exhibit 10.1 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155). | ||
| (n) | Coal Transportation Agreement dated July 10, 1981, by and among the Montana Power Company, Puget Sound Power & Light Company, Puget Colstrip Construction Company, The Washington Water Power Company, Portland General Electric Company, Pacific Power & Light Company, Basin Electric Power Cooperative, and Western Energy Company is incorporated herein by reference to Exhibit 10.2 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155). | ||
| (o) | Amendment No. 1 to the Coal Transportation Agreement dated September 14, 1987, by and among The Montana Power Company, Puget Sound Power & Light Company, Puget Colstrip Construction Company, The Washington Water Power Company, Portland General Electric Company, Pacific Power & Light Company and Western Energy Company is incorporated herein by reference to Exhibit 10.3 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155). | ||
| (p) | Amendment No. 2 to the Coal Transportation Agreement dated August 24, 1998, by and among The Montana Power Company, Puget Sound Power & Light Company, Puget Colstrip Construction Company, The Washington Water Power Company, Portland General Electric Company, Pacific Power & Light Company, Basin Electric Power Cooperative, and Western Energy Company is incorporated herein by reference to Exhibit 10.4 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155). | ||
| (q) | Lignite Supply Agreement dated August 29, 1979, between Northwestern Resources Co. and Utility Fuels Inc. is incorporated herein by reference to Exhibit 10.5 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155). | ||
| (r) | Settlement Agreement and Amendment of Existing Contracts dated August 2, 1999, between Northwestern Resources Co. and Reliant Energy, Incorporated is incorporated herein by reference to Exhibit 10.6 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155). | ||
| (s) | Term Loan Agreement dated as of April 27, 2001 by and among Westmoreland Mining LLC, WCCO-KRC Acquisition Corp., Dakota Westmoreland Corporation, Western Energy Company, Northwestern Resources Co., the other entities from time to time party thereto as guarantors, and the purchasers named in Schedule A thereto is incorporated herein by reference to Exhibit 99.2 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155). |
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| (t) | Credit Agreement dated as of April 27, 2001 by and among Westmoreland Mining LLC, WCCO-KRC Acquisition Corp., Dakota Westmoreland Corporation, Western Energy Company, Northwestern Resources Co., the other entities from time to time party thereto as guarantors, the banks party thereto, and PNC Bank, National Association, in its capacity as agent for the banks is incorporated herein by reference to Exhibit 99.3 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155). |
| (u) | First Amendment to Credit Agreement dated as of August 15, 2001 among Westmoreland Mining LLC, the Loan Parties under the Credit Agreement, the Banks under the Credit Agreement, and PNC Bank, National Association, as Agent is incorporated herein by reference to Exhibit 10.7 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155). | ||
| (v) | First Amendment to Note Purchase Agreement dated as of August 15, 2001 among Westmoreland Mining LLC, the other Obligors under the Agreement, the Purchasers under the Agreement, and PNC Capital Markets, Inc., as lead arranger is incorporated herein by reference to Exhibit 10.8 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001 (SEC File #001-11155). | ||
| (w) | Amendment No. 2 to Credit Agreement dated February 27, 2002 among Westmoreland Mining LLC, the Loan Parties under the Credit Agreement, the Banks under the Credit Agreement, and PNC Bank, National Association, as Agent, is incorporated herein by reference to Exhibit 10(w) to Westmoreland's Annual Report on Form 10-K for the year ended December 31, 2001 (SEC File #001-11155). | ||
| (x) | Second Amendment to Term Loan Agreement dated February 27, 2002 among Westmoreland Mining LLC, the other Obligors under the Agreement, the Purchasers under the Agreement, and PNC Capital Markets, Inc. as lead arranger, is incorporated herein by reference to Exhibit 10(x) to Westmoreland's Annual Report on Form 10-K for the year ended December 31, 2001 (SEC File #001-11155). | ||
