SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
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
Securities registered pursuant to Section 12(b) of the Act:
| NAME OF STOCK EXCHANGE | |
| TITLE OF EACH CLASS | ON WHICH REGISTERED |
| Common Stock, par value $2.50 per share | |
| Depositary Shares, each representing | American Stock Exchange |
| one-quarter of a share of Series A Convertible | |
| Exchangeable Preferred Stock | |
| Preferred Stock Purchase Rights | |
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.
XThe aggregate market value of voting common stock held by non-affiliates as of March 1, 2002 is estimated to be $86,179,000.
There were 7,528,833 shares outstanding of the registrant’s Common Stock, $2.50 Par Value (the registrant’s only class of common stock), as of March 1, 2002.
There were 834,833 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 1, 2002.
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.
| Item | Page |
| 1 | Business | 1 |
| 2 | Properties | 11 |
| 3 | Legal Proceedings | 22 |
| 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 | 30 |
| 7 | Management's Discussion and Analysis of Financial Condition and Results of Operations | 32 |
| 7A | Quantitative and Qualitative Disclosures About Market Risk | 55 |
| 8 | Financial Statements and Supplementary Data | 57 |
| 9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 97 |
| 10 | Directors and Executive Officers of the Registrant | 97 |
| 11 | Executive Compensation | 97 |
| 12 | Security Ownership of Certain Beneficial Owners and Management | 97 |
| 13 | Certain Relationships and Related Transactions | 97 |
| 14 | Exhibits, Financial Statement Schedule, and Reports on Form 8-K | 98 |
| Signatures | 104 |
Certain statements in this report which are not historical facts or information are “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, including, but not limited to, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations. Any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. 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; healthcare 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 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, reopeners and extensions; the Company’s ability to maintain satisfactory labor relations; changes in the industry; competition; the Company’s ability to utilize its 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; the announced liquidity issues of Washington Group International, Inc. (“Washington Group” or “WGI”) and other factors discussed in Items 1, 3 and 7 below. 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.
Westmoreland Coal Company (“Westmoreland” or “WCC”) traces its origin as a coal company to businesses established in 1853 and incorporated in Delaware in 1910. The term “Company” as used herein includes WCC and its subsidiaries.
The Company’s current principal activities, all conducted within the United States, are: (i) the production and sale of coal from Montana, North Dakota and Texas; (ii) the development, ownership and management of interests in cogeneration and other non-regulated independent power plants; and (iii) the leasing of capacity at Dominion Terminal Associates, a coal storage and vessel loading facility. Refer to Item 8 - Financial Statements and Supplementary Data for more information regarding the Company’s operating segments.
In 2001, the Company substantially expanded its coal business by acquiring the coal operations of The Montana Power Company (“Montana Power”) and MDU Resources Group, Inc.‘s subsidiary, Knife River Corporation. These acquisitions are described in more detail in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, under the heading “Impact of Acquisitions.” The new operations are also described below and in Item 2 – Properties.
Westmoreland Resources, Inc. (“WRI”). WRI is owned 80% by the Company and 20% by Washington Group, formerly known as Morrison Knudsen Company, Inc., which also mines the coal for WRI on a contract basis. WRI operates the Absaloka Mine, a surface operation located on approximately 15,000 acres of subbituminous coal reserves in the Powder River Basin near Hardin, Montana. The Absaloka Mine was expressly developed to supply coal to Xcel Energy’s (formerly Northern States Power) Sherburne County Station near Minneapolis, Minnesota. Over the years, it has sold coal to several other upper Midwest utilities. The coal sold to Xcel is under a long-term base price cost escalating contract which expires at the end of 2002. The Absaloka Mine has provided coal to Xcel since 1974 and the Company expects that this contract will be renewed with prices and terms similar to those now in effect. WRI shipped 5,904,000, 4,910,000, and 5,466,000 tons of coal in 2001, 2000 and 1999, respectively. Transportation is arranged and charges are paid by WRI’s customers. The Company received cash dividends from WRI of $4,400,000 in 2001, $8,400,000 in 2000 and $4,000,000 in 1999.
Westmoreland Mining LLC (“WML”) . WML is a separate subsidiary of WCC that was formed as required by the lenders providing financing for the acquisitions of the operating coal business of Montana Power and the coal assets of Knife River Corporation. WML provides management and administrative support to its subsidiaries including environmental, sales and accounting services. WML’s subsidiaries are Western Energy Company, Northwestern Resources Co., Dakota Westmoreland Corporation, and WCCO-KRC Acquisition Corporation. WML is located in Billings, Montana.
Western Energy Company (“WECO”). WECO was acquired in April 2001 as part of the acquisition of the coal business of Montana Power. WECO operates the Rosebud Mine in Colstrip, Montana, a surface mine in the Northern Powder River Basin. The Rosebud Mine is one of the largest coal mines in the United States and sold 11,284,000 tons of subbituminous coal in 2001 (7,610,000 tons for the eight months since the acquisition). After mining the coal, WECO crushes it and sells it without further preparation. WECO’s primary customers are the owners of the four-unit, mine-mouth Colstrip Station, which has a combined electric generating capacity of approximately 2,200MW. This coal is sold under long-term contracts expiring in 2009 for Colstrip Units 1 and 2 and 2019 for Colstrip Units 3 and 4. The Colstrip Units 1 and 2 contract has a base price with escalating provisions for certain costs and the Colstrip Units 3 and 4 contract is a cost-plus arrangement. WECO also supplies coal to Minnesota Power under an increasing fixed price coal supply agreement that expires in 2003 and to several smaller customers under contracts of varying term.
Northwestern Resources Co. (“NWR”). NWR was also acquired in April 2001 as part of the acquisition of the coal business of Montana Power. NWR operates the Jewett Mine, located in central Texas, and supplies surface-mined lignite to the two electric generating units at the Limestone Electric Generating Station (“LEGS”), located adjacent to the mine. LEGS is owned by Reliant Energy, Inc. (“Reliant”). The lignite is sold under a long-term lignite supply agreement (“LSA”) that expires in 2015. Beginning July 1, 2002, tonnages and price will be determined sequentially on an annual basis pursuant to a procedure under which NWR will commit the number of tons it wishes to supply and price will be determined according to a formula which estimates hypothetical value of Powder River Basin coal if delivered to the plant that year. For the full year of 2001, NWR sold 7,138,000 tons of lignite (4,463,000 tons for the eight months since WCC’s acquisition) under the LSA.
Dakota Westmoreland Corporation (“DWC”). DWC was formed in 2001 to acquire part of the coal assets of Knife River Corporation. DWC operates the Beulah Mine, a lignite surface mine near the town of Beulah, North Dakota. For the full year of 2001, the Beulah Mine sold 3,087,000 tons (2,014,000 tons for the eight months since WCC’s acquisition) of lignite under long-term coal agreements with the Heskett Station in Bismarck, North Dakota, and the Coyote Station adjacent to the mine. During 2001, approximately 82% of the tons were shipped to Coyote and the remainder to Heskett. The Coyote agreement, which has a base price with escalating provisions for certain costs, expires in 2016. The Heskett agreement, which is priced based on the Coyote agreement, expires in 2005 and has a five-year extension at expiration at DWC’s option.
WCCO-KRC Acquisition Corporation (“Savage”). Savage was also formed in 2001, to acquire other parts of the coal assets of Knife River Corporation. Savage operates the Savage Mine near Sidney, Montana. This is a lignite surface mine and for the full year of 2001, Savage sold 346,000 tons (236,000 tons for the eight months since WCC’s acquisition) of lignite under a full requirements, base price with an escalating provision for certain costs contract with the nearby Lewis and Clark station. This contract expires on December 31, 2002. The Savage Mine has provided lignite to the Lewis and Clark station for over 40 years and the Company expects that this contract will be renewed with prices and terms similar to those now in effect. The mine also has a contract, expiring August 31, 2003, to provide lignite to Holly Sugar’s nearby beet processing facility.
The following tables show, for each of the past five years, tons sold and revenues derived from mines that were, at the time of production, owned by the Company. The Company had no export sales during the five-year period ended December 31, 2001.
| Year | Coal Sales in Tons (in 000’s) |
Coal Revenues in Dollars (in 000’s) |
| 2001 | 20,503 | 231,048 |
| 2000 | 4,910 | 35,137 |
| 1999 | 5,466 | 38,539 |
| 1998 | 6,458 | 44,010 |
| 1997 | 7,059 | 47,182 |
Tonnage sold by the Company pursuant to contracts calling for deliveries over a period longer than one year is considered a long-term contract. The table below presents the percentage of coal tonnage sold under long-term contracts for the last five years:
| Sales Tonnage Under Long-Term Contracts |
|
| 2001 | 99% |
| 2000 | 100% |
| 1999 | 100% |
| 1998 | 98% |
| 1997 | 97% |
The following table presents estimated minimum total sales tonnage under existing long-term contracts for the next five years from the Company’s existing mining operations. The price for all future tonnage is subject to revision and adjustments based upon market prices, certain indices and/or cost recovery.
| Projected Sales Tonnage Under | |
| Existing Long-Term Contracts (000s) | |
| 2002 | 27,120 |
| 2003 | 22,883 |
| 2004 | 22,850 |
| 2005 | 22,850 |
| 2006 | 21,850 |
The weighted average price under existing long-term contracts was $11.05 in 2001, $7.16 in 2000 and $7.05 in 1999.
In 2001, the Company’s three largest customers accounted for 74% of its coal revenues. Colstrip 3 and 4, Xcel Energy and Reliant accounted for 20%, 13% and 41%, respectively. No other customer accounted for as much as 10% of the Company’s 2001 coal revenues. The long-term contract with WRI’s largest customer, Xcel Energy, expires December 31, 2002. NWR’s long-term contract with Reliant expires 2015. The long-term contract with WECO’s largest customer, Colstrip Units 3 and 4, expires in 2019. The Company anticipates replacing sales as contracts expire with extensions, new contracts or spot sales over the life of the coal reserves.
Other Acquisition Assets. In connection with the 2001 acquisitions, the Company obtained ownership of Basin Resources, Inc. (“Basin”), Northern Central Resources, Inc. (“North Central”), Horizon Coal Services, Inc. (“Horizon”), and Western Syncoal LLC (“SynCoal”). Basin is a coal mining company that operated the Golden Eagle Mine in Trinidad, Colorado and was part of Montana Power. Basin ceased operations in 1996 and is inactive. Westmoreland is seeking to dispose of its assets and obligations. North Central holds the land and water rights associated with the mining operations of Basin. Horizon’s only asset is a royalty interest in coal reserves located in Campbell County, Wyoming at the Caballo Mine owned by Peabody Energy. The royalty covers 225 million tons of coal mined at the rate of $.10 per ton, making the gross royalty amount $22,500,000. The latest mine plan delivered to Horizon by Peabody Energy in March 2002 indicates that mining of this lease will begin in 2006. SynCoal is a synthetic coal production facility located in Colstrip, Montana and is inactive. In addition, WCC acquired Knife River Corporation’s right to develop the lignite deposits at Gascoyne, North Dakota.
Westmoreland Energy, Inc. (“WEI”) owns and manages interests in independent power projects. WEI, through various subsidiaries, currently has interests in three such power projects, all of which are operational. Each project has a single power purchaser and steam host. The Company is scheduled to receive distributions from its ROVA plants in January and July of each year. Refer to Note 3 of the Consolidated Financial Statements for additional information concerning WEI, including specific project operational statistics.
WEI’s independent power projects sell electricity through long-term power sales contracts to utilities. There are three types of independent power projects: cogeneration projects which provide two types of useful energy (e.g., electricity and thermal energy, like steam) sequentially from a single primary fuel (e.g., coal); small power producers which utilize waste, biomass or other renewable resources as fuel; and exempt wholesale generators (“EWG”) which provide electrical energy without the requirement to sell thermal energy or use waste or renewable resources as fuel sources. WEI has invested in cogeneration projects and in projects that are EWGs. For WEI, the key elements of an independent power project are a long-term contract for the sale of electricity, long-term contracts for the fuel supply, a suitable site, required permits and project financing. Cogeneration projects require another long-term contract for the sale of the steam or other thermal energy. The economic benefits of cogeneration can be substantial because, in addition to generating electricity, a significant portion of the energy is used to produce steam or high temperature water (thermal energy) for industrial processes. Electricity is sold to utilities and, in certain situations, to end-users of electrical power, including large industrial facilities. Thermal energy from the cogeneration plant is sold to commercial enterprises and other institutions. Large industrial users of thermal energy include plants in the chemical processing, petroleum refining, food processing, pharmaceutical, pulp and paper industries.
Westmoreland Power, Inc. (“WPI”) was formed to acquire certain rights from Knife River Corporation and to pursue new independent power development. On February 28, 2001, it announced that it had submitted a proposal to develop, own and operate, either independently or in partnership, a new state-of-the-art 500 MW lignite-fired power plant near Gascoyne, North Dakota in connection with Lignite Vision 21 (“LV-21”). WCC acquired the right to develop the lignite deposits at Gascoyne from Knife River Corporation. LV-21 is a partnership between the state of North Dakota and the Lignite Energy Council (“LEC”) that is administered by the Industrial Commission of North Dakota and is designed to encourage construction of a new baseload power plant in North Dakota. Project proposals were also submitted by MDU Resources Group, Inc. (“MDU”), Great River Energy and Great Northern Properties. MDU and WPI have joined together to pursue development of a new lignite fired generation unit near Gascoyne, North Dakota and executed a joint development agreement. On September 27, 2001, the Industrial Commission approved the joint MDU-WPI project and awarded up to $10 million in matching funds to facilitate feasibility and various technical studies after approval of the joint project WPI and MDU each own a 50% interest in the project.
Westmoreland Terminal Company, a wholly owned subsidiary of the Company, owns a 20% interest in Dominion Terminal Associates (“DTA”), the owner of a coal storage and vessel-loading facility in Newport News, Virginia. The Company leases ground storage space and vessel-loading capacity and facilities to others and provides related support services. DTA’s annual throughput capacity is 22,000,000 tons, with a ground storage capacity of 1,700,000 tons. DTA loaded 7,980,000, 7,160,000 and 8,357,000 tons in 2001, 2000 and 1999, respectively. The Company’s portion of these tons was 197,000, 163,000 and 379,000 in 2001, 2000 and 1999, respectively.
The Company idled the Virginia Division in 1995 and completed the sale of substantially all its assets by 1999. No tons were shipped from the Virginia Division during 2001, 2000 or 1999. Asset sales in 1999 resulted in proceeds, before selling costs, of approximately $726,000. There were no asset sales during 2001 or 2000. The Company is in the process of selling the Bullitt refuse area, the last of the Virginia Division assets the Company now owns. The refuse area has no recorded value. An application to transfer the refuse area permit to the buyer was filed with the Virginia Division of Mine Land Reclamation in February 2001.
Refer to Note 13 of the Consolidated Financial Statements for additional information regarding the Company’s business segments.
The Company, including subsidiaries, directly employed 918 people on December 31, 2001, compared with 31 people on December 31, 2000.
The Company and Basin were parties to separate and distinct wage agreements with the United Mine Workers of America (“UMWA”), which were effective December 16, 1993 (the “1993 Agreement”) and expired on August 1, 1998. The Company is not a party to any subsequent wage agreement with the UMWA; however, WECO is a party to an agreement with Local 400 of the International Union of Operating Engineers (“IUOE”) and DWC and Savage assumed agreements with Local 1101 of the UMWA and Local 400 of the IUOE, respectively, when the coal assets were purchased from Knife River Corporation.
The coal industry is highly competitive. The Company competes principally on price and quality of coal with other coal producers of various sizes. However, the Company has a transportation advantage where its mines are located adjacent to its customers’ power plants. The Company’s production accounted for less than 2% of coal production in the United States in 2001. Coal-fired generation was responsible for approximately 54% of all electricity generated within the United States in 2001.
The Company’s steam coal production 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 will be 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 $5.60 per MMBTU in February 2001 to a low of $1.70 per MMBTU in November 2001) making the relative price stability in the coal market a significant contributor to renewed interest in constructing new, more environmentally friendly coal-fired generation.
The Company also generates electricity directly from projects in which WEI owns an interest, and sells 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. In the initial years following implementation of deregulation, prices for electricity were quite competitive in some states as a result of low fuel prices and a relatively high level of surplus capacity. Increasing energy demand, volatile fuel prices, and the failure of growth in generating capacity to keep pace with the increase in demand for power converged in 2000 to result in power shortages and higher electricity prices in many parts of the country. This helped create renewed interest in coal-fired capacity and more than 65,000 megawatts of planned additions had been announced as of December 2001.
The principal sources of competition in this market 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 WEI and WPI. 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. New generating capacity must compete today on a unit per kilowatt basis and be capable of complying with stringent environmental regulations.
Westmoreland Terminal Company is subject to competition from both domestic and international providers of coal transloading services. A significant portion of the coal shipped from DTA is exported to foreign locations. Coal suppliers from Australia, South Africa, China, Indonesia and a number of other foreign locations provide similar services.
Westmoreland places the safety of its employees above all else and has an active safety and education program at every operation. NWR had worked over the last sixteen months in excess of 1,100,000 man-hours without a lost time accident before experiencing a minor accident in February 2002. The Company’s mining operations are subject to state and federal legislation including the Federal Coal Mine Safety and Health Act of 1969 and the 1977 Amendments thereto, which prescribes mining health and safety standards. In addition to authorizing fines and other penalties for violations, the Act empowers the Mine Safety and Health Administration to suspend or halt offending operations.
The highly publicized California energy crisis sparked renewed interest in a national energy policy based on a multi-pronged strategy involving energy efficiency and conservation, and maximizing domestic resources. Increased coal utilization and additional federal funding for clean coal research and technologies are prominently featured in the national energy policy debate. As a direct consequence, interest in building new coal-fired generation has increased. Many new generating facilities, including the Company’s potential LV-21 project, have been publicly announced.
At both the national and state level, the debate about deregulation of electricity and the creation of competitive markets for wholesale and retail sale of electricity have continued. While events in California during 2001, including rolling blackouts and extreme market fluctuations in energy prices, have influenced the debate, many states and the federal government continue to consider creating competitive wholesale and retail power markets. System reliability and transmission issues, including wheeling power from one system to another and system constraints (insufficient line capacity to add new 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. Enron’s recent failure will likely cause the move to unrestricted market competition to slow even more. The public debate once again includes reference to regulatory concepts like “fair and reasonable rates” for not only transmission of electricity but also generation of electricity
WEI’s ROVA I and ROVA II generating units are located in Weldon, North Carolina. These facilities are EWGs. EWG status allows the ROVA facilities to operate with certain exemptions from federal and state regulation. Pursuant to the provisions of the National Energy Policy Act of 1992, an EWG can provide power without the requirement that it also sell thermal energy as a Qualifying Facility (“QF”) must. An EWG can be a QF as defined in the Public Utilities Regulatory Policies Act of 1978 but is not required to maintain QF status. EWGs that are not QFs must have rates approved by the Federal Energy Regulatory Commission (“FERC”). Both ROVA I and ROVA II have rates approved by FERC.
Mining Operations. The Company believes its mining operations are in compliance with applicable federal, state and local environmental laws and regulations, including those relating to surface mining and reclamation, and it is the policy of the Company to operate in compliance with such standards. The Company maintains compliance primarily through the performance of reclamation, maintenance and monitoring activities. Utilization of coal to generate electricity produces certain by-products, the emission of which is subject to Federal regulation. Depending on coal purity and the combustion process, the emission by-products may include nitrogen oxide, sulfur dioxide, carbon dioxide and mercury. Emission levels vary among generating units. The newer an electric generating unit, the fewer emissions are produced in the combustion process.