| (y) | Third Amendment to Term Loan Agreement dated March 8, 2004 among Westmoreland Mining LLC, the other Obligors under the Agreement, the Purchasers under the Agreement, and PNC Capital Markets, Inc. as lead arranger, is incorporated herein by reference to Exhibit 10.1 on Form 8-K filed March 10, 2004 (SEC File #001-11155). | ||
| (z) | Third Amendment to Credit Agreement dated March 8, 2004 among Westmoreland Mining LLC, the Loan Parties under the Credit Agreement, the Banks under the Credit Agreement, and PNC Bank, National Association, as Agent, is incorporated by reference to Exhibit 10.2 on Form 8-K filed on March 10, 2004 (SEC File #001-11155). |
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| (aa) | Loan Agreement dated as of December 14, 2001 between Westmoreland Coal Company, a Delaware corporation, and First Interstate Bank, a Montana corporation, is incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on December 19, 2001 (SEC File #001-11155). | ||
| (bb) | First Amendment dated as of December 24, 2002 to Loan Agreement dated December 14, 2001 between Westmoreland Coal Company, a Delaware corporation, and First Interstate Bank, a Montana corporation, is incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on January 28, 2003 (SEC File #001-11155). |
| (cc) | Second Amendment dated as of January 24, 2003 to Loan Agreement dated December 14, 2001 between Westmoreland Coal Company, a Delaware corporation, and First Interstate Bank, a Montana corporation, is incorporated herein by reference to Exhibit 10.2 on Form 8-K filed on January 28, 2003 (SEC File #001-11155). | ||
| (dd) | Pledge Agreement is dated as of April 27, 2001 by and among Westmoreland Coal Company, Westmoreland Mining LLC, the other entities from time to time party thereto as pledgors, and Firstar Bank, N.A., as collateral agent for the purchasers in connection with the Term Loan Agreement, incorporated herein by reference to Exhibit 99.4 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155). | ||
| (ee) | Pledge Agreement dated as of April 27, 2001, by and among 7Westmoreland Coal Company, Westmoreland Mining LLC, the other entities from time to time party thereto as pledgors, and Firstar Bank, N.A., as collateral agent for the banks in connection with the Revolving Credit Agreement is incorporated herein by reference to Exhibit 99.5 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155). | ||
| (ff) | Continuing Agreement of Guaranty and Suretyship dated as of April 27, 2001 by and among WCCO-KRC Acquisition Corp., Dakota Westmoreland Corporation, Western Energy Company, Northwestern Resources Co., and each of the other persons which becomes a guarantor thereunder, in favor of the purchasers under the Term Loan Agreement is incorporated herein by reference to Exhibit 99.6 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155). | ||
| (gg) | Continuing Agreement of Guaranty and Suretyship dated as of April 27, 2001 by and among WCCO-KRC Acquisition Corp., Dakota Westmoreland Corporation, Western Energy Company, Northwestern Resources Co., and each of the other persons which becomes a guarantor thereunder, in favor of PNC Bank, National Association, as agent for the banks in connection with that Credit Agreement is incorporated herein by reference to Exhibit 99.7 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155). | ||
| (hh) | Security Agreement dated as of April 27, 2001 by and among Westmoreland Mining LLC, WCCO-KRC Acquisition Corp., Dakota Westmoreland Corporation, Western Energy Company, Northwestern Resources Co., and each of the other persons which becomes a guarantor under the Term Loan Agreement and Firstar Bank, N.A., as collateral agent for the purchasers under the Term Loan Agreement is incorporated herein by reference to Exhibit 99.8 to the Registrant's Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155). |
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| (ii) | Stock Purchase Agreement dated as of September 15, 2000 by and between Westmoreland Coal Company and Entech, Inc. is incorporated herein by reference to Exhibit 99.1 to the Registrant's Current Report on Form 8-K filed February 5, 2001 (SEC File #001-11155). |
| (jj) | Letter Agreement dated June 18, 2002, between Reliant-HL&P and Northwestern Resources Co. is incorporated herein by reference to Exhibit 10.1 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2002 (SEC File #001-11155). |