Clean Air Act
In 1990, certain amendments to the Clean Air Act (“1990 Amendments”) were enacted. As the first major revisions to the Clean Air Act since 1977, the 1990 Amendments vastly expanded the scope of federal regulations and enforcement in several significant respects. In particular, the 1990 Amendments required that the United States Environmental Protection Agency (“EPA”) consider or issue new regulations related to ozone non-attainment, air toxics and acid rain. Phase I of the acid rain provisions required, among other things, that certain electric utility power plants reduce their sulfur dioxide (SO2) emissions to effectively less than 2.5 pounds per million Btu by January 1, 1995. Phase II required essentially all utility power plants to reduce emissions to effectively less than 1.2 pounds per million Btu by January 1, 2000. The 1990 Amendments allow utilities the freedom to choose the manner in which they will achieve compliance with the required emission standards. Recently, both the EPA and Congress have become more focused on promulgating some type of air toxics regulation. All coal-fired generating plants could be impacted by such regulations. The Company cannot currently determine the effect of such proposed regulations or the Clear Skies and Global Climate Change Initiatives on its operations.
Clear Skies and Global Climate Change Initiatives
On February 14, 2002, President Bush announced two major initiatives. The Clear Skies Initiative proposes cuts in power plant emissions of nitrogen oxides (NOX); sulfur dioxide (SO2) and mercury. Under the President’s plan, SO2 emissions will be reduced 73% from current levels of approximately 11 million tons to a cap of 4.5 million tons in 2010 and 3 million tons in 2018. NOX emissions will be reduced by 67% from current levels of approximately 5 million tons to a cap of 2.1 million tons in 2008 and 1.7 million tons in 2018. Mercury emissions will be reduced by 69% from current levels of approximately 48 millions to a cap of 26 million tons in 2010 and then to 15 million tons in 2018. This policy initiative envisions use of an emissions permit limit program modeled after the 1990 Clean Air Act Acid Rain Program and encourages use of new and cleaner pollution control technology. All coal-fired generating plants could be impacted by President Bush’s or a similar proposal. The Company cannot currently determine the effect of the Clear Skies Initiative on its operations.
President Bush also unveiled his Global Climate Change Initiative, which calls for a cut in greenhouse gas intensity by 18% over the next ten years. Greenhouse gas intensity is the ratio of greenhouse gas emissions to economic output. The Global Climate Change Initiative seeks to lower the United States rate of emissions from an estimated 183 metric tons to 151 metric tons per million dollars of gross domestic product. The Global Climate Change Initiative is comparable to the average progress that nations participating in the Kyoto Protocol are required to achieve.
State Initiatives
State specific environmental legislation may impact Company operations. For example, Texas has passed new regulations requiring all fossil fuel fired generating facilities in the state to reduce NOx emissions to 0.165 pounds per million Btu on an annual average basis beginning in May 2003. The Texas NOx regulations may impact lignite usage at LEGS. See Item 7, Managements Discussion and Analysis, for more information. Other states are evaluating various strategies for improving air quality and reducing emissions. Passage of other state specific environmental laws may further affect the Company’s operations. The Company is monitoring events and issues to evaluate the effects of any new environmental law or regulations.
Mine Reclamation
As of December 31, 2001, the Company has reclamation bonds in place in Montana, North Dakota, Texas, and Virginia to assure that operations comply with all applicable regulations and to assure the completion of final reclamation activities. The amount of the bonds exceeds the estimated cost of final reclamation of $235,321,000. Final reclamation obligations estimated to cost $50 million at the Jewett Mine are the responsibility of its customer, Reliant, which has posted a reclamation bond for that amount. At the Rosebud and Absaloka Mines, certain customers and WRI’s contract miner are obligated to either perform or reimburse the Company for certain reclamation activities as they are performed. These reclamation activities are estimated to cost approximately $23,700,000. As of December 31, 2001, WML had $47,924,000 in cash escrowed and invested to use for future reclamation activities at the Rosebud Mine, which activities are estimated to cost approximately $132,500,000 and will be performed through approximately 2025.
Reclamation of the Bullitt refuse area continues to be deferred as the permit transfer application in connection with the Company’s proposed sale of the area to a local operation is being evaluated by the Virginia Division of Mined Land Reclamation. The estimated cost of approximately $800,000 to reclaim this site has been accrued.
Independent Power. The environmental laws and regulations applicable to the projects in which WEI and WPI may or do participate primarily involve the discharge of emissions into the water and air, but can also include waste disposal, wetlands preservation and noise regulation. These laws and regulations in many cases 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 partnerships that own the projects in which WEI has an interest and the partnership through which WPI and MDU are pursuing the LV-21 project have the primary responsibility for obtaining the required permits and complying with the relevant environmental laws.
On December 17, 1999, the EPA issued a Section 126 rule calling for combined NOX 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 ROVA I and II. The additional NOX reductions were to begin in 2003. The rule responds to petitions filed by several northeastern states under Clean Air Act Section 126 and seeks to control upwind NOX emissions which the petitioning states allege prevent them from attaining the one hour ambient air quality standard (.15 ppm) for ozone. The rulemaking approach is an alternative to regional NOX reductions called for in the EPA NOX State Implementation Plan Call which was challenged by industry groups. One of the most significant differences between the NOX SIP Call and the Section 126 rule is that under the Section 126 rule, the EPA regulates the individual source directly. Each source is assigned an emissions allocation. The baseline for 2003-2007 NOX emissions allocations is the average of the highest date for any two years in the 1995-1998 period. Allocation budgets will be updated in five-year increments and the EPA will inform sources of their allocations three years in advance. Initial allocations for the ROVA projects beginning in 2003 were published in the December 17, 2000 EPA rule.
On May 15, 2001, the U.S. Court of Appeals for the D.C. Circuit upheld the majority of the EPA’s Section 126 rule but required certain additional justification from the EPA on factors to be used in estimating utilization in 2007. The court’s decision had the effect of suspending the EPA’s effort to impose controls on named sources. The Company expects that after the EPA submits the information that the court has requested, implementation of the Section 126 rule will resume.
At this time, the independent power projects in which the Company owns an interest are evaluating strategies for complying with the Section 126 rule. In 2000, the ROVA project partnership installed neural networks in the boilers. The neural network increases boiler efficiency and reduces NOx and carbon monoxide (CO) emissions. While the neural network reduces the level of NOx and CO emissions from the ROVA I and ROVA II power plants, the ROVA project partnership is evaluating additional compliance strategies, including emission trading. Replacement or upgrades to ROVA’s continuous emission monitoring (“CEM”) system are being evaluated.
Dominion Terminal Associates. DTA is responsible for complying with certain state and federal environmental laws and regulations, particularly those affecting air and water quality. DTA has employees on its staff who are responsible for assuring that it is in compliance. In the event that DTA failed to comply, the Company could be responsible for a 20% share of any expense incurred.
The demand for the power produced by the generating units that are supplied by the Company’s mines and owned by the independent power projects in which the Company holds an interest tend to be higher in the winter and summer months and lower in the spring and fall months. While all of these generating units are base loaded, the demand for their power may also be affected by maintenance outages.
The Company’s assets and operations are, and for each of the last three years have been, located entirely within the United States. There have been no export sales during the last three years.
As of December 31, 2001, the Company owned or leased coal properties located in Montana, Texas, North Dakota, and Virginia. The 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. The Company includes in “coal reserves” 107,000,000 tons that are not fully permitted but that otherwise meet the definition of “coal reserves.” A description of the permitting process and the Company’s assessment of that process as applied to these 107,000,000 tons follows the table 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 stage work. This coal does not qualify as a “coal reserve” until, among other things, a final comprehensive evaluation based upon unit cost per ton, recoverability, and other material factors conclude legal and economic feasibility.
The following table shows the location of the Company’s estimated coal reserves, coal deposits, production in 2001 and other mine information. All of the coal is used in steam boilers to produce electricity.
Summary of
Coal Reserves, Deposits, Production
and other
Mine Information
as of
December 31, 2001
| Absaloka Mine |
Rosebud Mine |
Jewett Mine |
Beulah Mine |
Savage Mine |
|
| Location | Hardin, MT | Colstrip, MT | Jewett, TX | Beulah, ND | Savage, MT |
| Coal Reserves: (thousands of tons) |
|||||
| Proven (1) | 64,186(2) | 263,808 | 114,051(2) | 52,011 | 15,828 |
| Probable (3) | 0 | 0 | 0 | 12,253 | 4,665 |
| Coal Deposits (4) (thousands of tons) |
542,197 | 283,993 | 0 | 0 | 0 |
| Sulfur Percent (5) | .64 | .72 | 1.02 | 1.00 | .45 |
| 2001 Annual Production (thousands of tons) |
5,904 | 11,284 | 7,138 | 3,087 | 346 |
| Year Opened | 1974 | 1924 | 1985 | 1963 | 1958 |
| # of Draglines | 1 | 4 | 4 plus bucketwheel | 2 | 1 |
| Delivery | Rail | Truck/Rail/ Conveyer |
Conveyer | Conveyer/Rail | Truck |
| (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 has been committed by the Company to operating mining equipment and plant facilities. |
| (2) | Includes tons for each mine as described below that are not fully permitted but otherwise meet the definition of “proven” coal reserves. |
| (3) | Probable reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation. |
| (4) | All coal deposits have been assigned by the Company to operating mining equipment and plant facilities. |
| (5) | Percent Sulfur applies to the 2001 production tons. |
Absaloka Mine
WRI owns the Absaloka Mine, a surface (open pit) coal mine located in Big Horn County, Montana and has been the only operator on the property. The mine is located in the upper Sarpy Creek drainage, 35 miles south of Hysham and 30 miles east of Hardin via Route 384. The mine is accessed from Route 384 via County Road 42. Mine facilities consisting of a truck dump, primary and secondary crushers, conveyors, coal storage barn, train loadout, rail loop and support facilities including shop, warehouse, boiler house, deep well and water treatment plant were constructed beginning in late 1972 and completed in early 1974. Power is purchased under a long-term contract with the local utility. The primary excavating machine (completed in 1979) is a Bucyrus-Erie 2570W walking dragline with a bucket capacity of 110 cubic yards and is owned by WRI. The present sustainable mine capacity using the dragline is 6.5 million tons per year; production of 5.9 million tons in 2001 was approximately 91 percent of capacity. Mobile equipment, including loaders, haul trucks, scrapers, dozers, graders, water trucks and fuel truck are owned by WRI’s mining contractor and minority owner, Washington Group. WRI’s total cost for the foregoing mine facilities incurred through 2001 is approximately $76,000,000. The Company anticipates spending an additional $500,000 no later than 2007 to permit an additional mining area within its present mine plan. WRI does not believe additional exploration or development of this area is necessary other than obtaining future mining permits.
The first unit train coal shipment was loaded July 1, 1974. Initially, coal was produced from the Rosebud-McKay and Robinson coal seams; attempts were also made to recover coal from two thin rider seams identified as the Stray-1 and Stray-2. The Stray-1 is in the overburden 10 to 30 feet above the Rosebud. It is of erratic structure and quality, and for this reason initial efforts to recover a marketable product were unsuccessful, and it has been excavated as overburden. The Stray-2 underlies the Rosebud-McKay by one to six feet. The Stray 2 is relatively high in ash and sulfur, and for several years it was blended with the primary seams. Such blending resulted in erratic quality, and it was abandoned in 1985. The Robinson coal underlies the Rosebud-McKay coal by 60 to 100 feet.
In 1988, WRI began supplying coal to a new generating unit designed by its customers to burn coal from the Absaloka Mine, but almost immediately severe slagging problems were encountered. The problem was traced to coal from the Robinson seam. The plant owners notified WRI that they would no longer accept Robinson coal, and consequently, mining of the Robinson seam was discontinued in 1990. Hence, the only seam now being mined is the Rosebud-McKay seam, which is actually two seams separated by a thin parting ranging in thickness from a few inches to several feet. The total aggregate coal thickness in the Rosebud and McKay seams averages 32 feet. The coal is subbituminous C grade with an average heating value of 8,700 Btu/lb. and 0.64 percent sulfur as received.
All coal reserves and coal deposits shown in the previous table in the column captioned “Absaloka Mine” are leased by WRI from the Crow Tribe of Indians to exhaustion of the mineable and merchantable coal. WRI is evaluating the acquisition of the rights to additional reserves or deposits contiguous to its existing leases. The Company believes that all such deposits and reserves are recoverable through existing facilities with current technology and the Company’s existing infrastructure. These reserves and deposits were estimated to be 799,803,000 tons as of January 1, 1980, based principally upon a report by Intrasearch, Inc., an independent firm of consulting geologists, prepared in February 1980. Estimated remaining tons are reduced annually by production in the Rosebud-McKay seam and by the amount of coal in the Robinson, Stray-1 and Stray-2 seams bypassed after mining the Rosebud-McKay seam. Through 2001, approximately 117,475,000 tons of coal have been shipped to customers, primarily in the upper Midwest for use as steam coal. Transportation is arranged and charges are paid by WRI’s customers. There have been no significant problems with operation of the coal handling plant. The only significant operating problem has been spoil stability in high overburden areas.
The mining and reclamation permit application process operates under regulations of the Office of Surface Mining (“OSM”) and the State of Montana under its OSM approved program. Among the requirements are detailed pre-mining inventories of environmental resources including soils, vegetation, wildlife, hydrology and archaeology. The application must include detailed plans for mining, reclamation and protection of hydrological resources. The process includes an exhaustive review of the application for compliance with all applicable regulations. After initial review of the application, the regulatory authority issues a letter reviewing deficiencies in the application to which the applicant responds by revising the application where appropriate. This process of identifying and responding to deficiencies is repeated until all matters are cleared. The decision document and environmental assessment are subject to formal public review, including public hearings if requested. The process typically takes two to four years from the time the initial application is filed.
A total of 3,307 acres have been disturbed by mining. Reclamation is complete on 2,336 acres, with the balance involved in active mining operations. The reclamation bond, which is posted by WRI and is an estimate by the Montana Department of Environmental Quality of total cost to reclaim, is $10,614,000. However, except for a small percentage funded by WRI, Washington Group is contractually responsible for reclaiming the property, whatever the cost. After reclamation is complete, WRI is responsible for maintaining and monitoring the reclaimed property until the bond is released. For the property mined through December 31, 2001, WRI’s estimated future cost of maintaining and monitoring such property prior to bond release is approximately $1,500,000 to $2,000,000.
WRI has chosen not to permit all of the coal reserves in its mine plan because it already has sufficient permitted coal to meet production, given the current rate of mining and demand, through 2008. It is anticipated that an application covering an estimated 30 million tons of unpermitted reserves will be filed in the first half of 2003. Based upon the Company’s current knowledge of the permitting process and the nature of these reserves, the Company believes that there are no matters that would hinder its ability to obtain this mining permit on a timely basis.
Rosebud Mine
WECO was acquired by WML on April 30, 2001. Rosebud Mine coal comes from the Rosebud Seam in the Montana portion of a much larger deposit commonly identified as the Powder River Basin. The Rosebud Mine is an open-pit or surface mine; WECO uses four draglines in a single pass system to uncover one seam of coal. There are three 60 cubic yard capacity draglines purchased in 1975, 1976 and 1980 and one 75 cubic yard dragline purchased in 1983. The draglines use electric power purchased from Montana Power under standard individual tariffs. The machines operate primarily on the highwall side of the pit with an extended bench that is developed by large production tractors. Coal is excavated from the seam using 17 to 25 cubic yard electric shovels and loaded on 120 to 200 ton bottom dump trucks. The trucks haul the coal to one of three crushing facilities where it is loaded directly on conveyors and transported to the four Colstrip units. Both the overburden and coal are drilled and blasted prior to excavation. Other equipment used at the Rosebud Mine includes overburden and coal drills, dozers, water wagons, motor blades, front end loaders, scrapers and numerous support equipment including service trucks, pumps and cranes. The Rosebud Mine has multiple maintenance and support facilities and administration buildings. The mine work force is represented by Local 400 of the IUOE. The Burlington Northern Santa Fe Railroad transports production to rail-served customers. The Rosebud Mine is equipped with a loop track and tipple facility capable of loading unit trains at the rate of 4,000 tons per hour.
The Rosebud Mine is located at Colstrip, Montana, 130 miles east of Billings. The Northern Pacific Railroad began mining coal for its steam locomotives at Colstrip in 1924. The railroad produced approximately 44 million tons of coal from these reserves before adapting to diesel locomotives in 1958. In 1959, Montana Power purchased the coal leases, mining machinery and Colstrip town site to produce coal for future thermal generating plants, and for sale to others. The total cost of the mine incurred through 2001 is approximately $192,000,000.
WECO was formed as a wholly owned Montana Power subsidiary in 1966 to operate the Rosebud Mine. Initial production was shipped to Montana Power’s Corette Plant at Billings, and to utilities and municipalities in the upper Midwest. Major coal supply contracts were signed with two upper Midwest utilities in the early 1970‘s and in 1980 contracts were finalized for two new 750-MW mine-mouth generating plants at Colstrip. These long-term contracts provided the foundation for a major expansion of the Rosebud Mine. The mine’s production of 11.7 million tons of coal in 1979 steadily grew to 16 million tons in 1988. The Rosebud Mine has consistently ranked among the largest single coal mines in the nation, based on annual production.
All coal reserves and coal deposits shown in the foregoing table in the column captioned “Rosebud Mine” are in Montana and leased by WECO from the federal government, Great Northern Properties, or the State of Montana. The royalty payable under federal leases adjusts every ten years, and the leases remain in effect as long as minimum commercial quantities of coal are mined. WECO annually mines at least the minimum tonnages required to keep the leases current. Great Northern leases were renewed in 1989 for a term of 30 years, and the royalty payable under these leases adjusts every five years. The state leases remain current as long as commercial quantities are produced or as long as they are under a valid mining permit. These reserves and deposits were estimated to be 560,552,000 tons as of January 1, 1998, based principally upon a reserve study prepared for a Logical Mining Unit Application to the Bureau of Land Management. This reserve study was prepared by the Environmental and Engineering Department of WECO while it was owned by Montana Power. The coal consists exclusively of the Rosebud seam. In 1999, WECO successfully bid on an additional 29,110,000 tons of federal coal and these reserves were added. The Company believes that all held deposits and reserves are recoverable through existing facilities at the Rosebud Mine with current technology and the Company’s existing infrastructure. The coal has an average heating value of 8,500 Btu/lb. and 0.72 percent sulfur as received. Through 2001, approximately 323,001,000 tons of coal have been produced and shipped from the Rosebud Mine to the Colstrip power plants and utility customers in Billings, Montana and the upper Midwest for use as steam coal. Transportation charges are paid by WECO’s customers. There have been no significant problems with operation of the coal handling plant.
A total of 13,969 acres have been disturbed by mining of which reclamation is complete on 6,505 acres, with the balance involved in active mining operations. The reclamation bond, which is posted by WECO and is an estimate of total cost to reclaim, is $163,334,000. After reclamation is complete, WECO is responsible for maintaining and monitoring the reclaimed property until the bond is released at an estimated cost of $2,000,000 to $2,500,000.
The permit application process is subject to the regulations of the State of Montana under its OSM approved program. Among the requirements are detailed pre-mining inventories of environmental resources including soils, vegetation, wildlife, hydrology and archaeology. The application must include detailed plans for mining, reclamation and protection of hydrological resources. The process includes an exhaustive review of the application for compliance with all applicable regulations. After initial review of the application, the regulatory authority issues a letter reviewing deficiencies in the application to which the applicant responds by revising the application where appropriate. This process of identifying and responding to deficiencies is repeated until all matters are cleared. The decision document and environmental assessment are subject to formal public review, including public hearings if requested. The process typically takes two to four years from the time the initial application if filed.
WECO 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 2007. Based upon the Company’s current knowledge of the permitting process and the nature of remaining reserves, the Company believes that there are no matters that would hinder its ability to obtain additional mining permits in the future.
Jewett Mine
NWR owns and leases coal properties for the Jewett Mine, an open-pit mine in East Texas, approximately half way between Dallas and Houston west of Interstate Highway 45. The properties are located in Leon, Freestone, and Limestone Counties and are accessed on Farm to Market Road 39. The surface and coal leases for the Jewett Mine are all under private ownership. Most leases are for a term of 25 to 35 years although a few extend to 50 years. The term of the primary leases expire from 2004 to 2025 but are renewable if coal production is being done in the required radius area. The Jewett Mine was developed pursuant to an agreement with Reliant (formerly Houston Lighting and Power) calling for production of “the most economic 240,000,000 tons” from the project area to supply the nearby LEGS. The coal deposit was evaluated through a series of exploration programs, including physical and chemical analysis, according to those criteria. As of December 31, 2001, a total of 125,949,000 tons have been produced and sold leaving 114,051,000 tons remaining. The Company believes that all such reserves are recoverable through existing facilities and with the Company’s existing infrastructure.
Mine facilities consist of a truck dump, crusher, conveyors, coal storage, shop/warehouse complex, administrative support buildings, and water treatment facilities. The contract with Reliant requires that all equipment and facilities be maintained such that they continue to be serviceable and support production comparable to the original specifications. Total capital cost to develop the mine was approximately $54,000,000 as of December 31, 2001.
Overburden removal is scheduled 24 hours per day, 7 days per week. Where total overburden thickness exceeds 180 feet, trucks and loaders are utilized to prebench to a 180-foot level. Draglines then work to expose the lignite seams. Depending on overburden depths and seam geometry, the dragline may take as many as two highwall passes and three spoilside passes to complete a pit. Pit widths vary from 100 to 200 feet with a 140-foot pit being normal. Overburden depths vary from 20 to 240 feet. When the draglines cannot uncover sufficient lignite to meet fuel deliveries, additional prebenching below the aforementioned 180 feet level is required. This reduces the amount of dragline overburden, thus increasing lignite release. The BES system operates in a single mine area to reduce the dragline overburden to a predetermined depth. Once the lignite is exposed it is removed utilizing backhoes, front-end loaders, and 150-ton bottom dump coal haulers. The lignite seams vary in thickness from 1.5 feet to 15 feet. The coal haulers transport the lignite to the coal handling facilities where it is crushed and delivered to the power plant by means of a conveyor belt.
The mine has been in continuous operation by NWR since 1985 and consists of four active areas with as many as four lignite seams within each area. Lignite is a dark brown to black combustible mineral formed over millions of years by the partial decomposition of plant material subject to increased pressure and temperature in an airless atmosphere. Lignite is coal with a lower grade and Btu value. Because of its lower heat value, lignite typically can serve only contiguous power generating units. Overburden removal is accomplished with four draglines, a bucketwheel excavator system and/or a truck and shovel fleet. The primary excavating machines consist of three walking draglines with bucket capacities of 84 cubic yards, one walking dragline with a bucket capacity of 128 cubic yards, and one around-the-pit Bucketwheel Excavator System (“BES”). Additional mobile equipment consists of dozers, scrapers, end dump trucks, bottom dump trucks, front-end loaders, and backhoes. The aforementioned equipment is owned by Reliant and is leased by NWR on an annual basis. Electrical power for the facilities and major stripping equipment is generated by the Brazos River Authority and transferred to the mine site by Navasota Valley Electric Cooperative.
The first ton of coal from the Jewett Mine was sold in July 1985. The four primary seams are named the #3, #4, #5, and #6 seams. Interburden ranging from one foot to 70 feet in thickness separates them. The total aggregate coal thickness from all four seams is approximately 15 feet. All of the coal mined from the Jewett Mine is shipped approximately one mile, via conveyor, from the crushing facility located at the mine to LEGS. The lignite has an average heating value of 6,670 Btu/lb. and 1.02 percent sulfur as received.
Initially, the mine operated with the three Marion 8200 walking draglines. In 1990, due to increased overburden depth, the BES was put into operation. In 1997, due to increased depth of overburden and increased delivery demands by LEGS, a fourth dragline, the Marion 8750, was put into operation. On average, the mine has sold 7.8 million tons of coal per year for 16 years.
Exploration work for the project area was initiated in the late 1970s, and initial reserve estimates were prepared by NWR engineers and geologists while NWR was owned by Montana Power. NWR engineers and geologists initially estimated the coal deposits and reserves. To further define the coal reserve, exploration drilling was utilized to delineate that part of the deposit that met an economic depth and strip-ratio. Based on the economic depth and strip-ratio, coring was conducted on 1000-foot centers and then on 500-foot centers to develop the proven reserves. Core samples were taken on 1000-foot centers and were analyzed for physical and chemical parameters. Electronic logs were taken on 500-foot centers. Additional drilling was conducted to further define the limits of the coal seams. As of December 31, 2001, all planned exploration is complete for the life-of-mine coal reserve.
Reclamation activities follow mining. The dragline spoils are regraded to an approximate original contour and are covered with a minimum of four feet of suitable plant growth material. The area is then seeded and mulched.
To date, the mine has regraded and revegetated 10,669 acres; at any given time there are approximately 500 to 600 acres disturbed in association with the pit, prebench and unregraded spoil. The reclamation bond, which is posted by NWR and by a Reliant self-bond, exceeds the total estimated cost to reclaim the mine. Under the current contract with Reliant, NWR performs the reclamation work and the cost is passed through to Reliant. This will change in June 2002 so that NWR will perform the reclamation work on current mining including “final” pits in each area as part of its cost of mining. Final reclamation of the Jewett Mine, at the end of its useful life, is the financial responsibility of Reliant.
The surface coal mine permitting process is regulated by the Railroad Commission of Texas (“RCT”) under its OSM approved program. Some of the information required for permitting includes detailed premining inventories of environmental resources including soils, vegetation, wildlife, hydrology and archaeology. The application must include detailed plans for mining, reclamation and protection of hydrological resources. The permit preparation process takes in excess of a year. The regulatory review and approval process includes an exhaustive review of the application for compliance with all applicable regulations. After initial review of the application, the regulatory authority issues a letter reviewing deficiencies in the application to which the applicant responds by revising the application where appropriate. This process of identifying and responding to deficiencies is repeated until all matters are cleared. The decision document and environmental assessment are subject to formal public review, including public hearings if requested. The process typically takes eighteen months to two years from the time the initial application is filed.
A permit term encompasses five years of mining. Jewett currently holds two mining permits. Permit 32E is a renewal of the same general permit area that has been in place and actively mined since 1985; it encompasses 21,324 acres. The current term for 32E is July 1998 through July 2003. This permit renewal submittal is scheduled to go to the RCT in the first quarter of 2002. The renewal term will be from the date of the RCT approval (projected to be approximately July 2003) through July 2008. Permit 47 is a new permit area encompassing approximately 9,341 acres; it is located contiguous to Permit 32E. The current term for Permit 47 is December 2001 through December 2006.
Prior to any surface mining activity, all surface improvements are removed or relocated from the immediate area. These include buildings, utilities, oil/gas wells and pipelines, county roads, railroads, and public highways. Drainage control facilities such as sedimentation ponds and diversions are constructed during this phase of operations to control runoff from all areas to be disturbed during mining. Clearing and grubbing takes place in advance of overburden removal operations and includes staking and burning of trees and brush. Dewatering/depressurization wells are installed a minimum of one year in advance of mining activities for the purpose of ground water control. Trucks and loaders selectively handle suitable plant growth material in advance of mining. A minimum of four feet of this suitable plant growth material is transported to the regraded areas of the spoil to reconstruct the surface area for revegetation.
Beulah Mine
DWC operates the Beulah Mine in Beulah, North Dakota. This property was purchased as of April 30, 2001 from Knife River Corporation. The mine and support facilities are located between the two mining areas and service both. Total capital cost to develop the mine was approximately $70,000,000 as of December 31, 2001. Mine facilities consist of a truck dump hopper, primary and secondary crushers, conveyors, train loadout, railroad spur, coal storage bin and coal stockpile. The coal preparation facilities will prepare the coal for transport via conveyor to the Coyote power plant or for loading onto railroad cars for shipment to the Heskett power plant. There is no wash plant at this mine site. The support facilities include several maintenance shops, equipment storage buildings, warehouse, employee change houses and mine office and trailers. Power for the mine is purchased from the local electric utility. The two primary excavating machines are a walking dragline with a bucket capacity of 17 cubic yards operates in the West Brush Creek area and a walking dragline with a bucket capacity of 84 cubic yards removes overburden at East Beulah. Additional major equipment utilized at the mine include a Caterpillar 5130 track excavator and three end-dump trucks, a coal loading shovel, rubber tired loaders, haul trucks, scrapers, dozers, motor graders, water trucks, and coal drills.
The Beulah Mine is a surface (open pit) coal mine located in Mercer and Oliver Counties, North Dakota. The mine is approximately 2 miles south of Beulah. The mine is accessed from North Dakota Highway 49. There are currently two separate mining permits that cover the Beulah Mine. These permits are referred to as the West Brush Creek area and the East Beulah area. Acreage contained within the current permit area for West Brush Creek amounts to approximately 1,030 acres. The Company has private and state surface leases that cover the permit area. The East Beulah current permit area contains approximately 4,289 acres. All surface rights are leased from private owners, with the Company having federal, private and state coal leases which expire from 2009 to 2019. The mine has been open at the current location since 1963 and the coal from this operation supplies the fuel requirements for the adjacent Coyote Generating Station and the Heskett Generating Station in Mandan, North Dakota.
The estimated total owned and leased coal reserves at this site were approximately 64,264,000 tons at December 31, 2001. The Company believes all of these reserves are recoverable through existing facilities with current technology and existing infrastructure. Reserves were estimated to be 73,010,000 tons as of January 1, 1999, based principally upon a report prepared by Weir International Mining Consultants, an independent consulting firm. Presently, the mine produces approximately 3,000,000 tons of coal annually.
Of the lignite beds, the Beulah-Zap Seam is the most consistent in quality, lateral continuity and thickness. The Beulah-Zap seam, ranging in thickness from 10 to 12 feet, is the primary focus of mining in both reserve areas. Several other seams are contained within the stratigraphic package above and below the Beulah-Zap. Among these is the Schoolhouse seam, which lies 45-50 above the Beulah-Zap and is also being mined in the East Beulah area. The Schoolhouse seam averages 6 feet in thickness. A lower bench of the Beulah-Zap seam, referred to as the Beulah-Zap lower seam, or BZ-2, is also being mined in the East Beulah mine area. The BZ-2 seam ranges in thickness from 2 to 4 feet. Three individual seams are mined in the East Beulah area and only one in the West Brush Creek area, all with varying in-place quality characteristics. These coals require blending in order to assure consistent product quality. At the present time, nearly all coal blending is conducted in-pit through the scheduling of daily production from different areas and different seams. A quality control engineer is assigned the task of determining the in-place quality parameters and scheduling production accordingly. Estimated overall quality of the coal at the Beulah Mine is an average heating value of 7,000 Btu/lb and 1.00 percent sulfur as received.
Of the 5,319 permitted acres, 3,922 acres have been disturbed by mining. Reclamation has been completed on 2,584 acres, with the balance involved in active mining operations. The reclamation bond, which is posted by the Company and is an estimate of the total cost to reclaim the mine, is $10,730,000. The North Dakota Public Service Commission does not require mining operations to bond for facility removal or for the post-mining reclamation monitoring period. After all reclamation has been completed, the Company is responsible for maintaining and monitoring the reclaimed property until the bond is released, which is a minimum of 10 years after the final seeding has occurred. The Company estimates the cost of maintaining and monitoring the property prior to bond release will be $1,500,000.
Of the total reserves shown, approximately 4.5 million tons in the West Brush Creek area and 7.5 million tons at East Beulah are fully permitted at this time. Based on the current estimated production rates of 500,000 and 2,500,000 tons respectively, there are roughly 9 and 3 years remaining under the current permitted mine plans. The permit application process is subject to the regulations of the OSM and the State of North Dakota under its OSM approved program which is regulated by the North Dakota Public Service Commission. Among the requirements are detailed pre-mining inventories of environmental resources including soils, vegetation, wildlife, hydrology and archaeology. The application must include detailed plans for mining, reclamation and protection of the hydrological resources. The process includes an exhaustive review of the application for compliance with all applicable regulations. After initial review of the application, the regulatory authority issues a letter outlining deficiencies in the application to which the applicant responds by revising the application where appropriate. This process of identifying and responding to deficiencies is repeated until all matters are addressed. The decision document and environmental assessment are subject to formal public review, including public hearing if requested. This process can take anywhere from one to three years from the time the initial application is filed. Based upon the Company’s current knowledge of the permitting process and the environmental issues which were associated with the permitted reserves, the Company believes that there are no matters that would hinder its ability to obtain any mining permits in the future. The Company is preparing a permit revision for the East Beulah area that will be submitted in the summer of 2002 to add approximately 700 acres that will extend the tons permitted to accommodate five years’ production at current rates.
Savage Mine
Savage is the current operator of the Savage Mine in Eastern Montana. This property was also purchased in 2001 from Knife River Corporation. Mine facilities consist of a truck dump, near-pit portable crushing unit, conveyors, coal stockpile; support facilities include a shop, warehouse and mine office. Total capital cost to develop the mine was approximately $7,000,000 as of December 31, 2001. There is no wash plant at this mine site. Power for the mine is purchased from the local electric utility. The primary excavating machine is a walking dragline with a bucket capacity of 12 cubic yards. Additional major equipment utilized at the mine include a 992 front-end-loader, haul trucks, scraper, dozers, motor grader, water trucks, drills and other rubber tired loaders. The Pust Seam is the only reserve area. The Pust Seam is classified as a lignite coal with an average heating value of 6,371 Btu/lb and 0.45 percent sulfur as received. It ranges in thickness from 15 to 25 feet, averaging around 20 feet and usually occurs as a single seam; however, a seam parting with a thickness of 1 to 6 feet does occur. Where present, the parting occurs in the lower part of the seam, dividing the lignite into two distinct benches.
The Savage Mine is a surface (open pit) coal mine located in Richland County, Montana. The mine is approximately 32 miles north of Glendive and 20 miles south of Sidney. The mine is accessed from Montana Highway 16 via County Road 107. Acreage contained within the current life-of-mine plan amounts to approximately 874 acres. All 874 permitted acres of surface leased fall under private ownership, with the Company having 562 acres of private coal leases and the remaining 311 acres are held under federal coal leases which expire from 2013 to 2017. The mine was opened in 1958 and the coal from this operation supplies the fuel requirements for the Lewis and Clark Generating Station and a Holly Sugar Corporation sugar beet processing plant, both located in Sidney.
As of December 31, 2001, Savage’s estimated total coal reserves in owned or leased property were approximately 20,493,000 tons. The Company believes these reserves are recoverable through existing facilities with current technology and existing infrastructure. These reserves were estimated to be 21,486,000 tons as of January 1, 1999, based principally upon a report prepared by Weir International Mining Consultants, an independent consulting firm. Presently, the mine produces approximately 300,000 tons of coal per year.
Of the 874 permitted acres, 455 acres have been disturbed by mining. Reclamation has been completed on 196 acres, with the balance involved in active mining operations. The reclamation bond, which is posted by the Company and is an estimate of the total cost to reclaim the mine, is $2,946,000. After all reclamation has been completed, the Company is responsible for maintaining and monitoring the reclaimed property until the bond is released, which is a minimum of 10 years after the final seeding has occurred. The cost of maintaining and monitoring the property prior to bond release has been estimated at $217,000 and is included in the reclamation bond estimate.
Of the total reserves shown in the above table in the column captioned “Savage Mine”, approximately 5.0 million tons are fully permitted at this time. Based on the current estimated production rate of 300,000 tons, there are roughly 15 years remaining under the current permitted mine plan. The permit application process is subject to the regulations of the OSM and the State of Montana under its OSM approved program which is regulated by the Montana Department of Environmental Quality. Among the requirements are detailed pre-mining inventories of environmental resources including soils, vegetation, wildlife, hydrology and archaeology. The application must include detailed plans for mining, reclamation and protection of the hydrological resources. The process includes an exhaustive review of the application for compliance with all applicable regulations. After initial review of the application, the regulatory authority issues a letter outlining deficiencies in the application to which the applicant responds by revising the application where appropriate. This process of identifying and responding to deficiencies is repeated until all matters are addressed. The decision document and environmental assessment are subject to formal public review, including public hearing if requested. This process can take anywhere from one to three years from the time the initial application is filed. Based upon the Company’s current knowledge of the permitting process and the environmental issues which were associated with the permitted reserves, the Company believes that there are no matters that would hinder its ability to obtain any mining permits in the future.
Refer to Note 3 of Notes to Consolidated Financial Statements for a description of WEI properties.
On December 23, 1996 (“Petition Date”), Westmoreland Coal Company and four subsidiaries, Westmoreland Resources, Inc., Westmoreland Coal Sales Company, Westmoreland Energy, Inc., and Westmoreland Terminal Company (the “Debtor Corporations”), filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Colorado (the “Chapter 11 Cases”). On July 27, 1998, they filed a joint motion to be dismissed from bankruptcy. By order of the Bankruptcy Court entered on December 23, 1998, the Chapter 11 Cases were dismissed. No objections were filed during the ten-day stay period that expired on January 4, 1999. Effective with the dismissal, the Debtor Corporations are no longer subject to the protections afforded or restrictions imposed by the Bankruptcy Code. Prior to the dismissal, the Debtor Corporations were in possession of their respective properties and assets and were operating as debtors in possession pursuant to provisions of the Bankruptcy Code. Refer to Note 1 to the Consolidated Financial Statements for additional information concerning the bankruptcy proceedings.
Westmoreland Coal Company – The Company has commenced arbitration proceedings with the UMWA 1974 (Retirement) Plan regarding the Company’s withdrawal liability. Refer to Item 7 – Management’s Discussion and Analysis and Note 8 to the Consolidated Financial Statements for further information.
Westmoreland Resources, Inc. – On July 1, 1999, WRI restructured the terms of its coal sales agreement with Xcel Energy. The new agreement increased the tonnage of coal that Xcel Energy is required to purchase and that WRI is required to deliver and eliminates an option agreement that Xcel had to purchase additional tonnage. The new agreement expires on December 31, 2002. WRI anticipates that an extension or a new agreement will be negotiated before the end of 2002. Under the old agreement, WRI had entered into an option agreement whereby it had agreed to sell up to an additional 200,000,000 tons of coal to Xcel Energy. As compensation for granting the option, WRI received 1 1/4 cents, payable quarterly (with applicable price adjustments) for each optioned ton. The option was never exercised. In 1999, WRI recorded income of $1,593,000 relative to this option agreement. On May 23, 2001, the Minerals Management Service (“MMS”) of the Department of Interior, responsible for insuring payment of royalties on minerals, including coal produced from Federal or Native American lands, issued a letter demanding payment of an additional $1,900,000 in royalty for the period of from 1986 through 1999. MMS asserts that the Xcel option payments were payments for current coal and therefore royalties should have been paid on these amounts. WRI disagrees with MMS and has appealed the MMS determination. Refer to Item 7 – Management’s Discussion and Analysis.
On March 7, 2000, WRI filed suit in the U.S. District Court for Montana against its mining contractor, Washington Group, asserting that WGI had failed to pay for repairs to WRI’s dragline, as required by the 1978 letter agreement in which WRI permitted Washington Group to use the dragline. However, in May 2001, before the dragline litigation could be concluded, Washington Group filed a bankruptcy petition with the federal bankruptcy court in Reno, Nevada. Initiating the bankruptcy proceeding automatically stayed the dragline litigation. On February 15, 2002, the bankruptcy court lifted the automatic stay and remanded the dragline litigation to the U.S. District Court in Montana. WRI will press for a scheduling order and prompt trial to resolve this litigation. The Company expects that WRI’s claim against Washington Group with respect to the dragline will be tried in mid-2002.