| (kk) | Approved Westmoreland Coal Company 2000 Performance Unit Plan, dated May 22, 2003, is incorporated herein by reference to Exhibit 10.1 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2003 (SEC File #001-11155). |
| (ll) | First Amendment to Westmoreland Coal Company 2000 Non-employee Directors' Stock Incentive Plan, dated May 22, 2003 is incorporated by reference to Exhibit 10.2 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2003 (SEC File #001-11155). |
| (mm) | Termination Agreement for Robert J. Jaeger, Chief Financial Officer is herein incorporated by reference to Exhibit 10.3 to Westmoreland's Quarterly Report on Form 10-Q for the Quarter ended June 30, 2003 (SEC File #001-11155). |
| (nn)* | Supplemental Settlement Agreement and Amendment of Existing Contracts Between Northwestern Resources Company and Texas Genco, L.P. dated January 30, 2004. |
| * | Confidential treatment has been requested as to certain portions, which portions have been omitted and filed separately with the Securities and Exchange Commission. | ||
| (21) | Subsidiaries of the Registrant | ||
| (23) | Consent of Independent Certified Public Accountants | ||
| (31) | Rule 13a-14(a))/15d-14(a) Certifications. | ||
| (32) | Certifications pursuant to 18 U.S.C. Section 1350. | ||
| b) | Reports on Form 8-K. | ||
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| (1) | On January 28, 2003, the Company filed a report on Form 8-K regarding the execution on December 24, 2002 of the First Amendment to a Loan Agreement dated December 14, 2001 with First Interstate Bank, a Montana corporation. The amendment extended the maturity date of the revolving loan from December 14, 2003 to December 14, 2004. On January 24, 2003 the Company executed the Second Amendment to the Loan Agreement. The Second Amendment further extends the maturity date of the revolving loan to January 15, 2005 and increases the Revolving Line of Credit from $7 million to $10 million. | ||
| (2) | On February 7, 2003, the Company filed a report on Form 8-K announcing an amendment to its Rights Agreement dated as of January 28, 1993 by entering into an Amended and Restated Rights Agreement dated as of February 7, 2003. | ||
| (3) | On February 10, 2003, the Company filed a report on Form 8-K announcing its Board of Directors has authorized a dividend of $0.15 per depositary share payable on April 1, 2003 to holders of record as of March 7, 2003. | ||
| (4) | On March 17, 2003, the Company filed a report on Form 8-K announcing it had reached agreement with Dominion Energy Terminal Company, Inc. for the sale of Westmoreland Terminal Company's 20% interest in Dominion Terminal Associates and associated industrial revenue bonds. | ||
| (5) | On May 9, 2003, the Company filed a report on Form 8-K announcing its Board of Directors authorized a dividend of $0.15 per depositary share payable on July 1, 2003 to holders of record as of June 10, 2003. | ||
| (6) | On July 2, 2003, the Company filed a report on Form 8-K announcing the sale of its interest in Dominion Terminal Associates and associated industrial revenue bonds to Dominion Energy Terminal Company, Inc. | ||
| (7) | On July 9, 2003, the Company filed a report on Form 8-K disclosing the pro forma effect to the change in accounting principle as if the Financial Accounting Standards Board "Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations" had been in effect during the Company's three most recent fiscal years. | ||
| (8) | On August 5, 2003, the Company filed a report on Form 8-K announcing its Board of Directors authorized a dividend of $0.20 per depositary share payable on October 1, 2003 to holders of record as of September 10, 2003. | ||
| (9) | On November 7, 2003, the Company filed a report on Form 8-K announcing its Board of Directors authorized a dividend of $0.20 per depositary share payable on January 1, 2004 to holders of record as of December 8, 2003. | ||
| (10) | On February 9, 2004, the Company filed a report on Form 8-K announcing its subsidiary, Northwestern Resources CO. has reached agreement with Texas Genco, its customer establishing pricing and volumes for the Jewett Mine through 2007. |
103
| (11) | On February 17, 2004, the Company filed a report on Form 8-K announcing its 80% owned subsidiary, Westmoreland Resources, Inc., which owns and operates the Absaloka Mine near Hardin, Montana, has reached agreement with the Crow Tribe to explore and develop a Northern Powder River Basin coal reserve located on the Crow Reservation immediately adjacent to the Absaloka mine. | ||