On or about September 4, 2001, WRI asserted claims in the bankruptcy proceeding against Washington Group for failure to pay for repairs to the dragline, overcharges on mining costs, the MMS royalty underpayment issue and adequate assurances that Washington Group will perform its contractual reclamation obligations. WRI has objected to Washington Group’s assumption of the mining contract between WGI and WRI, and Washington Group has reserved the right to reject all pending agreements with WRI. These claims were not affected when the bankruptcy court allowed WRI’s claim related to repair of the dragline to proceed in Montana. WRI’s claims against Washington Group (other than the claim related to repair of the dragline, which is expected to be resolved in the Montana federal court described above) and WRI’s objection to Washington Group’s assumption of the mining contract will be tried as “adversary proceedings” in the WGI bankruptcy. Washington Group will not be required to assume or reject the contracts until all adversary proceedings are resolved. Resolution of these issues is not expected before August 2002 at the earliest.
It is impossible to predict the outcome of the litigation against Washington Group. Refer to Item 7 – Management’s Discussion and Analysis for further information.
Basin Resources, Inc. – Basin was an operating company and currently has no assets. The previous owner operated the Golden Eagle mine near Trinidad, Colorado and it ceased operations in 1998. Basin’s workforce had been represented by the UMWA. In 1993, Basin signed a Basin-specific labor contract with the UMWA which expired on August 1, 1998. A group of former employees filed an action in the U.S. District Court in 1998 claiming they were entitled to lifetime health benefits. Basin contended that when the contract expired it was not obligated to continue to provide health benefits. Both Basin and the former employees moved for the District Court to award summary judgment. The Court awarded the former employees’ summary judgment and ordered Basin to reinstate its former health plan and to pay medical costs incurred up to that date. The estimated obligation of $4,000,000 was accrued by the Company as of December 31, 2001. Basin has appealed the District Court’s decision to the U.S. Court of Appeals for the Tenth Circuit.
Western Energy Company - WECO has received two preliminary demand letters from the Montana Department of Revenue (“DOR”), as agent for the MMS, asserting underpayment of certain royalties. DOR contends that royalty payments are due on the fees WECO receives to transport coal from the contract delivery point to the customer. DOR has claimed that approximately $3.2 million is due in respect of this claim. Secondly, DOR has alleged that royalties are also due for certain “take or pay” payments WECO received when its customers did not require coal. DOR has alleged that approximately $1.8 million is due in respect of this claim. Great Northern Properties (“GNP”), one of WECO’s lessors, has also notified WECO that it also has claims for potential underpayment of royalties. GNP has alleged it is due royalties for the transportation fees WECO receives to transport coal from the point of delivery to the customer. WECO has not received a final assessment letter and demand for payment by DOR. If WECO receives a payment demand from DOR, it can appeal the assessment. The appeal process will take several years. WECO and GNP have selected a three-person arbitration panel and are engaged in a preliminary exchange of information. The arbitration process will take several months to conclude.
Purchase Price Adjustment – Pursuant to the terms of the Stock Purchase Agreement dated as of September 15, 2001 (the “Stock Purchase Agreement”) between Entech, a subsidiary of Montana Power, and WCC, 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. Pursuant to the terms of the Stock Purchase Agreement the seller had 60 days after the transaction closed to provide Westmoreland a certificate setting forth the seller’s calculation of the net assets of the entities that the Company was acquiring and the net revenues of those entities through the closing date. Westmoreland then had 30 days to agree or object to the seller’s certificate. Entech and Montana Power submitted a certificate that would have increased the purchase price by approximately $9 million. The Company submitted its own adjustments which would result in a substantial decrease in the original purchase price and objected to Entech’s and Montana Power’s certificate. Under the Stock Purchase Agreement, the parties had 15 days from the submission of the Company’s certificate and objection to the seller’s certificate to resolve their differences. If they could not reach agreement within that period, the Stock Purchase Agreement requires that their disagreements shall be submitted to an independent accountant for resolution. The parties have not been able to agree on either the amount of the purchase price adjustment or the methodology to calculate the adjustment, and Entech refused to refer the matter to the independent accountant. Consequently, on November 26, 2001, Westmoreland initiated an action in the Supreme Court of New York seeking specific performance of the purchase price adjustment methodology in the Stock Purchase Agreement. The Supreme Court of New York agreed with Westmoreland and ordered Entech and Montana Power to comply with the purchase price adjustment methodology in the Stock Purchase Agreement. Entech appealed the Court’s decision and was seeking to enjoin the use of the independent accountant until its appeal was heard. A temporary stay was granted pending a hearing before the full Appellate Division of the Supreme Court of New York. On March 19, 2002, the Appellate Division denied Entech’s request to continue the stay pending completion of Entech’s appeal and dissolved the temporary stay. The Company will press to have the independent accountant appointed and the purchase price adjustment determined. Although there can be no assurance as to the ultimate outcome, the Company denies Entech’s claims, believes its own claims are meritorious, and intends to pursue its rights vigorously. See Item 7 – Management’s Discussion and Analysis for further information.
Northwestern Resources Co. - Under the terms of the LSA with Reliant, lignite prices are set until June 30, 2002. From July 1, 2002, through July 20, 2015 lignite prices will be the lesser of (1) a redetermined price set to be competitive with Powder River Basin coal supplies (subject to an established minimum), or (2) the price that would have otherwise been paid under the LSA. In 1998, when the amended LSA was executed, LEGS consisted of two 800MW generating units. Thereafter, Reliant decided to increase the generating capacity of these units from 800MW per unit to 890MW per unit and to make other modifications, such as construction of a rail that would facilitate use of coal from the Powder River Basin (“PRB”). Disputes subsequently arose regarding post-July 2002 tonnages, pricing, the potential impacts of Texas NOx regulations and Reliant’s increase in the generating capacity of LEGS. In light of differences of opinion between the parties regarding various contract provisions, NWR filed an action seeking a declaratory judgment in Freestone County, Texas on December 11, 2001. The action asks the Court to assist in resolving the parties’ differences regarding construction of the LSA. Discussions are continuing. Refer to Item 7 – Management’s Discussion and Analysis for further information.
There are other pending legal issues at the various Westmoreland subsidiaries which are not material or out of the ordinary course of business.
This item is not applicable.
The following table shows the executive officers of the Company, their ages as of March 1, 2002, 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 | |
| (1) Christopher K. Seglem | 55 | Chairman of the Board | 1996 | |
| President and | 1992 | |||
| Chief Executive Officer | 1993 | |||
| (2) Robert J. Jaeger | 53 | Senior Vice President of Finance and Development | 1996 2001 |
|
| (3) W. Michael Lepchitz | 48 | Vice President and General Counsel | 2000 | |
| and Secretary | 2001 | |||
| (4) Thomas G. Durham | 53 | Vice President Coal Operations | 2000 | |
| (5) Todd A. Myers | 38 | Vice President Sales and Marketing | 2000 | |
| (6) Gregory S. Woods | 48 | Vice President Eastern Operations | 2000 | |
| (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. Jaeger held various financial positions at Penn Virginia Corporation from 1976 and was Vice President and Chief Financial Officer when he left in March 1995. He joined Westmoreland Energy, Inc. in April 1995 as Vice President-Finance. He was elected Vice President Finance, Treasurer and Controller of Westmoreland in September 1995. He was elected Senior Vice President-Finance, Treasurer and Controller in February 1996 and relinquished the position of Controller in January 1998 and the position of Treasurer in July 2001. He became Senior Vice President, Development in October 2001. |
| (3) | Mr. Lepchitz joined Westmoreland in 1991 as Assistant General Counsel. He was named General Counsel of Westmoreland Energy, Inc. in 1995 and became President of WEI 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 Virginia State Bar. |
| (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. He became a registered professional engineer in 1976. |
| (5) | Mr. Myers re-joined Westmoreland in January 2000 as 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 an energy consulting firm, specializing in coal markets, independent power development, and environmental regulation. |
| (6) | Mr. Woods joined Westmoreland in May 1973 and held various corporate accounting and management information systems' positions while at Westmoreland's Virginia and West Virginia coal mining operations. Mr. Woods has been with Westmoreland Energy, Inc. since 1990 and has held the positions of Controller, Asset Manager, and Vice President - Finance and Asset Management. Mr. Woods was elected to his current position as Executive Vice President of Westmoreland Energy, Inc. in 1996 and as Vice President - Eastern Operations of Westmoreland Coal Company in June 2000. |
The following table shows for the past two years 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”).
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 | |
| 2000 | ||||
| First Quarter | $ 4.06 | $ 2.75 | $ 16.00 | $ 14.88 |
| Second Quarter | 3.88 | 2.63 | 18.00 | 14.50 |
| Third Quarter | 5.50 | 2.88 | 22.00 | 15.13 |
| Fourth Quarter | 9.25 | 4.75 | 20.75 | 17.00 |
| 2001 | ||||
| First Quarter | 16.50 | 8.25 | 33.00 | 20.50 |
| Second Quarter | 20.85 | 13.35 | 38.50 | 29.00 |
| Third Quarter | 17.75 | 10.80 | 34.85 | 28.00 |
| Fourth Quarter | 17.05 | 12.61 | 34.99 | 29.00 |
| Number of Holders of Record | |
| Title of Class | (as of March 1, 2002) |
| Common Stock ($2.50 par value) | 1,582 |
| Depositary Shares, each representing a | |
| one-quarter share of Series A | |
| Convertible Exchangeable Preferred | |
| Stock | 26 |
Preferred stock dividends at a rate of 8.5% per annum were paid quarterly from the third quarter of 1992 through the first quarter of 1994. The declaration and payment of preferred stock dividends was suspended in the second quarter of 1994 in connection with extension agreements with the Company’s principal lenders. Upon the expiration of these extension agreements, the Company paid a quarterly dividend on April 1, 1995 and July 1, 1995. Pursuant to the requirements of Delaware law, described below, the preferred stock dividend was suspended in the third quarter of 1995 as a result of recognition of losses and the subsequent shareholders’ deficit. The quarterly dividends which are accumulated but unpaid through and including January 1, 2002 amount to $12,862,000 in the aggregate ($61.63 per preferred share or $15.41 per depositary share). Common stock dividends may not be declared until the preferred stock dividends that are accumulated but unpaid are made current.
On March 10, 1999, the Company offered to purchase up to 1,052,631 depositary shares, each representing one quarter of a share of its Series A Convertible Exchangeable Preferred Stock (“Series A Preferred Stock”). The offer price of $19 per share was in full satisfaction of claims to accumulated but unpaid dividends on the depositary shares tendered. On April 7, 1999, the offer expired and 1,683,903 depositary shares were tendered in response to the offer. Because the number of shares tendered exceeded the maximum number of shares the Company had offered to purchase, a proration factor of approximately 62.5% was applied to all shares tendered. A total of 1,052,631 depositary shares were purchased for $20,000,000. The balance sheet effect of this transaction was to reduce cash and shareholders’ equity by $20,000,000. Following completion of the tender offer, the depositary shares purchased in the offer were converted into shares of Series A Preferred Stock, the shares of Series A Preferred Stock were retired, and the capital of the Company was reduced by the par value of the shares of Series A Preferred Stock retired. This reduced the number of shares of Series A Preferred Stock outstanding from 575,000 to 311,843, accumulated but unpaid dividends from $21,994,000 to $11,928,000, and the ongoing quarterly preferred dividend requirement from $1,222,000 to $663,000.
On September 16, 1999, the Company made a second offer to purchase up to an additional 631,000 depositary shares at $19 per depositary share. The offer price of $19 per share was in full satisfaction of claims to accumulated but unpaid dividends on the depositary shares tendered. On October 26, 1999, the offer expired and 412,536 depositary shares were tendered in response to the offer. The Company purchased a total of 412,536 depositary shares for $7,838,000. The balance sheet effect of the transaction was to reduce cash and shareholders’ equity by $7,838,000. Following completion of the tender offer, the depositary shares purchased in the offer were converted to shares of Series A Preferred Stock, the shares of Series A Preferred Stock were retired, and the capital of the Company was reduced by the par value of the shares of Series A Preferred Stock retired. This reduced the number of shares of Series A Preferred Stock outstanding from 311,843 to 208,708, accumulated but unpaid dividends from $13,253,000 to $8,870,000 and the ongoing quarterly dividend requirement from $663,000 to $444,000.
There are statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which the Company is incorporated. Under Delaware law, the Company is permitted to pay preferred stock dividends only: (1) out of surplus, surplus being the amount of shareholders’ equity in excess of the par value of the Company’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 $208,708 at December 31, 2001). The Company had shareholders’ equity at December 31, 2001 of $10,415,000 and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $18,996,000 at December 31, 2001.
The Board of Directors continues to review the subject of reinstating the preferred stock dividend and satisfying the accumulated unpaid dividends on the preferred stock. Based upon the acquisitions consummated by the Company during the second quarter and the anticipation of positive earnings, the Company’s Board expects to review again, in the next six months, the possibility of reinstating the preferred stock dividend and the issue of the accumulated unpaid dividends. The Company continues to be committed to meeting its obligations to the preferred shareholders in a manner consistent with the best interests of all shareholders.
| 2001(1) | 2000 | 1999 | 1998(2) | 1997(2) | ||||||
| Consolidated Statement of | ||||||||||
| Operations Information | ||||||||||
| Revenue – Coal | $ | 231,048 | $ | 35,137 | $ | 38,539 | $ | 44,010 | $ | 47,182 |
| – Independent Power and other | 13,949 | 30,460 | 33,028 | 64,559 | 18,650 | |||||
| Total revenues | 244,997 | 65,597 | 71,567 | 108,569 | 65,832 | |||||
| Cost and expenses | 233,582 | 61,511 | 63,605 | 78,250 | 66,383 | |||||
| Pension expense (benefit) | (211) | (585) | (149) | 111 | (5,547) | |||||
| Unusual charges (credits) | - | - | - | 2,000 | (27,214) | |||||
| Doubtful accounts recoveries | (446) | (400) | (174) | (1,028) | (1,410) | |||||
| Impairment charges | - | 4,632 | - | 12,164 | - | |||||
| Loss (gains) on the sales of assets | 440 | 6 | (433) | (475) | (969) | |||||
| Operating income | 11,632 | 433 | 8,718 | 17,547 | 34,589 | |||||
| Interest expense | (8,418) | (911) | (1,135) | (190) | (320) | |||||
| Minority interest | (780) | (518) | (854) | (775) | (1,092) | |||||
| Interest and other income | 3,229 | 867 | 1,826 | 1,999 | 713 | |||||
| Income (loss) before reorganization | ||||||||||
| items and income taxes | 5,663 | (129) | 8,555 | 18,581 | 33,890 | |||||
| Reorganization legal and consulting fees |
- | - | - | (9,872) | (2,484) | |||||
| Reorganization interest income | ||||||||||
| (expense), net | - | - | - | (1,594) | 1,552 | |||||
| Income tax benefit (expense) | (436) | 437 | 82 | (3,787) | - | |||||
| Income from continuing operations | 5,227 | 308 | 8,637 | 3,328 | 32,958 | |||||
| Loss from discontinued operations | - | - | - | - | (4,802) | |||||
| Cumulative effect of changes in | ||||||||||
| accounting principles | - | - | - | (9,876) | - | |||||
| Net income (loss) | 5,227 | 308 | 8,637 | (6,548) | 28,156 | |||||
| Less preferred stock dividend | ||||||||||
| requirements | 1,776 | 1,776 | 2,992 | 4,888 | 4,888 | |||||
| Net income (loss) applicable to | ||||||||||
| common shareholders | 3,451 | (1,468) | 5,645 | (11,436) | 23,268 | |||||
| Net income (loss) per share applicable | ||||||||||
| to common shareholders: | ||||||||||
| Basic | $ | 0.48 | $ | (0.21) | $ | 0.80 | $ | (1.64) | $ | 3.34 |
| Diluted | 0.43 | (0.21) | 0.79 | (1.64) | 3.34 | |||||
| Weighted average number of common | ||||||||||
| and common equivalent shares: | ||||||||||
| Basic | 7,239 | 7,070 | 7,040 | 6,965 | 6,965 | |||||
| Diluted | 8,000 | 7,070 | 7,146 | 6,965 | 6,965 | |||||
| Balance Sheet Information | ||||||||||
| Working capital (deficit) | $ | 11,346 | $ | (1,557) | $ | 8,886 | $ | 15,054 | $ | 38,512 |
| Net property, plant and equipment | 197,271 | 34,693 | 36,558 | 36,950 | 35,687 | |||||
| Total assets | 466,532 | 139,096 | 142,297 | 215,606 | 181,997 | |||||
| Total debt | 122,910 | - | 1,563 | 1,762 | 458 | |||||
| Liabilities subject to compromise | - | - | - | - | 132,667 | |||||
| Shareholders’ equity | 10,415 | 3,373 | 3,057 | 21,845 | 28,393 | |||||
| (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. |
| (2) | On December 23, 1996 Westmoreland Resources, Inc., Westmoreland Coal Sales Company, Westmoreland Energy, Inc., and Westmoreland Terminal Company (the “Debtor Corporations”), filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Colorado. The Debtor Corporations were in possession of their respective properties and assets and operated as debtors in possession pursuant to provisions of the Bankruptcy Code. The cases were dismissed on December 23, 1998. Refer to Note 1 to the Consolidated Financial Statements for further information. |
Certain statements in this report which are not historical facts or information are “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, including, but not limited to, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations. Any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. 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; healthcare 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 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, reopeners and extensions; the Company’s ability to maintain satisfactory labor relations; changes in the industry; competition; the Company’s ability to utilize its 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, the announced liquidity issues for Washington Group and other factors discussed in this Item 7 and in Items 1 and 3 above. 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.
The acquisitions completed in the second quarter of 2001 have significantly affected the Company’s financial and operating results for the year ended December 31, 2001. The operations of WML, since the effective date of the acquisitions, have contributed the following:
| Year Ended | |
| December 31, 2001 | |
| (in thousands) | |
| Coal Revenues | $ 187,021 |
| Operating Income | 25,722(a) |
| Cash provided by operating activities | 34,799(a) |
| Increased selling and administrative costs | 11,559 |
| (a) | Does not include $1,500,000 in management fees paid by WML to WCC. |
These results may not necessarily be indicative of the results to be realized in future periods.
As described in Note 2 to the Consolidated Financial Statements, the acquisitions also affected the Company’s balance sheet at acquisition by:
| • | Adding $120,000,000 of acquisition debt, $12,298,000 of revolving debt for working capital and $3,963,000 of assumed debt |
| • | Adding property, plant and equipment of $166,387,000 |
| • | Adding accrued reclamation costs of $135,844,000 partially offset by currently invested cash collateral of $46,827,000 |
| • | Providing the basis for recognizing a deferred tax asset of $55,600,000 |
The above amounts are included in the consolidated financial statements. Also included as of December 31, 2001 is $624,000 of cash and $8,371,000 of restricted cash held by WML, which along with its cash from continuing operations, is dedicated to debt service and funding of the debt service reserve required by the term loan and revolving credit agreements. Until the debt service reserve account is fully funded, WML may not distribute any earnings to the Company; however, for quarters ended on or before December 31, 2001, WML was permitted to distribute up to $1,250,000 per quarter to the Company. This $1,250,000 distribution was in addition to the $500,000 management fee that WML may pay the Company each quarter. The Company expects that the debt service reserve account will be fully funded in March 2002.
While the acquisitions are generating significant positive operating cash flows, the term notes and revolving credit facility agreements include certain conditions with respect to the use of such cash flows which will affect the amount of cash flows available for general use by the Company, particularly in the first year following the acquisitions as discussed in Note 4 to the Consolidated Financial Statements.
The final purchase price for the acquisition of Montana Power’s coal business is subject to adjustment. As discussed in Item 3 – Legal Proceedings, the Company and Montana Power have not been able to agree on either the amount of the purchase price adjustment or the methodology to calculate the adjustment. The Company initiated action in the Supreme Court of New York, seeking specific performance of the purchase price methodology. Any change in the purchase price will result in a change to the preliminary purchase price allocation. If the purchase price is reduced, amounts received are required to repay the acquisition debt. In the unlikely event an additional purchase price payment is required to be made by the Company, it would likely be funded by the use of WML’s revolving credit facility. Although there can be no assurance as to the ultimate outcome, the Company believes its claims are meritorious and intends to pursue its rights vigorously.