| (12) | On February 27, 2004, the Company filed a report on Form 8-K announcing its Board of Directors authorized a dividend of $0.20 per depositary share payable on April 1, 2004 to holder of record as of March 8, 2004. | ||
| (13) | On March 10, 2004, the Company filed a report on Form 8-K regarding execution on March 8, 2004 of the Third Amendment to Term Loan Agreement dated April 22, 2001 and Third Amendment of the Credit Agreement. | ||
| (14) | On March 11, 2004, the Company filed a report on Form 8-K announcing that it has reached agreement with the 1974 United Mine Workers of America Retirement Plan to settle the Company's withdrawal obligations resulting from the termination of its last covered operations in the Eastern United States in 1995. |
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Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| WESTMORELAND COAL COMPANY | |
| Date: March 12, 2004 | By: /s/ Ronald H. Beck |
| Ronald H. Beck | |
| Vice President of Finance and Treasurer | |
| (A Duly Authorized Officer) | |
| Date: March 12, 2004 | By: /s/ Thomas S. Barta |
| Thomas S. Barta | |
| Controller | |
| (Principal Accounting Officer) | |
|
Signature
|
Title
|
Date
|
| Principal Executive Officer: | ||
| Chairman of the Board, President, and | ||
| /s/ Christopher K. Seglem |
Chief Executive Officer |
March 12, 2004 |
| Christopher K. Seglem |
|
|
| Directors: | ||
| /s/ Michael Armstrong |
Director |
March 12, 2004 |
| Michael Armstrong | ||
| /s/ Thomas J. Coffey |
Director |
March 12, 2004 |
| Thomas J. Coffey | ||
| /s/ Pemberton Hutchinson |
Director |
March 12, 2004 |
| Pemberton Hutchinson | ||
| /s/ Robert E. Killen |
Director |
March 12, 2004 |
| Robert E. Killen | ||
| /s/ Thomas W. Ostrander |
Director |
March 12, 2004 |
| Thomas W. Ostrander | ||
| /s/ James W. Sight |
Director |
March 12, 2004 |
| James W. Sight | ||
| /s/ William M. Stern |
Director |
March 12, 2004 |
| William M. Stern | ||
| /s/ Donald A. Tortorice |
Director |
March 12, 2004 |
| Donald A. Tortorice | ||
105
The Board of Directors and Shareholders
Westmoreland Coal Company:
Under date of February 20, 2004, except as to Notes 5 and 9 which are as of March 8, 2004, we reported on the consolidated balance sheets of Westmoreland Coal Company and subsidiaries as of December 31, 2003 and 2002, and the related statements of operations, shareholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2003, which report appears in the December 31, 2003, Annual Report on Form 10-K of Westmoreland Coal Company. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related financial statement schedule II. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement schedule based on our audits.
In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
| KPMG LLP |
Denver, Colorado
February 20, 2004
106
Schedule II
Valuation Accounts
Years ended December 31, 2003, 2002 and 2001
(in thousands)
| Balance at beginning of year | Deductions credited to earnings | Other Additions | Balance at end of year | ||||
| Year ended December 31, 2003: | |||||||
| Allowance for doubtful accounts | $ | 2,441 | - | - | $ | 2,441 | (A) |
| Year ended December 31, 2002: | |||||||
| Allowance for doubtful accounts | $ | 2,957 | (516) | - | $ | 2,441 | (A) |
| Year ended December 31, 2001: | |||||||
| Allowance for doubtful accounts | $ | 3,301 | (446) | 102 | $ | 2,957 | (A) |
| Amounts above include current and non-current valuation accounts. |
| (A) | Includes reserves related to the uncollectibility of notes receivable reported as a reduction of other assets in the Company's Consolidated Balance Sheets. |
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EXHIBIT 21
Subsidiaries of the Registrant for the year ended December 31, 2003:
| Subsidiary Name | State of Incorporation |
| Kentucky Criterion Coal Company | Delaware |
| Pine Branch Mining Inc. | Delaware |
| WEI - Fort Lupton, Inc. | Delaware |
| WEI - Rensselaer, Inc. | Delaware |
| WEI - Roanoke Valley, Inc. | Delaware |
| Westmoreland Coal Sales Inc. | Delaware |
| Westmoreland Energy, LLC | Delaware |
| Westmoreland Resources, Inc. | Delaware |
| Westmoreland Terminal Company | Delaware |
| Westmoreland - Altavista, Inc. | Delaware |
| Westmoreland - Fort Drum, Inc. | Delaware |
| Westmoreland - Franklin, Inc. | Delaware |