The future income expected to be generated by the acquisitions will allow the Company to use at least a portion of its tax net operating loss carryforwards. As a result and as required by generally accepted accounting principles, the Company recognized a $55,600,000 deferred tax asset on the acquisition date. As taxable income is generated in future periods and the net operating loss carryforwards are utilized, the tax asset will be reduced and a non-cash deferred income tax expense will be recognized and no regular Federal income taxes will be paid. Under purchase accounting for the acquisitions, recognition of the deferred tax asset reduced the Company’s basis in the property, plant and equipment acquired, thus reducing future depreciation and depletion expense. This accounting treatment has no effect on cash flows, which will reflect the full benefit to the Company of using its tax loss carryforwards.
The Company describes in this filing many important issues affecting it. In order to facilitate understanding of the Company’s operations, results and future performance certain critical accounting policies and contractual obligations and commitments are presented in the following two sections.
The Company’s significant accounting policies are described in the Consolidated Financial Statements. It is increasingly important to understand that the application of generally accepted accounting principles involve certain assumptions, judgments and estimates that affect reported amounts of assets, liabilities, revenues and expenses. Thus, the application of these principles can result in varying results from company to company.
The most significant principles that impact the Company and its subsidiaries relate to post retirement benefits and pension obligations, reclamation costs and reserve estimates, consolidation policy, depletion of mineral rights and development costs included in property, plant and equipment and deferred income taxes. The following discussion highlights those impacts.
The most significant long-term obligations of the Company are post retirement medical and life insurance benefits and pneumoconiosis (black lung) benefits. The majority of these benefits are provided through self-funded programs. The Company describes these obligations as heritage health benefit costs and the estimated amount of future payments for such obligations are determined actuarially. The discount rate used to calculate the present value of these future benefits was reduced from 7.50% in 2000 to 7.25% in 2001 and will be adjusted annually based upon interest rate fluctuations. The discount rate used can vary from company to company. In addition, the estimated amount of future claims is affected by the assumed health care cost trend rate. During 2001, the Company increased the initial cost trend rate assumption to 10% from 5.5%. These factors, among others, greatly affected the annual expense which totaled $23.8 million in 2001 compared to $21.5 million in 2000 and the recorded liability of $111 million at December 31, 2001 for post retirement medical and life insurance costs. The pneumoconiosis obligation has an excess of funds held in trust over the obligation of $7.0 million.
The Company’s share of reclamation costs, along with other costs related to mine closure, are accrued and charged against income on a units-of-production basis over the life of the mine, except at WRI where only monitoring costs are fixed and are being expensed over a 15-year period. Future costs of reclamation are estimated based upon the standards for mine reclamation that have been established by various regulatory agencies that regulate the Company’s mining operations. Estimated costs can change and the liability included in the financial statements of $139 million as of December 31, 2001 must be viewed as an estimate which is subject to revision. The remaining coal reserves used to calculate annual reclamation expense are also engineering estimates and are subject to change.
The Company’s consolidation policy is described in the Consolidated Financial Statements. In particular, the general and limited interests in partnerships owned by WEI related to independent power projects are accounted for under the equity method, as disclosed in Note 3. WEI performs project development and venture and asset management services for the partnerships but does not control them. The ROVA projects had approximately $250 million in long-term debt as of December 31, 2001, all of which was non-recourse to WEI and Westmoreland and is not included in the Consolidated Financial Statements of the Company in accordance with generally accepted accounting principles.
The Company depletes its mineral acquisition, development costs and some plant and equipment using the units of production method based upon estimated recoverable proven and probable reserves. These estimates are reviewed on a regular basis and are adjusted to reflect current mining plans. As a result, changes in estimates of recoverable proven and probable reserves could change amounts recorded in the future for amortization of development costs.
The Company accounts for deferred income taxes using the asset and liability method. One of the largest potential assets of the Company is the Federal net operating loss carryforwards which were approximately $181 million as of December 31, 2001. Utilization of these losses to reduce future income taxes until they all expire in the year 2019 is dependent upon many factors which determine taxable income. These factors include the timing of tax deductions for certain obligations, such as postretirement medical benefits and reclamation; percentage depletion of coal production; and any potential limitation on using losses due to a “change of ownership” in the Company. Each period, the Company assesses and estimates future utilization of the tax losses and its impact on the recognition of deferred tax assets. As a result of the recent acquisitions, the Company recognized a $55.6 million deferred income tax asset on the acquisition date which assumed that a portion of the previously unrecognized net operating loss carryforwards will be utilized through the generation of future taxable income. Any increases or decreases to this asset affect deferred income tax expense and can materially affect net earnings resulting in an effective book income tax rate different than the 34% Federal statutory rate.
The following table presents contractual obligations (or estimates) and commitments of the Company as of December 31, 2001, which are discussed elsewhere in this filing.
| Payments Due by Period (in thousands of dollars) |
||||||
| Contractual Obligations and Commitments |
Total | 2002 | 2003 | 2004 | 2005 | After |
| WML Revolving debt | 8,000 | 8,000 | ||||
| WML Term debt | 109,000 | 12,700 | 7,800 | 10,300 | 10,300 | 67,900 |
| WCC Revolving debt | 3,000 | 3,000 | ||||
| WEI Letter of credit | 400(1) | |||||
| Other debt | 2,910 | 1,053 | 1,052 | 169 | 169 | 467 |
| Operating leases | 6,152 | 3,515 | 1,118 | 899 | 620 | |
| Heritage Health Benefit/ Pension: | ||||||
| Undiscounted obligations: | ||||||
| Workers’ compensation | 13,041 | 2,900 | 2,750 | 2,500 | 2,250 | 2,641 |
| 1974 UMWA pension | 9,409 | 1,374 | 1,467 | 1,575 | 1,692 | 3,301 |
| Discounted obligations: | ||||||
| Combined Benefit Fund (Multiemployer) |
38,711(2) | 5,058 | 4,672 | 4,573 | 4,344 | 20,064 |
| Postretirement medical | 205,564(3) | 13,966 | 15,188 | 14,958 | 15,666 | 145,786 |
| Qualified pension benefits | 33,544(4) | 300 | 350 | 400 | 460 | 32,034 |
| SERP benefits | 1,503(5) | 76 | 76 | 76 | 76 | 1,199 |
| Pneumoconiosis | 22,987(6) | 4,100 | 3,700 | 3,400 | 3,100 | 8,687 |
| Reclamation costs | 235,321(7) | 7,500 | 7,725 | 7,950 | 8,200 | 203,946 |
| Preferred dividends | 12,862(8) | 1,776(9) | 1,776(9) | 1,776(9) | 1,776(9) | 1,776(9) per year |
| (1) | Expires December 28, 2002 and is collateralized by a $400,000 cash deposit held by the issuing bank. |
| (2) | The present value of the estimated obligation is not accrued as a liability since it is a multiemployer plan. Premium payments are expensed when due. |
| (3) | Gross benefit obligation is shown in the table. The accrued liability, net of the unrecognized net actuarial loss and the unrecognized net transition obligation, was $111,093,000 as of December 31, 2001. |
| (4) | Fair value of plan assets at December 31, 2001 was $33,593,000. Future payments will be made from plan assets. |
| (5) | Gross benefit obligation is shown in the table. The accrued liability, net of the unrecognized net actuarial gain and the unrecognized prior service cost, was $1,752,000 as of December 31, 2001. The plan was unfunded at December 31, 2001. |
| (6) | Fair value of plan assets at December 31, 2001 totaled $29,972,000. Future payments will be made from plan assets. |
| (7) | Gross estimated cost of final reclamation is shown in table. The accrued liability of $139,348,000 as of December 31, 2001 will increase as acres are disturbed in mining operations and will increase to the gross estimated cost of final reclamation. The accrued liability does not include contractual obligations of customers and a contract miner to perform reclamation currently estimated at $73,700,000. In addition, escrowed investments totaled $47,924,000 as of December 31, 2001 for reclamation at WECO’s Rosebud Mine. |
| (8) | Represents quarterly dividends which are accumulated but unpaid through and including January 1, 2002. |
| (9) | 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 therefor.” In general, dividends that are not paid cumulate, as provided in the Certificate of Designation. |
Westmoreland acquired several existing coal supply agreements when it purchased the coal businesses of Montana Power. WECO supplies coal to the four Colstrip Units under two distinct contracts. The contract for Units 1 and 2 calls for the price to be reopened on the contract’s thirtieth anniversary, which was July 2001, and gives the parties six months to negotiate a new delivered price for coal. If the parties are unable to agree on a new price, the issue is submitted to binding arbitration. WECO and the owners of Units 1 and 2 have been negotiating since July 2001 in an attempt to reach an agreement for the price of coal through 2009. The deadline provided in the contract for arbitration has been extended; however, it is possible that the parties will not agree on the price of delivered coal and the issue will be arbitrated. While WECO believes it is due a price increase, as with any arbitration, the outcome is uncertain.
WECO also supplies coal pursuant to a long-term Coal Supply Agreement (“CSA”) to owners of the Colstrip 3 and 4 electric generating units. The CSA allows for the full recovery of WECO’s costs, plus a return on investment and profit. Pursuant to the provisions of the CSA, an annual operating plan (“AOP”) must be approved by the Units 3 and 4 owners. If the parties are in disagreement over any component of the AOP, the CSA provides avenues for dispute resolution over the components in dispute prior to arbitration.
NWR, as part of a settlement of pending litigation entered into the LSA in 1998 with Reliant. The LSA preserved the existing cost-plus contract structure through June 30, 2002, when the price shifts to a market-based price derived by comparison to the value of Powder River Basin (“PRB”) spot coal delivered to LEGS. The price must be between a minimum and a maximum as determined in the LSA. The contract provides for NWR to make its annual tonnage commitments one year in advance and six months before the price is determined. LEGS is obligated to take NWR’s committed tonnage. NWR has nominated tonnages it will deliver to LEGS through December 31, 2003; however, the price for the nominated tonnage will not be set until July 1, 2002. NWR always has the right to supply nominated volumes as well as any additional fuel required by LEGS as long as it meets the price equivalent to the value of PRB coal at LEGS. In the event that NWR elects not to match the equivalent PRB value on all or any portion of the LEGS fuel requirement, Reliant may purchase PRB coal.
NWR has begun discussions with Reliant to resolve pricing for the eighteen-month supply of lignite it has nominated through December 31, 2003. It is expected that NWR will make similar tonnage nominations until the contract expires in 2015. In addition, NWR and Reliant are discussing impacts of changes to LEGS and construction of a rail unloader. To protect its contract rights and, if necessary, obtain guidance on interpreting the LSA in the changed circumstances, NWR has filed a declaratory judgment action in Freestone County, Texas. The litigation has only recently been filed and it is too early to predict any likelihood of success. If the cost of delivering PRB coal became such that NWR determined that producing lignite was uneconomic, Reliant would be obligated to begin performance of final reclamation activities. Refer to Item 3 – Legal Proceedings for further information.
In addition to the contract issues discussed above, the Company is involved with various other legal proceedings, described in Item 3 – Legal Proceedings, which may affect the Company’s liquidity.
Westmoreland’s businesses use large equipment, including mining and power generation equipment and conveyor systems used for the transportation of coal. While every effort is made to maintain this equipment, there is always a risk that unexpected equipment breakdowns can interrupt either the production of coal or generation of electricity.
Unexpected equipment failure at electric generating units, called forced outages, if significant, may adversely impact Westmoreland. These forced outages could cause fluctuations in delivery of coal or distributions from Westmoreland’s independent power plants. For example, the Colstrip Unit 3 was shut down in January and February 2002 for unexpected repairs which will reduce coal sales from the Rosebud Mine during the first quarter.
Westmoreland’s business is subject to some seasonality. Weather has the potential to impact Westmoreland’s business. Coal is supplied to electric generation units and if winter is unseasonably warm or summer is unseasonably cool, the customer’s need for coal may be less than expected. The mild winter of 2001/2002 has decreased the demand for electrical generation and is lowering the Company’s coal sales.
Washington Group is contractually obligated to perform mining and reclamation at the Absaloka Mine. WGI filed a petition seeking protection in the U.S. Bankruptcy Court in Reno, Nevada. WRI has filed several claims as discussed elsewhere in this report and objected to WGI’s assumption of current mining contracts. If WGI elected to reject the mining contracts, as permitted by the bankruptcy code, WRI would be prepared to operate the mine and supply coal to its customers, and would have a claim against WGI.
Changes in various mining, coal-fired generating plant and other environmental regulations have the potential to impact Westmoreland. These include President Bush’s Clean Skies Initiative and Global Climate Initiative, the Kyoto Protocols, and the Texas NOx regulations.
The Company is dependent on certain contracts and customers. The Company derives substantially all of its revenues from a relatively small number of coal supply contracts.
The Company may have difficulty managing existing and future growth. The Company has rapidly and significantly expanded its operations during 2001, and will pursue further opportunities to expand and diversify its revenue base. These expansions may place a significant strain on the Company’s management, operations, and financial resources and may require additions to the Company’s current personnel, systems, procedures, and controls.
The loss of key senior management personnel could negatively affect the Company’s business. The Company depends 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. The Company does not have “key person” life insurance policies. The unexpected loss of any of the Company’s executive officers or other key employees could harm its business.
The Company’s cash and cash equivalents were $5,233,000 million at December 31, 2001. Cash provided by operating activities was $28,435,000 in 2001 and $2,160,000 in 2000. Cash used in operating activities was $22,281,000 in 1999. The increase in cash from operations in 2001 compared to 2000 is due to the operating performance and changes in net assets related to the acquisitions completed in the second quarter of 2001. Also, cash flows in 2000 were positively impacted by the settlement of the ROVA forced outage litigation. The change in cash provided by operations in 2000 compared to 1999 is mainly due to the receipt in 2000 of one-time cash distributions from the overfunded pneumoconiosis trust and workers’ compensation bond compared to the additional payment of cumulative pre-petition liabilities, one-time reorganization costs and alternative minimum income taxes offset by the proceeds received on the sale of Rensselaer in 1999.
Cash used in investing activities was $151,325,000 in 2001, $4,434,000 in 2000 and $12,699,000 in 1999. The primary use of cash in 2001 was $162,700,000 paid for Montana Power and Knife River Corporation acquisitions. Cash provided by investing activities in 2001 includes $15,954,000 in proceeds from the sale of the Company’s interests in the three Virginia independent power projects. During the year, WML deposited $8,340,000 into a required restricted cash account to pay the next six months principal and interest requirements due under WML’s term loan agreement. Cash used in investing activities also included the recoupment of collateral required for long-term security deposits and bond obligations of $9,368,000 in 2001 associated with a change in bonding agents. In addition to the Montana Power and Knife River acquisitions, additions to the Company’s property, plant and equipment totaled $5,433,000 in 2001 and consisted principally of mine development costs at WECO. Cash used in investing activities in 2000 included funding of collateral for security deposits of $4,321,000 and fixed asset additions of $647,000 (including $621,000 at WRI) offset by a partial reimbursement from WRI’s mine operator of $530,000. Cash used in investing activities in 1999 included funding collateral required for security deposits and bond obligations of $11,356,000 and fixed asset additions of $2,069,000 (including $2,599,000 at WRI) offset by proceeds from sales of assets of $726,000.
Cash provided by financing activities for 2001 totaled $113,930,000. Cash provided in 2001 represented proceeds from the issuance of long-term and revolving debt, net of $5,396,000 debt issuance costs, and cash from the exercise of stock options less $1,479,000 for repayment of long-term debt and dividends paid to WRI’s minority shareholder. Cash used in financing activities in 2000 totaled $3,655,000 and was primarily for repayment of WRI’s long-term debt as well as the payments of dividends to minority shareholders of WRI. Cash used of $28,971,000 in 1999 was primarily for the purchase of preferred stock and the payments of dividends to minority shareholders of WRI.
Consolidated cash and cash equivalents at December 31, 2001 totaled $5,233,000 (including $624,000 at WML and $3,449,000 at WRI). At December 31, 2000, cash and cash equivalents totaled $14,193,000 (including $2,406,000 at WRI.) The cash at WRI, an 80%-owned subsidiary, is available to the Company through dividends. In addition, the Company had restricted cash, security deposits and bond collateral which were not classified as cash or cash equivalents, of $18,423,000 at December 31, 2001 and $19,217,000 at December 31, 2000. The restricted cash at December 31, 2001 includes $8,371,000 in the WML debt service reserve account described above and $6,000,000 deposited to collateralize the Company’s obligations required by the Master Agreement dated as of January 4, 1999 (the “Master Agreement”) among WCC, WRI, WEI, 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 UMWA, and the Official Committee of Equity Security Holders, which facilitated the dismissal of WCC’s bankruptcy case. The Company’s workers’ compensation bond was collateralized by interest bearing cash deposits of $4,052,000, which amount was classified as a non-current asset. In addition, the Company has reclamation deposits of $47,924,000, which were funded by certain customers to be used for payment of reclamation activities at the Rosebud Mine. The Company also has $4,600,000 in interest-bearing debt reserve accounts for certain of the Company’s independent power projects. This cash is restricted as to its use and is classified as part of the investment in independent power projects. Security deposits and bond collateral at December 31, 2000 represents interest-bearing cash deposit accounts; $6,000,000 which collateralizes the Company’s Contingent Note required by the Master Agreement, $9,368,000 of collateral for the surety bond required by the 1992 UMWA Benefit Plan, and $3,849,000 that collateralizes the outstanding surety bonds for workers’ compensation self-insurance programs. At the end of 2000, there was $8,000,000 in debt reserve accounts for certain of the Company’s independent power projects.
Preferred stock dividends at a rate of 8.5% per annum were paid quarterly from the third quarter of 1992 through the first quarter of 1994. The declaration and payment of preferred stock dividends was suspended in the second quarter of 1994 in connection with extension agreements with the Company’s principal lenders. Upon the expiration of these extension agreements, the Company paid a quarterly dividend on April 1, 1995 and July 1, 1995. Pursuant to the requirements of Delaware law, described below, the preferred stock dividend was suspended in the third quarter of 1995 as a result of recognition of losses and the subsequent shareholders’ deficit. The Company conducted two tender offers for its Preferred Stock in 1999; the Company’s purchases of preferred stock from preferred stockholders in 1999 pursuant to these two offers reduced shareholders’ equity by $27,800,000. The quarterly dividends which are accumulated but unpaid through and including January 1, 2002 amount to $12,862,000 in the aggregate ($61.63 per preferred share or $15.41 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 the Company is incorporated. Under Delaware law, the Company 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 the Company’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 $208,708 at December 31, 2001). The Company had shareholders’ equity at December 31, 2001 of $10,415,000 and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $18,996,000 at December 31, 2001.
The Board of Directors continues to review the subject of reinstating the preferred stock dividend and satisfying the accumulated unpaid dividends on the preferred stock. Based upon the acquisitions consummated by the Company during the second quarter and the anticipation of positive earnings, the Company’s Board expects to review again, in the next six months, the possibility of reinstating the preferred stock dividend and the issue of the accumulated unpaid dividends. The Company continues to be committed to meeting its obligations to the preferred shareholders in a manner consistent with the best interests of all shareholders.
The major factors impacting the Company’s liquidity outlook are its significant “heritage health benefit costs”, its debt repayment requirements, and its ongoing and future business needs. The Company’s principal sources of cash flow are dividends from WRI, distributions from independent power projects and distributions from WML which are limited by its debt agreement provisions.