| Westmoreland - Hopewell, Inc. | Delaware |
| Westmoreland Technical Services, Inc. | Delaware |
| Cleancoal Terminal Co. | Delaware |
| Criterion Coal Co. | Delaware |
| Deane Processing Co. | Delaware |
| Eastern Coal and Coke Co. | Pennsylvania |
| Westmoreland Savage Corp. | Delaware |
| Westmoreland Mining LLC | Delaware |
| Dakota Westmoreland Corporation | Delaware |
| Western Energy Company | Montana |
| Northwestern Resources Co. | Montana |
| Westmoreland Risk Management, Ltd. | Bermuda |
| Basin Resources, Inc. | Colorado |
| North Central Energy Company | Colorado |
| Horizon Coal Services, Inc. | Montana |
| Westmoreland Power, Inc. | Delaware |
108
EXHIBIT 23
The Board of Directors
Westmoreland Coal Company:
We consent to incorporation by reference in the registration statements (No. 2-90847, No. 33-33620, No. 333-56904, No. 333-66698 and No. 333-106852) on Form S-8 of Westmoreland Coal Company of our report dated February 20, 2004, except as to Notes 5 and 9, which are as of March 8, 2004, relating to the consolidated balance sheets of Westmoreland Coal Company and subsidiaries as of December 31, 2003 and 2002, 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, 2003, and the report dated February 20, 2004 on the related schedule, which reports appear in the December 31, 2003, Annual Report on Form 10-K of Westmoreland Coal Company.
Our report refers to the adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003.
| KPMG LLP |
Denver, Colorado
March 12, 2004
109
Exhibit 31
CERTIFICATION
I, Christopher K. Seglem, certify that:
| 1. | I have reviewed this Annual Report on Form 10-K of Westmoreland Coal Company; | |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; | |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; | |
| 4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: | |
| a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | |
| b. | [Paragraph omitted in accordance with SEC transition instructions contained in SEC Release 34-47986] | |
| c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | |
| d. | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and | |
| 5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): | |
110
| a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and | |
| b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. | |
| Date: March 12, 2004 | /s/ Christopher K. Seglem |
| Name: | Christopher K. Seglem | |
| Title: | Chairman of the Board, President and Chief Executive Officer |
CERTIFICATION
I, Ronald H. Beck, certify that:
| 1. | I have reviewed this Annual Report on Form 10-K of Westmoreland Coal Company; | |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; | |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; | |
| 4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: | |
| a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | |
| b. | [Paragraph omitted in accordance with SEC transition instructions contained in SEC Release 34-47986] | |
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| c. | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | |
| d. | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and | |
| 5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): | |
| a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and | |
| b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. | |
| Date: March 12, 2004 | /s/ Ronald H. Beck |
| Name: | Ronald H. Beck | |
| Title: | Vice President-Finance and Treasurer Acting Chief Financial Officer |
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Exhibit 32
STATEMENT PURSUANT TO 18 U.S.C. §1350
Pursuant to 18 U.S.C. § 1350, each of the undersigned certifies that this Annual Report on Form 10-K for the period ended December 31, 2003 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained in this report fairly presents, in all material respects, the financial condition and results of operations of Westmoreland Coal Company.
| Dated: March 12, 2004 | /s/ Christopher K. Seglem |
| Christopher K. Seglem | |
| Chief Executive Officer | |
| Dated: March 12, 2004 | /s/ Ronald H. Beck |
| Ronald H. Beck | |
| Acting Chief Financial Officer |
A signed original of this written statement required by Section 906 has been provided to Westmoreland Coal Company and will be retained by Westmoreland Coal Company and furnished to the Securities and Exchange Commission or its staff upon request.
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