While the Company was able to meet its retiree health benefit and other obligations with operating cash flows and proceeds from the sales of non-strategic assets during the course of its restructuring, it sought a long-term solution to improve its financial position. Following the dismissal of its bankruptcy case in December 1998, the Company undertook an extensive review and analysis of its strategic plan for growth. The result was a development plan focused on expanding the Company’s existing core operations and acquiring profitable businesses in the energy sector where America’s dual goals of low cost power and a clean environment could be effectively addressed. The Company has sought to do this in niche markets that will minimize exposure to competition, maximize stability of long-term cash flows and provide opportunities for synergistic operation of existing assets and new opportunities in the energy sector. A key to the Company’s strategy of acquiring profitable businesses is the availability of approximately $200 million in net operating loss carryforwards (“NOL’s”) at the beginning of 2000. The availability of these NOL’s can shield the Company’s future taxable income from payment of regular Federal income tax and thereby increase the return the Company receives from profitable investments (as compared to the return a tax-paying entity would receive that cannot shield its income from federal income taxation).
As discussed below, substantial steps towards implementation of the Company’s strategic plan for growth have now been completed:
| • | The Company completed its acquisition of Montana Power’s coal business on April 30, 2001. These operations produced approximately 18.5 million tons of coal during the full year ended December 31, 2001. Over 90% of current production is sold under long-term contracts to the owners of mine-mouth power plants located adjacent to the Rosebud Mine in Colstrip, Montana and the Jewett Mine in Jewett, Texas. |
| • | The Company completed its acquisition of Knife River Corporation’s coal operations on May 11, 2001, effective April 30, 2001. These operations produce over three million tons of coal annually, again primarily for mine-mouth or nearby power plants. |
| • | On July 26, 2001, the Company signed a definitive agreement for joint development with MDU Resources Group, Inc. to develop, own and operate a new state-of-the-art 500MW lignite-fired power plant near Gascoyne, North Dakota in connection with Lignite Vision 21 (“LV-21”). Each party has an undivided fifty percent interest in the project. LV-21 is a partnership between the state of North Dakota and the Lignite Energy Council designed to encourage construction of a new baseload power plant in North Dakota and includes up to $10 million in matching funds for development. |
Each of these opportunities is aimed at enabling the Company to expand its operations in order to meet its significant heritage health benefit costs and other ongoing business needs and objectives, resume and sustain dividend payments, pay accumulated unpaid dividends on the Preferred Stock, and increase shareholder value. Given the demand for new power generating capacity, stronger energy pricing, the need for stabilizing fuel and electricity costs, and pressure to reduce harmful emissions into the environment, the Company believes that its strategic plan positions it well for potential further growth, profitability, and improved liquidity.
The Company’s acquisitions described above greatly increase revenues and operating cash flow, and return the Company to profitability, but the cash used and financing arranged to make those acquisitions could create short-term liquidity issues which must be managed. The Company used $39 million of available cash in the second quarter of 2001 to complete the acquisitions, knowing that short-term liquidity would be temporarily reduced due to the requirements of the acquisition financing. The terms of the acquisition financing facility described in Note 4 to the Consolidated Financial Statements restrict distributions to the Company from WML, particularly in the first twelve months after closing while the required debt service reserve account is being fully funded. As a result, the limited distributions available from WML during that period along with remaining cash reserves and the distributions from the Company’s other principal sources of operating cash flow, which include distributions from independent power projects, dividends from WRI, and interest on cash reserves, might not be adequate to cover all of the Company’s heritage health benefit costs and operating expenses during that period due to the timing of distributions or worse than expected performance. Therefore, the Company has continued to take steps to conserve its cash. The Company has also investigated the possible sale of non-strategic assets where favorable values could be achieved. Finally, the Company has sought other sources of interim financing and working capital. During the fourth quarter, the Company obtained additional financing under a $7 million two-year revolving line of credit for general corporate purposes. Management believes that cash flows from operations, along with available borrowings, should be sufficient to pay the Company’s heritage health benefit costs, meet repayment requirements of the debt facilities, and fund ongoing business activities as long as currently anticipated surplus cash distributions from WML are received.
A significant source of liquidity, which the Company expects to receive in the second quarter of 2002, is the release of the $6 million in cash currently collateralizing its obligations to the UMWA Funds. The Company agreed to secure its obligations to the UMWA Funds under the Master Agreement for a period of six years by providing a Contingent Promissory Note (“Note”). The original principal amount of the Note is $12 million with a reduction to $6 million in 2002. The Note terminates in 2005. The Note is payable only in the event the Company does not meet its Coal Act obligations, fails to meet certain ongoing financial tests specified in the Note, or fails to maintain the required balance of $6 million in an escrow account established through 2001 in connection with the Note. The financial tests were met through 2001 and cash flows from the ROVA project exceeded $8 million in 2001, which allows the entire $6 million held in escrow to be returned to the Company.
Other sources of potential additional future liquidity include reimbursement of amounts paid to the 1974 UMWA Pension Plan, WRI’s recovery from Washington Group for dragline repairs and on other claims, and the effect of any future legislation that causes Medicare to cover all or a portion of the cost of prescription drug benefits for the Company’s retirees.
The Company expects that there will be continued upward pressure on corporate insurance and surety bonding rates as a result of insurers’ world-wide loss experiences over the past several years, the terrorist attacks in September and ongoing threats around the world. Absent legislative relief, medical and health care costs may also continue to increase. The Company does not anticipate that its coal and power production will diminish materially as a result of the current economic downturn because the independent power projects in which the Company owns interests and the power plants that purchase coal mined by the Company produce relatively low-cost, baseload power. In addition, the Company is party to long-term contracts, which help insulate the Company from downward price reductions.
The following paragraphs specifically describe the health benefit and retirement obligations of the Company.
The Company’s heritage health benefit costs consist primarily of payments for post-retirement medical and workers’ compensation benefits. The Company also is obligated for employee pension and pneumoconiosis benefits; however, these obligations have a funding surplus at present. The Company currently expects to incur cash costs in excess of $19,000,000 for post-retirement medical benefits in 2002, which costs are expected to continue to increase in the near-term and then decline to zero over the next approximately thirty-five years. As a result of the acquisitions completed in 2001, the Company assumed additional obligations, as of April 30, 2001, for post-retirement medical and life insurance benefits of approximately $12,745,000, which will negatively impact the estimated annual expenditures for benefits. Due to the impact of increasing healthcare cost trends on the actuarial valuations of future obligations the Company’s total estimated liability has increased and the heritage health benefit expense for 2002 may increase approximately 15%. The Company expects to incur cash costs of less than $3,000,000 for workers’ compensation benefits in 2002, and expects that amount to steadily decline to zero over the next approximately nineteen years. There were no workers’ compensation obligations assumed in conjunction with the acquisitions as all operations are fully insured.
One element of heritage health benefit costs is UMWA pensions under the 1974 (Retirement) Plan. Since this plan is a multiemployer plan under ERISA, a contributing company is liable for its share of unfunded vested liabilities upon termination or withdrawal from the Plan. The Company believes the Plan was fully funded in 1998 when the Company terminated its last UMWA employees who were participants in the 1974 Retirement Plan and withdrew from the Plan. However, the Plan claims that the Company withdrew on a date earlier than the date on which the Company terminated its last UMWA employee and that when the Company withdrew the Plan was not fully funded. The Plan has asserted a claim of $13,800,000, which the Company is vigorously contesting through arbitration as provided under ERISA. The Company recognized the $13,800,000 asserted liability in 1998. The arbitration proceeding began June 4, 2001 and evidence regarding determination of the appropriate withdrawal date has been submitted. The Company is awaiting the Arbitrator’s decision on the withdrawal date issue. Determination of the amount of withdrawal liability, if any, was deferred until the withdrawal date was determined. If necessary, a second arbitration proceeding to determine the amount of withdrawal liability will be held. In accordance with the Multiemployer Pension Plan Amendments Act of 1980, the Company has made monthly principal and interest payments to the Plan while it pursues its rights and will continue to make such monthly payments until arbitration is completed. Included in the payments made in 2001 is interest of approximately $791,000 and principal of $1,279,000. At the conclusion of arbitration the Company may be entitled to a refund or it could be required to pay any remaining obligation in installments through 2008.
Under the Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”), the Company is required to provide postretirement medical benefits for UMWA miners by making premium payments into three benefit plans: (i) the UMWA Combined Benefit Fund (the “Combined Fund”), a multiemployer plan which benefits miners who retired before January 1, 1976 or who retired thereafter but whose last employer did not provide benefits pursuant to an operator-specific Individual Employer Plan (“IEP”), (ii) an IEP for miners who retired after January 1, 1976, and (iii) the 1992 UMWA Benefit Plan, a multiemployer plan which benefits (A) miners who were eligible to retire on February 1, 1993, who did retire on or before September 30, 1994 and whose former employers are no longer in business, (B) miners receiving benefits under an IEP whose former employer goes out of business and ceases to maintain the IEP, and (C) new spouses or new dependents of retirees in the Combined Fund who would be eligible for coverage thereunder but for the fact that the Combined Fund was closed to new beneficiaries as of July 20, 1992. The premiums paid by the Company cover its own retirees and its allocated portion of the pool of retired miners whose previous employers have gone out of business.
The Coal Act also authorized the Trustees of the 1992 UMWA Benefit Plan to implement security provisions for the future payment of benefits pursuant to the Coal Act. The Trustees set the level of security for each company at an amount equal to three years’ benefits. The Company secured its obligation to provide retiree health benefits under the 1992 Plan by posting a bond in the amount of $22 million in 1999 which was increased to $23 million in 2000 and decreased to $20 million in 2001. The bond amount and the amount to be secured are to be reviewed and adjusted on an annual basis. The bond was collateralized by U.S. Government-backed securities in the amount of $7,968,000 at March 31, 2001 which amount the Company withdrew during second quarter 2001 in connection with a change of bonding agents. The Company’s previous bonding agent required collateral equal to 40% of the bonded amount. The Company’s bond amount is increasing by approximately $4,000,000 in 2002 and the bonding agent has requested cash collateral be deposited. The Company is currently negotiating financing arrangements for the $4,000,000 increase.
The Combined Fund faces an ongoing solvency crisis because benefit expenses continue to exceed premiums from contributing companies. The Combined Fund sought additional funding relief from Congress in 2000. Under the sponsorship of Senators Byrd and Rockefeller of West Virginia, the House and Senate approved, as a part of the Interior and Related Agencies Appropriations Bill, a transfer of accumulated interest in the Abandoned Mine Land Reclamation Fund (“AML”) to the Combined Fund. In its report, the conference committee noted that this was a short-term solution and urged that the Congressional committees with jurisdiction over the matter work with the concerned parties to insure the long-term solvency of the Combined Fund. The conference committee went on to admonish the parties not to ask for additional funding from AML in the future. This funding was in addition to the annual transfer from the AML Funds and does not prevent the Combined Fund from continuing to operate at a deficit.
Prior to leaving office, President Clinton signed a grant authorizing the grant of $130 million to the UMWA Benefit Funds by the Department of Health and Human Services (“HHS”) to create and implement a prescription drug pilot program, which was premised on managing drug therapy and delivery of health care services to reduce hospitalizations for the elderly. The theory supporting the grant was that the elderly either forget to take prescription medications or because the cost of prescription medications is prohibitive intentionally hoard or ration their medications. The program intended to create a “network” or quasi-buddy system where regular contacts and calls would be made to ask if medication had been taken or meals eaten. In addition to establishing the networking or monitoring system, the grant funds were to also help underwrite the costs of prescription medicines. By alleviating some of the cost concerns, the reminders provided by the network system improve the regularity that prescription medications are taken and improve overall health, thereby reducing hospitalizations. As structured, the HHS grant provides an additional $35 million per year for the Combined Fund’s use specifically directed at affecting prescription drug costs. The pilot program was established in only a few states. Westmoreland is monitoring the program.
The debate over prescription drug costs for the elderly continues to generate a great deal of interest from both political parties, their leaders and in the press around the country. While health care generally remains one of the most discussed matters of public policy, politicians have begun to focus increasingly on the specific concern of meeting the pharmaceutical needs of the Medicare-eligible population. Congress included $40 billion over five years in its FY 2001 budget to fund some form of prescription drug benefit. Several bills were introduced in both the House and Senate during the 106th Congress. However, no prescription drug legislation passed both houses. With mid-term elections this fall, both parties promise some form of prescription drug legislation. On January 28, 2002, President Bush announced his intent to spend $190 billion over the next decade to overhaul Medicare and provide prescription drug benefits for low-income seniors. Of the $190 billion that President Bush wants to spend on Medicare reform, $77 billion is earmarked for prescription drug benefits. Lawmakers from both parties immediately said that the $190 billion was insufficient. It is expected that other versions of a prescription drug benefit will be introduced in this session of Congress and both the amount of spending and population that will benefit will be vigorously debated.
A Medicare prescription drug benefit that covers Medicare-eligible beneficiaries covered by the Coal Act could address one of the Company’s largest costs. Westmoreland currently pays over $19 million per year on retirees’ health care costs and over 50% of that is for prescription drugs. There is no assurance at this time what, if any, proposal will be enacted into law or what effect that it may have on the Company’s obligation.
The Company is monitoring energy deregulation and other industry trends. At both the national and state level, there is an ongoing debate about removing regulatory constraints and allowing competition and market forces to determine the price of electricity. Several states have already passed legislation either permitting immediate wholesale and/or retail competition or providing a mechanism for transitioning to a competitive marketplace. At this time, the promulgation of state legislation is not expected to have any immediate impact on existing long-term power purchase agreements. Several proposed bills, calling for deregulation of the traditional utility monopolies, are pending in the U.S. Congress. When, or if, some form of national deregulation legislation will be enacted cannot be predicted. Impacts of Enron’s collapse and the California energy crisis on the deregulation debate are also uncertain. However, it is likely that deregulation issues will be more critically analyzed and the process is likely to slow down.
In addition to deregulation, current industry trends include increased demand for new generating capacity and addressing problems with existing transmission capacity, the need for stabilizing fuel and electricity costs, and pressure to reduce harmful emissions into the environment. The Company’s experience in developing new generating capacity and its current coal production capability may enable the Company to take advantage of these trends. However, there is no assurance that the Company will be able to successfully capitalize on, or that any profitable opportunities will arise, as a result of these trends.
In previous years, WRI expended approximately $4,100,000 to repair the dragline at WRI. All of these expenditures substantially increased the productive life of the dragline and therefore, were capitalized. The Company believes that, under the terms of WRI’s agreements with Washington Group, Washington Group is responsible for all dragline repairs. WRI expended these amounts to assure continued, uninterrupted production at WRI, and has demanded reimbursement from Washington Group for the full cost of the repair. Washington Group has reimbursed WRI for approximately $530,000 of these costs. On March 7, 2000, WRI commenced litigation against Washington Group in the United States District Court for the District of Montana seeking, among other things, payment by Washington Group of approximately $3.6 million of dragline repair costs paid or expected to be paid by WRI, plus accrued interest. The Company has not recorded any amounts that may be recoverable from Washington Group in its Consolidated Financial Statements. On March 2, 2001, Washington Group announced that it was facing a severe near-term liquidity problem due to a delay in resolving purchase price adjustments in connection with an acquisition and in May 2001, Washington Group sought protection in the bankruptcy court in Reno, Nevada. WRI filed claims against Washington Group to recover the cost of repairing the dragline tub, for overcharges on mining costs, potential royalty underpayment as alleged by the Minerals Management Service in a recent demand letter and seeking adequate assurances that Washington Group will perform its contractual obligations regarding reclamation. In addition, WRI objected to the assumption of existing contract mining agreements between WRI and Washington Group. While Washington Group’s plan of reorganization has been approved, WRI’s issues remain unresolved and pending in the bankruptcy court, except for the tub litigation discussed in Item 3 – Legal Proceedings. It is expected that these issues will be resolved this year; however, the Company cannot currently determine what impact, if any, the reorganization may have on its operations or this litigation.
As discussed in Note 14 to the Consolidated Financial Statements, the Company has certain contract contingencies, which may impact future sales, prices received and cost of operations. These include:
| • | WRI’s dispute with WGI regarding both past and current pricing for contract mining services. |
| • | Replacement or extension of the current coal supply agreement with WRI’s largest customer which expires at the end of 2002 and another customer’s request to explore acceleration of a contract reopener provision from 2003 into 2002. |
| • | Determination of supply and pricing at LEGS, which uses lignite from the Jewett mine. |
| • | A price reopener in July 2002 under WECO’s Coal Supply Agreement with Colstrip units 1 and 2. |
In addition, there are other issues regarding royalty payments, labor negotiations and reclamation obligations, which may affect the Company but their impact is not known at this time.
DTA is being utilized at less than capacity and is incurring operating losses due to the continued softness of the export market for U.S. coal. Alternatives for this facility and steps to lower operating losses are being pursued.
The Company has a 4.49% interest in the Ft. Lupton power project. No distributions have been received from that project since 1999 due to a decision by the major partners or because of debt covenants. Steps are being taken to determine whether the distributions from that project can resume.
The availability of the Company’s net operating loss carryforwards, (“NOLs”), which the Company hopes to fully utilize through its growth strategy, is governed by Section 382 of the Internal Revenue Code of 1986 (“Code”). The Code limits the utilization of a corporation’s NOLs if an “ownership change” within the meaning of the Code (an “Ownership Change”) occurs with respect to that corporation. In general, an Ownership Change occurs if, among other things, “5-Percent shareholders” within the meaning of the Code (“5-Percent Shareholders”) increase their percentage ownership of the corporation’s stock by more than 50 percentage points over any three-year period. A 5-Percent Shareholder is any person who owns 5 percent or more of the value of the corporation’s stock, and the value of the corporation’s stock is the sum of the market values of all of the corporation’s outstanding shares. The Company continues to monitor the ongoing status of ownership changes by 5-Percent Shareholders and cautions its current shareholders and potential investors that the creation of new 5-Percent Shareholders or trading by existing 5-Percent Shareholders could negatively impact the calculation of the Ownership Change. The Company believes that, based on public information currently on file, there has not been an Ownership Change, but that the percentage of change is approximately 38% as of December 31, 2001. If the percentage of change begins to approach the 50% limitation, then the Company may ask existing and potential shareholders for their assistance in minimizing the change. If the change exceeds the 50% limitation, the Company may be unable to use a portion of its NOLs.
In light of the impact on the Company of post-retirement health benefit costs under the Coal Act, constraints upon the payment of dividends imposed by Delaware law and the restrictive covenants of the Master Agreement, management concluded that the execution of a growth strategy was vital to the Company’s continued ability to operate, pay accumulated dividends on the Preferred Stock, resume and sustain dividend payments in the future, and create value for shareholders.
Following the dismissal of its bankruptcy case, the Company undertook an extensive review, analysis and development of its strategic plan for growth as discussed above. Among the issues the Company considered in the course of its strategic planning were:
| • | The market for energy in the United States, including forecasts under various economic assumptions about levels of demand for different sources of power, forecasts about levels of supply for different sources of power, and forecasts as to cost and price data. |
| • | The continuing impact of de-regulation on the energy market. |
| • | The continuing impact of laws and regulations designed to protect the environment on the supply of and demand for power produced from different sources, and the opportunities that presently exist and that may arise to balance the country’s desire for affordable energy and a clean environment. |
| • | The business opportunities that existed and that the Company believed would arise in the energy sector. |
| • | The availability of approximately $200 million (at the beginning of 2001) of net operating loss carryforwards (“NOLs”), to shield the Company’s future profits from federal income taxation and thereby increase the return the Company receives from profitable investments (as compared with the return a tax paying entity that cannot shield its income from federal income tax would receive). |
| • | Alternatives to optimize the value of the Company’s existing assets, including sales of assets, if the price is favorable to the Company, recognizing that the Company’s asset base delivers tax-shielded cash flow to the Company and are burdened by the Coal Act, both of which tend to make such assets more valuable to the Company than to potential tax-paying buyers. |
| • | Potential sources of additional cash that might become available to the Company, including the possible reimbursement of the Company’s expenditures to repair the dragline at WRI and the other potential sources described in the “Liquidity Outlook” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
| • | The financial effect of possible legislative developments, such as a prescription drug program, that could substantially reduce the Company’s obligations under the Coal Act since over 50% of the Company’s post-retirement medical costs are for retiree prescription drug benefits. |
| • | The importance of properly prioritizing and sequencing the Company’s efforts, and maximizing use of available cash to meet all strategic business objectives, including the tax-advantaged expansion of the Company through acquisitions, and the ability to pay accumulated and future stock dividends. |
The Company’s strategic plan adopted focuses on expanding the Company’s existing core operations and acquiring profitable businesses in the energy sector where America’s dual goals of low cost power and a clean environment can be effectively addressed. The Company seeks to do this in niche markets that will minimize exposure to competition, maximize stability of long-term cash flows and provide opportunities for synergistic operation of existing assets and new opportunities in the energy sector.
Coal Operations. The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods:
| Year Ended | |||||
| 2001(a) | 2000 | Change | |||
| Revenues – thousands | $ | 231,048 | $ | 35,137 | 558% |
| Volumes – millions of equivalent coal tons | 20.503 | 4.910 | 318% | ||
| Cost of sales – thousands | $ | 177,304 | $ | 30,250 | 486% |
| (a) | Includes only eight months of operations from acquisitions discussed in Note 2 to the Consolidated Financial Statements. |
The dramatic increase of mining coal revenues to $231,048,000 in 2001 from $35,137,000 in 2000 is the result of adding eight months revenues from the acquisitions as well as approximately 1.0 million more tons from the Company’s existing mine. Of the 20.5 million equivalent tons sold during 2001, over 99% was sold under long-term contracts, primarily to owners of power plants located adjacent to the mines. Equivalent tons sold include petroleum coke sales which are expected to continue through June 2002 at which time the Reliant plant at the Jewett Mine will not commit to continued purchases. The newly acquired mines average a higher price per ton and better margins than the Absaloka Mine, which continued its operations. As a result, costs as a percentage of revenues decreased to 77% in 2001 compared to 86% in 2000.
Depreciation, depletion and amortization increased to $9,165,000 in 2001 compared to $1,972,000 in 2000 as a result of the acquisitions and the large increase in capital assets.
Independent Power. Equity in earnings from the independent power projects was $15,871,000 in 2001 compared to $32,260,000 in 2000. The decrease in 2001 reflects the loss of earnings associated with the sale of the Virginia projects in March 2001, and an increased realization of $8 million in December 2000 as a result of settlement of past underpayments at ROVA. The decrease in 2001 was partially offset by improved results from ROVA in 2001 due in part to the restructured power purchase agreement which also came out of the litigation settlement. During 2001 and 2000, the ROVA projects produced 1,817,000 and 1,800,000 megawatt hours, respectively, and achieved average capacity factors of 90% and 89%, respectively.
Terminal Operations. The Company’s share of losses from DTA was $1,922,000 in 2001 compared to $1,800,000 in 2000. DTA is dependent upon its customers’ coal export business to maintain an acceptable level of throughput. The continued loss is due to a continued weakness in the export market. The coal export business has experienced a significant decline due to intense competitive pressure from coal suppliers in other nations. The Company does not believe that those competitive pressures will abate in the near term.
Costs and Expenses. Selling and administrative expenses were $23,340,000 for 2001 compared to $7,786,000 for 2000. The increase includes $11,499,000 incurred during eight months by the Company’s four mines acquired in 2001. The increase is also due to $2,668,000 of non-cash compensation expense in 2001 for the 2000 management long-term performance units compared to $824,000 expense in fiscal year 2000 and due to $507,000 non-cash expense for the 2001 management long-term performance units which are tied to performance of the Company’s stock, the price of which increased dramatically during 2001. Other increases in 2001 are due to annual salary increases, bonuses and the addition of employees and related relocation expenses associated with the Company’s growth. Fiscal 2001 benefited from a reduction of approximately $500,000 in the estimated liability for reclamation at the Bullitt Refuse Area.
During 2001, the Company recorded a $123,000 loss on the sale of WEI’s remaining interest in the Ft. Drum independent power project and a $317,000 loss related to the sale of WEI’s interests in the three Virginia independent power projects. The recognition of the Virginia loss, as well as an impairment charge recognized in the fourth quarter of 2000, was necessary because the service lives originally adopted for depreciation purposes for these projects were greater than the cash flow streams provided under the existing term of the power supply agreements for the facilities. The proceeds from the sale of the Virginia projects totaling $24,903,000, including $8,949,000 from operating earnings distributed by the projects at the time of the sale, were used to fund a portion of the acquisitions completed during the second quarter of 2001.
Heritage health benefit costs increased to $23,773,000 in 2001 compared to $21,503,000 in 2000 primarily as a result of increased costs for postretirement medical plans and payments to the Combined Benefit Fund. In addition, a lower pneumoconiosis benefit was recognized in 2001 than in 2000.
Interest expense was $8,418,000 and $911,000 for 2001 and 2000, respectively. The increase was mainly due to the acquisition financing. Interest income increased during 2001 despite declining rates due to the larger deposit accounts acquired in the acquisitions.
As a result of the recent acquisitions, the Company recognized a $55.6 million deferred income tax asset which assumes that at least a portion of previously unrecognized net operating loss carryforwards will be utilized because of the projected generation of future taxable income. The asset increased to $57,061,000 as of December 31, 2001 and is comprised of both a current and long-term portion. When taxable income is generated, the deferred tax asset relating to the Company’s net operating loss carryforwards is reduced and a deferred tax expense (non-cash) is recognized although no regular Federal income taxes are paid. Income tax expense for 2001 represents a current income tax obligation for State income taxes, the utilization of a portion of the Company’s net operating loss carryforwards and the impact of changes in deferred tax assets and liabilities. The Federal Alternative Minimum Tax regulations were recently changed to allow 100% utilization of net operating loss carryforwards in 2001 and 2002 thereby eliminating the Company’s current Federal income tax expense. In 2001, an income tax benefit to the Company of $989,000 resulting from stock option exercises was added to other paid-in capital. The income tax benefit of $437,000 in 2000 was primarily the result of percentage depletion.
Other Comprehensive Loss. The other comprehensive loss of $1,703,000 (net of income taxes of $1,135,000) recognized in 2001 represents the unrealized loss on an interest rate swap agreement on the ROVA debt caused by decreases in market interest rates during the period. If market interest rates continue to decrease prior to repayment of the debt, additional comprehensive losses will be recognized. Conversely, increases in market interest rates would result in comprehensive gains.
Coal Operations. The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods:
| Year Ended | |||||
| 2000 | 1999 | Change | |||
| Revenues – thousands | $ | 35,137 | $ | 38,539 | (9)% |
| Volumes – millions of tons | 4.910 | 5.466 | (10)% | ||
| Cost of sales – thousands | $ | 30,250 | $ | 33,637 | (10)% |
The reduction in revenues in 2000 was due to a decrease in tons sold in 2000 compared to 1999 that resulted from the expiration of the Company’s contract with Otter Tail Power supplied by the Absaloka Mine. In 1999, the Company shipped 1,496,000 tons to Otter Tail. Partially offsetting the decrease in shipments to Otter Tail Power, the Company’s remaining customers purchased approximately 940,000 more tons in 2000 than in 1999. Prices received were comparable in the two years. Costs as a percentage of revenues decreased to 86% in 2000 from 87% in 1999.
Depreciation, depletion and amortization increased to $1,972,000 in 2000 compared to $1,571,000 in 1999 due to capital expenditures made in recent years.
Independent Power. Equity in earnings of independent power operations in 2000 was $32,260,000 compared to $34,492,000 in 1999. The change is composed of an increase in earnings due to the $14,900,000 settlement of the ROVA litigation offset by the impact of the sale of the Rensselaer project in 1999. In 2000, in anticipation of the sale of the Virginia Projects in 2001, the Company recognized a $4,632,000 impairment charge relating to those investments.
Terminal Operations. Share of losses from DTA was $1,800,000 in 2000 compared to $1,464,000 in 1999. The increase is due to a decrease in throughput as a result of a continued decline in export coal sales from the U.S. DTA is dependent upon its customers’ coal export business to maintain an acceptable level of throughput. The coal export business has experienced a significant decline due to intense competitive pressure from coal suppliers in other nations. At this time the Company does not believe that those competitive pressures will abate in the near term.
Costs and Expenses. Selling and administrative expenses were $7,786,000 compared to $9,660,000 in 1999. During 1999 approximately $2,600,000 was paid to employees for bonuses covering several previous years. In 2000, the Company adopted a long-term performance unit compensation plan tied to increases in the Company’s common stock price which resulted in additional compensation expense of $824,000. The Company also incurred development expenses of $276,000 in 2000. The majority of other selling and administrative expenses decreased in 2000 compared to 1999 due to management’s cost control measures.
Heritage health benefit costs were $21,503,000 in 2000 compared to $18,737,000 in 1999, reflecting increased costs for the postretirement medical plans, as well as an increase in payments made to the Combined Fund.
Loss on dispositions of assets was $6,000 for 2000. Gain on sales of assets was $433,000 for 1999 which related to sales of assets from the idled Virginia Division.
Although not required, the following information provides a basis for comparative evaluation of performance, by segment, between the fourth and third quarters of 2001. This information is being provided in this filing in an effort to help investors follow the Company’s progress until more meaningful comparative information on a year-to-year basis is available.
| Coal | ||||
| Quarter ended | Quarter ended | |||
| 12/31/2001 | 9/30/2001 | |||
| (in thousands) | ||||
| Revenues – coal | $ | 82,883 | $ | 85,957 |
| Costs and expenses: | ||||
| Cost of sales – coal | 66,514 | 63,528 | ||
| Depreciation,depletion | ||||
| and amortization | 2,351 | 3,396 | ||
| Selling and administrative and other | 5,038 | 4,549 | ||
| 73,903 | 71,473 | |||
| Operating income | $ | 8,980 | $ | 14,484 |
Most of the decrease during the fourth quarter in revenues is due to a decrease in tons sold from 7.5 to 6.9 million tons. This was due to planned outages for maintenance at LEGS at the Jewett Mine. Cost of sales increased primarily due to increased overburden removal activities at the Rosebud Mine as stripping ratios increased. This cost trend is not expected to continue as a permit was obtained in December which allowed operations to move to a new area with a more favorable stripping ratio.
| Independent Power | Terminal Operations | |||||||
| Quarter ended | Quarter ended | Quarter ended | Quarter ended | |||||
| 12/31/2001 | 9/30/2001 | 12/31/2001 | 9/30/2001 | |||||
| (in thousands) | (in thousands) | |||||||
| Revenues - | ||||||||
| equity in earnings (share of losses) | $ | 3,136 | $ | 4,470 | $ | (590) | $ | (540) |
| Costs and expenses: | ||||||||
| Depreciation, depletion | ||||||||
| and amortization | 2 | 2 | - | - | ||||
| Selling and administrative | 104 | 70 | 26 | 12 | ||||
| Gain on sale of assets and other |
(352) | - | - | - | ||||
| (246) | 72 | 26 | 12 | |||||
| Operating income (loss) | $ | 3,382 | $ | 4,398 | $ | (616) | $ | (552) |
| Independent Power: | The third quarter benefited from higher utilization compared to the fourth quarter which had a scheduled outage at the ROVA I plant. |
| Terminal Operations: | Terminal operations losses increased due to lower throughput volumes and higher maintenance costs. |
| Corporate | ||||||
| Quarter ended | Quarter ended | |||||
| 12/31/2001 | 9/30/2001 | |||||
| (in thousands) | ||||||
| Revenues | $ | - | $ | - | ||
| Costs and expenses: | ||||||
| Depreciation, depletion and amortization | 7 | 6 | ||||
| Selling and administrative | 1,841 | 1,961 | ||||
| Heritage health benefit costs | 7,086 | 5,269 | ||||
| Pension benefit | (45) | (55) | ||||
| Gain on sale of assets and other | - | (3) | ||||
| 8,889 | 7,178 | |||||
| Operating loss | $ | (8,889) | $ | (7,178) | ||
Selling and administrative costs decreased in the fourth quarter primarily due to lower compensation costs. The decrease was partially offset by a net non-cash expense of $793,000 relating to the continued vesting of additional portions of the 2000 and 2001 management long-term performance units compared to a $4,000 non-cash expense related to these plans recognized during the third quarter.
Heritage health benefit costs increased in the fourth quarter compared to the third quarter primarily as a result of unfavorable actuarial valuation adjustments to the post-retirement liability due to increasing medical costs and pneumoconiosis benefit obligations.
In June 2001, the Financial Accounting Standards Board issued SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets and approved for issuance SFAS No. 143, Accounting for Asset Retirement Allocations. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated or completed after June 30, 2001. SFAS No. 141 also specifies criteria that intangible assets acquired in a purchase method business combination must meet to be recognized and reported apart from goodwill.
SFAS No. 142 requires that goodwill no longer be amortized, but instead tested for impairment at least annually. Any goodwill and any intangible asset determined to have an indefinite useful life that are acquired in a purchase business combination completed after June 30, 2001 will not be amortized, but will be evaluated for impairment in accordance with the appropriate existing accounting literature.
SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset and is effective for fiscal years beginning after June 15, 2002.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which is effective for fiscal years beginning after December 15, 2001. SFAS No. 144 establishes one accounting model to be used for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations to include more disposal transactions.
The adoption of SFAS 141 and SFAS 142 will not have an effect on the Company’s consolidated financial statements. Management is currently assessing the impact, if any, of SFAS 143 and SFAS 144 on the Company’s consolidated financial statements for future periods.
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, WEI, 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 is sold through long-term contracts with customers. These long-term contracts serve to minimize the Company’s exposure to changes in commodity 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, 2001.
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, 2001. Based on the balances outstanding as of December 31, 2001, a one percent change in the prime interest rate or LIBOR would increase interest expense by $200,000 on an annual basis. The Company’s heritage health benefit costs are also impacted by interest rate changes because its pension, pneumoconiosis and post-retirement medical benefit obligations are recorded on a discounted basis.
| Index to Financial Statements | Page |
| Consolidated Balance Sheets | 58 |
| Consolidated Statements of Operations | 60 |
| Consolidated Statements of Shareholders' Equity and Comprehensive Income | 61 |
| Consolidated Statements of Cash Flows | 62 |
| Summary of Significant Accounting Policies | 64 |
| Notes to Consolidated Financial Statements | 69 |
| December 31, | 2001 | 2000 | ||
| (in thousands) | ||||
| Assets | ||||
| Current assets: | ||||
| Cash and cash equivalents | $ | 5,233 | $ | 14,193 |
| Receivables: | ||||
| Trade | 34,381 | 3,105 | ||
| Other | 3,075 | 565 | ||
| 37,456 | 3,670 | |||
| Inventories | 13,748 | - | ||
| Restricted cash | 14,371 | - | ||
| Deferred income taxes | 15,859 | - | ||
| Other current assets | 5,941 | 1,086 | ||
| Total current assets | 92,608 | 18,949 | ||
| Property, plant and equipment: | ||||
| Land and mineral rights | 53,564 | 10,564 | ||
| Plant and equipment | 194,529 | 65,709 | ||
| 248,093 | 76,273 | |||
| Less accumulated depreciation and depletion | 50,822 | 41,580 | ||
| Net property, plant and equipment | 197,271 | 34,693 | ||
| Deferred income taxes | 41,202 | - | ||
| Investment in independent power projects | 28,707 | 49,419 | ||
| Investment in Dominion Terminal Associates (DTA) | 3,975 | 4,327 | ||
| Prepaid pension cost | 4,783 | 4,118 | ||
| Excess of trust assets over pneumoconiosis benefit | ||||
| obligation | 6,985 | 6,807 | ||
| Security deposits and bond collateral | 4,052 | 19,217 | ||
| Advance coal royalties | 6,570 | - | ||
| Reclamation deposits | 47,924 | - | ||
| Reclamation receivables | 10,360 | - | ||
| Other assets | 22,095 | 1,566 | ||
| Total Assets | $ | 466,532 | $ | 139,096 |
See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.
(Continued)
| December 31, | 2001 | 2000 | ||
| (in thousands except share data) |
||||
| Liabilities and Shareholders' Equity | ||||
| Current liabilities: | ||||
| Current installments of long-term debt | $ | 13,753 | $ | - |
| Accounts payable and accrued expenses: | ||||
| Trade | 24,168 | 2,357 | ||
| Income taxes | 57 | - | ||
| Production taxes | 17,544 | 3,170 | ||
| Workers’ compensation | 2,900 | 3,100 | ||
| Postretirement medical costs | 13,966 | 10,500 | ||
| 1974 UMWA Pension Plan obligations | 1,374 | 1,279 | ||
| Reclamation costs | 7,500 | 100 | ||
| Total current liabilities | 81,262 | 20,506 | ||
| Long-term debt, less current installments | 109,157 | - | ||
| Accrual for workers’ compensation, less current portion | 10,141 | 12,236 | ||
| Accrual for postretirement medical costs, less current | ||||
| portion | 97,127 | 82,968 | ||
| 1974 UMWA Pension Plan obligations, less current | ||||
| portion | 8,035 | 9,409 | ||
| Accrual for reclamation costs, less current portion | 132,148 | 2,309 | ||
| Other liabilities | 13,274 | 3,003 | ||
| Minority interest | 4,973 | 5,292 | ||
| Commitments and contingent liabilities | ||||
| Shareholders' equity | ||||
| Preferred stock of $1.00 par value | ||||
| Authorized 5,000,000 shares; | ||||
| Issued and outstanding 208,708 shares | 209 | 209 | ||
| Common stock of $2.50 par value | ||||
| Authorized 20,000,000 shares; | ||||
| Issued and outstanding 7,515,221 shares | ||||
| in 2001 and 7,069,663 shares in 2000 | 18,787 | 17,674 | ||
| Other paid-in capital | 69,723 | 67,318 | ||
| Accumulated other comprehensive loss | (1,703) | - | ||
| Accumulated deficit | (76,601) | (81,828) | ||
| Total shareholders' equity | 10,415 | 3,373 | ||
| Total Liabilities and Shareholders' Equity | $ | 466,532 | $ | 139,096 |
See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.
| Years Ended December 31, | 2001 | 2000 | 1999 | |||
| (in thousands except per share data) | ||||||
| Revenues: | ||||||
| Coal | $ | 231,048 | $ | 35,137 | $ | 38,539 |
| Independent power projects - equity in earnings | 15,871 | 32,260 | 34,492 | |||
| Dominion Terminal Associates (“DTA”) – share of losses |
(1,922) | (1,800) | (1,464) | |||
| 244,997 | 65,597 | 71,567 | ||||
| Cost and expenses: | ||||||
| Cost of sales – coal | 177,304 | 30,250 | 33,637 | |||
| Depreciation, depletion and amortization | 9,165 | 1,972 | 1,571 | |||
| Selling and administrative | 23,340 | 7,786 | 9,660 | |||
| Heritage health benefit costs | 23,773 | 21,503 | 18,737 | |||
| Pension benefit | (211) | (585) | (149) | |||
| Doubtful accounts recoveries | (446) | (400) | (174) | |||
| Impairment charges | - | 4,632 | - | |||
| Losses (gains) on sales of assets | 440 | 6 | (433) | |||
| 233,365 | 65,164 | 62,849 | ||||
| Operating income | 11,632 | 433 | 8,718 | |||
| Other income (expense): | ||||||
| Interest expense | (8,418) | (911) | (1,135) | |||
| Interest income | 2,657 | 1,866 | 2,052 | |||
| Minority interest | (780) | (518) | (854) | |||
| Other income (expense) | 572 | (999) | (226) | |||
| (5,969) | (562) | (163) | ||||
| Income (loss) before income taxes | 5,663 | (129) | 8,555 | |||
| Income tax (expense) benefit | (436) | 437 | 82 | |||
| Net income | 5,227 | 308 | 8,637 | |||
| Less preferred stock dividend requirements | 1,776 | 1,776 | 2,992 | |||
| Net income (loss) applicable to common | ||||||
| shareholders | $ | 3,451 | $ | (1,468) | $ | 5,645 |
| Net income (loss) per share applicable to | ||||||
| common shareholders: | ||||||
| Basic | $ | 0.48 | $ | (0.21) | $ | 0.80 |
| Diluted | $ | 0.43 | $ | (0.21) | $ | 0.79 |
| Weighted average number of common | ||||||
| shares outstanding - basic | 7,239 | 7,070 | 7,040 | |||
| Weighted average number of common | ||||||
| shares outstanding – diluted | 8,000 | 7,070 | 7,146 | |||
See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.
| Class A Convertible Exchangeable Preferred Stock |
Common Stock |
Other Paid-In Capital |
Accumulated Other Comprehensive Loss |
Accumulated Deficit |
Total Shareholders’ Equity |
|||||||
| (in thousands except share data) | ||||||||||||
| Balance at December 31, 1998 | ||||||||||||
| (575,000 preferred shares and 6,965,328 common shares outstanding) |
$ | 575 | $ | 17,413 | $ | 94,630 | $ | - | $ | (90,773) | $ | 21,845 |
| Common stock issued as | ||||||||||||
| compensation (77,334 shares) |
- | 193 | 104 | - | - | 297 | ||||||
| Common stock options | ||||||||||||
| exercised (25,000 shares) | - | 63 | 53 | - | - | 116 | ||||||
| Preferred stock repurchased | ||||||||||||
| and retired (366,292 shares) | (366) | - | (27,472) | - | - | (27,838) | ||||||
| Net income | - | - | - | - | 8,637 | 8,637 | ||||||
| Balance at December 31, 1999 | ||||||||||||
| (208,708 preferred shares and 7,067,663 common shares outstanding) | 209 | 17,669 | 67,315 | - | (82,136) | 3,057 | ||||||
| Common stock options | ||||||||||||
| exercised (2,000 shares) | - | 5 | 3 | - | - | 8 | ||||||
| Net income | - | - | - | - | 308 | 308 | ||||||
| Balance at December 31, 2000 | ||||||||||||
| (208,708 preferred shares 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 tax benefit of $1,135 |
- | - | - | (1,703) | - | (1,703) | ||||||
| Comprehensive income | 3,524 | |||||||||||
| Balance at December 31, 2001 | ||||||||||||
| (208,708 preferred shares and 7,515,221 common shares outstanding) | $ | 209 | $ | 18,787 | $ | 69,723 | $ | (1,703) | $ | (76,601) | $ | 10,415 |
See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.
| Years Ended December 31, | 2001 | 2000 | 1999 | |||
| (in thousands) | ||||||
| Cash flows from operating activities: | ||||||
| Net income | $ | 5,227 | $ | 308 | $ | 8,637 |
| Adjustments to reconcile net income to net cash | ||||||
| provided by (used in) operating activities: | ||||||
| Equity in earnings of independent power projects | (15,871) | (32,260) | (34,492) | |||
| Cash distributions from independent power projects | 18,426 | 23,434 | 51,653 | |||
| Share of losses of DTA | 1,922 | 1,800 | 1,464 | |||
| Cash generated by DTA | 257 | 168 | 942 | |||
| Cash contributions to DTA | (1,827) | (1,623) | (1,603) | |||
| Deferred income tax benefit | (472) | - | - | |||
| Depreciation, depletion and amortization | 9,165 | 1,972 | 1,571 | |||
| Stock compensation expense | 1,050 | - | 297 | |||
| Impairment charges | - | 4,632 | - | |||
| Losses (gains) on sales of assets | 440 | 6 | (433) | |||
| Distributions from pneumoconiosis trust | - | 6,397 | - | |||
| Minority interest | 780 | 518 | 854 | |||
| Other | (154) | 147 | ||||
| Changes in assets and liabilities: | ||||||
| Receivables, net | (5,429) | (893) | 2,519 | |||
| Prepaid pension cost | 391 | (221) | (149) | |||
| Excess of trust assets over pneumoconiosis | ||||||
| benefit obligation | (178) | (1,552) | (761) | |||
| Accounts payable and accrued expenses | 13,049 | (1,700) | (4,337) | |||
| Income taxes payable | 57 | 315 | (2,185) | |||
| Accrual for workers’ compensation | (2,295) | (2,936) | (2,266) | |||
| Accrual for postretirement medical costs | 4,728 | 4,695 | 4,564 | |||
| 1974 UMWA Pension Plan | (1,279) | (1,191) | (1,897) | |||
| Consent judgment payment obligation | - | - | (39,006) | |||
| Other assets and liabilities | 294 | 845 | (300) | |||
| Net cash provided by (used in) operating activities | ||||||
| before reorganization items | 28,435 | 2,560 | (14,781) | |||
| Changes in reorganization items- | ||||||
| Reorganization expenses paid | - | (400) | (7,500) | |||
| Net cash provided by (used in) operating activities | 28,435 | 2,160 | (22,281) | |||
(Continued)
| Years Ended December 31, | 2001 | 2000 | 1999 | |||
| (in thousands) | ||||||
| Cash flows from investing activities: | ||||||
| Additions to property, plant and equipment | (5,433) | (647) | (2,069) | |||
| Cash paid for acquisitions | (162,700) | - | - | |||
| Reimbursement from mine operator | - | 530 | - | |||
| Change in security deposits and bond collateral | 15,165 | (4,321) | (11,356) | |||
| Change in restricted cash | (14,371) | - | - | |||
| Net proceeds from sales of investments and assets | 16,014 | 4 | 726 | |||
| Net cash used in investing activities | (151,325) | (4,434) | (12,699) | |||
| Cash flows from financing activities: | ||||||
| Proceeds from long-term debt, net of debt issuance costs |
114,604 | - | - | |||
| Repayment of long-term debt | (12,053) | (1,563) | (199) | |||
| Net borrowings under revolving lines of credit | 11,000 | - | - | |||
| Dividends paid to minority shareholders of subsidiary | (1,100) | (2,100) | (1,000) | |||
| Exercise of stock options | 1,479 | 8 | 66 | |||
| Repurchase of preferred stock | - | - | (27,838) | |||
| Net cash provided by (used in) financing activities | 113,930 | (3,655) | (28,971) | |||
| Net increase (decrease) in cash and cash equivalents | (8,960) | (5,929) | (63,951) | |||
| Cash and cash equivalents, beginning of year | 14,193 | 20,122 | 84,073 | |||
| Cash and cash equivalents, end of year | $ | 5,233 | $ | 14,193 | $ | 20,122 |
| Supplemental disclosures of cash flow information: | ||||||
| Cash paid during the year for: | ||||||
| Interest | $ | 8,340 | $ | 1,000 | $ | 6,076 |
| Income taxes | 1,209 | 2 | 1,606 | |||
See accompanying Summary of Significant Accounting Policies and Notes to Consolidated Financial Statements.
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 companies where its ownership is between 20% and 50% and for partnerships and joint ventures in which less than a controlling interest is held.
The Company has a 20% interest in Dominion Terminal Associates (“DTA”), a partnership formed for the construction and operation of a coal-storage and vessel-loading facility in Newport News, Virginia. DTA’s annual throughput capacity is 22 million tons, and its ground storage capacity is 1.7 million tons. Each partner is responsible for its share of throughput and expenses at the terminal. The Company actively markets its 20% share of the terminal’s facilities. Accordingly, the Company’s share of losses from DTA represents the revenue received from WTC’s customer’s net of the Company’s share of the expenses incurred attributable to the terminal’s coal-storage and vessel loading operations. The Company currently leases the terminal’s ground storage space and vessel-loading facilities to certain unaffiliated parties who are engaged in the export business and provides related support services.
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 unit 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.
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. As of December 31, 2001 and 2000, $5,432,000 and $0, respectively, were recorded for deferred overburden removal costs and included in other assets.
The Company is self-insured for workers’ compensation claims incurred prior to 1996 and federal and state pneumoconiosis benefits for current and former employees. Workers’ compensation claims incurred after January 1, 1996 are covered by a third party insurance provider.
The liability for workers’ compensation claims is an actuarially determined estimate of the ultimate losses incurred on such claims based on the Company’s experience, and includes a provision for incurred but not reported losses. Adjustments to the probable ultimate liability are made continually 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 are restricted as to use for final reclamation activities. The total reclamation deposits of $47,924,000 at December 31, 2001 consist of $12,021,000 of cash and cash equivalents and $35,903,000 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 $10,360,000 as a long-term receivable, which amount will be collected as certain reclamation activities are performed at the Rosebud and Jewett Mines.
The amortized cost, gross unrealized holding losses and fair value of held-to-maturity securities at December 31, 2001 are as follows (in thousands):
| Amortized cost | $ | 35,903 |
| Gross unrealized holding losses | (515) | |
| Fair Value | $ | 35,388 |
Maturities of held-to-maturity securities are as follows at December 31, 2001 (in thousands):
| Amortized Cost | Fair Value | |||
| Due in five years or less | $ | 34,094 | $ | 33,619 |
| Due after five years to ten years | 1,809 | 1,769 | ||
| $ | 35,903 | $ | 35,388 | |
The Company accounts for health care and life insurance benefits provided to 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. 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.
Minimum standards for mine reclamation have been established by various regulatory agencies and dictate the reclamation requirements at the Company’s operations. Certain reclamation is performed and expensed on an ongoing basis as mining operations are performed. The remaining reclamation costs, along with other costs related to mine closure, are accrued and charged against income on a units-of-production basis over the life of the mine. Costs of future expenditures for reclamation and mine closure are not discounted to their present value.
WRI’s share of reclamation costs are fixed and are being recognized evenly over a 15-year period. Total expected reclamation costs at idled sites were fully accrued at the time of idling. Estimates at idle sites are periodically reviewed and adjustments are made in accruals to provide for changes in expected future costs.
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.
Basic earnings (loss) per share is computed by dividing net income (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share are determined on the same basis except that the weighted average shares outstanding are increased to include additional shares for the assumed exercise of stock options, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options were exercised and that the proceeds from such exercises were used to acquire shares of common stock at the average market price during the reporting period.
The following table provides a reconciliation of the number of shares used to calculate basic and diluted earnings per share (EPS):
| 2001 | 2000 | 1999 | |
| Weighted average number of common stock shares outstanding: | (in thousands of shares) | ||
| Basic | 7,239 | 7,070 | 7,040 |
| Effect of dilutive instruments | 761 | - | 106 |
| Diluted | 8,000 | 7,070 | 7,146 |
| 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. | 113 | - | 1,685 |
In June 2001, the Financial Accounting Standards Board issued SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets and approved for issuance SFAS No. 143, Accounting for Asset Retirement Allocations. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated or completed after June 30, 2001. SFAS No. 141 also specifies criteria that intangible assets acquired in a purchase method business combination must meet to be recognized and reported apart from goodwill.
SFAS No. 142 requires that goodwill no longer be amortized, but instead tested for impairment at least annually. Any goodwill and any intangible asset determined to have an indefinite useful life that are acquired in a purchase business combination completed after June 30, 2001 will not be amortized, but will be evaluated for impairment in accordance with the appropriate existing accounting literature.
SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset and is effective for fiscal years beginning after June 15, 2002.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which is effective for fiscal years beginning after December 15, 2001. SFAS No. 144 establishes one accounting model to be used for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations to include more disposal transactions.
The adoption of SFAS 141 and SFAS 142 will not have an effect on the Company’s consolidated financial statements. Management is currently assessing the impact, if any, of SFAS 143 and SFAS 144 on the Company’s consolidated financial statements for future periods.
Certain prior year amounts have been reclassified to conform to the current year presentation.
The Company’s current principal activities, all conducted within the United States, are: (i) the production and sale of coal from Montana, North Dakota and Texas; (ii) the development, ownership and management of interests in cogeneration and other non-regulated independent power plants; and (iii) the leasing of capacity at Dominion Terminal Associates, a coal storage and vessel loading facility.
Westmoreland Coal Company and four subsidiaries, Westmoreland Resources, Inc. (“WRI”), Westmoreland Coal Sales Company, Westmoreland Energy, Inc., and Westmoreland Terminal Company (“the Debtor Corporations”), filed voluntary petitions for protection under Chapter 11 of the Bankruptcy Code on December 23, 1996. On December 23, 1998, the Bankruptcy Court granted the Debtors’ Motion to Dismiss the cases. The automatic stay period pursuant to the Federal Rules of Bankruptcy Procedure expired on January 4, 1999.
Continued financial improvement of the Debtors during the bankruptcy provided the basis for dismissal and settlement with the UMWA Health and Benefit Funds (“Funds”), the Company’s principal creditors. On October 15, 1998, the Company, the Funds, the United Mine Workers of America (“UMWA”) and the Official Committee of Equity Security Holders (“Equity Committee”) reached agreement on the terms of a settlement, which provided for, among other things, the resolution of the Chapter 11 cases. The agreement, which facilitated a consensual dismissal of the bankruptcy cases, was announced during scheduled hearings on Westmoreland’s Motion to Dismiss and the Equity Committee’s Motion to Convert to Chapter 7, and the hearings were subsequently recessed. The agreement was subsequently documented in certain consent judgments and in a Master Agreement among the Company, the Funds, the UMWA, and the Equity Committee. The Debtor Corporations filed motions requesting approval of the consent judgments on November 18, 1998. There were no allowable objections and dismissal of the Chapter 11 Cases occurred on December 23, 1998. The Master Agreement was executed on January 29, 1999.
On April 30, 2001 and May 11, 2001, respectively, the Company, through its separate wholly owned subsidiary Westmoreland Mining LLC (“WML”), completed the acquisitions of the coal business of The Montana Power Company (“Montana Power”) for approximately $136 million, and the coal operations of Knife River Corporation (a subsidiary of MDU Resources Group, Inc.) 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, through its subsidiaries, 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 Montana Power transaction, WML acquired the stock of Western Energy Company (“WECO”), which owns and operates the Rosebud Mine located in the northern Powder River Basin near the town of Colstrip, Montana, 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. In connection with this acquisition, all of the membership interests in Western Syncoal LLC were transferred to the Company’s subsidiary, Westmoreland Power, Inc. (“WPI”). Western Syncoal LLC was previously a wholly owned subsidiary of Western Energy Company.
The Montana Power transaction is subject to contractual purchase price adjustments. Montana Power submitted adjustments which would result in an increase in the purchase price of approximately $9 million. The Company has submitted its own adjustments which would result in a substantial decrease in the original purchase price. The parties have not been able to agree on either the amount of the purchase price adjustment or the methodology to calculate the adjustment. Consequently, the Company initiated an action in the Supreme Court of New York seeking specific performance of the purchase price adjustment methodology in the Stock Purchase Agreement. The Court agreed with the Company and ordered compliance with the purchase price adjustment methodology in the Stock Purchase Agreement. Montana Power has appealed the Court’s decision. A temporary stay was granted pending a hearing before the full Appellate Division of the Supreme Court of New York. On March 19, 2002, the Appellate Division denied the stay, pending completion of Montana Power’s appeal and dissolved the temporary stay. The Company will press for completion of the purchase price methodology in the Stock Purchase Agreement. Management believes that the outcome will not have a material adverse effect on the Company’s results of operations or liquidity.
In the Knife River transaction, WML’s subsidiary, Dakota Westmoreland Corporation, acquired all of the assets associated with the Beulah Mine in Beulah, North Dakota, and WML’s subsidiary, WCCO-KRC Acquisition Corp., acquired all of the assets associated with the Savage Mine in Savage, Montana. In connection with this transaction, WPI acquired certain rights related to the former Gascoyne mine site in North Dakota. In December 2001, the Company and Knife River Corporation agreed to final purchase price adjustments and in January 2002, the Company received approximately $600,000 from Knife River Corporation.
The acquisitions were funded with $39 million in cash contributed to WML by the Company and borrowings of $125 million ($120 million term debt and $5 million revolving line of credit) by WML as described in Note 4.
The acquisitions were recorded under the purchase method of accounting and, therefore, the purchase prices have been allocated to the assets acquired and liabilities assumed based on estimated fair values at the date of acquisition. These purchase price allocations are subject to further adjustment based on the final purchase price closing adjustments discussed above. The estimated fair values of the assets acquired, the liabilities assumed and the deferred income tax asset recognized to reflect the value of a portion of the net operating loss carryforwards the Company now expects to utilize as a result of future taxable income generated by the acquisitions are summarized below (in thousands):
| Working capital | $ | 21,122 |
| Property, plant and equipment | 166,387 | |
| Deferred income tax asset | 55,600 | |
| Reclamation deposits | 46,827 | |
| Other assets | 31,063 | |
| Long-term debt | (3,963) | |
| Reclamation obligations | (135,844) | |
| Other liabilities | (18,492) | |
| Net assets acquired | $ | 162,700 |
The following unaudited consolidated pro forma financial information is presented for the years ended December 31, 2001 and 2000 in order to provide a basis for comparative evaluation of the consolidated companies’ performance as if the acquisitions had occurred at the beginning of the periods presented. This unaudited pro forma information includes permitted adjustments to give effect to depreciation of property, plant and equipment, interest expense on acquisition-related financing, and certain other adjustments, together with related income tax effects. The unaudited pro forma information is not meant to be nor should it be relied upon as necessarily indicative of the results of operations that actually would have occurred had the acquisitions occurred at the beginning of the periods presented or of future results of the combined operations.
| Year Ended December 31, | ||||
| 2001 | 2000 | |||
| (in thousands except per share data) | ||||
| Revenues | $ | 335,830 | $ | 323,156 |
| Net income applicable to common shareholders | $ | 9,963 | $ | 18,684 |
| Net income per share applicable to common shareholders: | ||||
| Basic | $ | 1.38 | $ | 2.64 |
| Diluted | $ | 1.25 | $ | 2.52 |
On March 23, 2001, the Company sold its 30% interests in three Virginia independent power projects (Altavista, Hopewell and Southampton) for aggregate net proceeds of approximately $24,903,000, including $8,949,000 of operating earnings distributed from the projects at the time of the sale. A net loss of $317,000 was recorded by the Company in conjunction with this sale. The recognition of the loss, as well as an impairment charge recognized in the fourth quarter of 2000, was necessary because the service lives originally adopted for depreciation purposes for these projects were greater than the cash flow streams provided under the power supply agreements for the facilities. During the second quarter of 2001, the Company sold its 1.25% interest in the Ft. Drum independent power project for proceeds of approximately $60,000, resulting in a loss of $123,000. The proceeds from the sales were used to fund a portion of the purchase prices of the acquisitions completed during the second quarter.
On July 27, 1999, the Company sold all remaining book assets of its idled Virginia Division. The assets consisted of the Bullitt Preparation Plant and Transloader Complex. The Company received approximately $650,000 in cash and the purchaser assumed reclamation liabilities of approximately $600,000. The transaction resulted in a net gain of approximately $360,000. The Company is negotiating to sell the Virginia Division refuse site to a local mine operator who will continue its active use. The site has no recorded asset value, but $797,000 has been accrued for its reclamation.
Westmoreland Energy, Inc., (“WEI”), 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, 2001 WEI held interests in three operating projects as listed and described in the Project Summary below. As discussed in Note 2, the Company sold its interests in four independent power projects during 2001. The lenders to the remaining projects have recourse only against these projects and the income and revenues therefrom. The debt agreements contain various restrictive covenants including restrictions on making cash distributions to the partners, with which the partnerships are in compliance. The type of restrictions on making cash distributions to the partners vary from one project lender to another.
| Project | Ft. Lupton | Roanoke Valley I |
Roanoke Valley II |
| Location: | Ft. Lupton, Colorado | Weldon, North Carolina |
Weldon, North Carolina |
| Gross Megawatt Capacity: | 290 MW | 180 MW | 50 MW |
| WEI 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 WEI which are accounted for under the equity method:
| Balance Sheets | ||||
| December 31, | 2001 | 2000 | ||
| (in thousands) | ||||
| Assets | ||||
| Current assets | $ | 40,458 | $ | 124,388 |
| Property, plant and equipment, net | 264,484 | 488,869 | ||
| Other assets | 23,832 | 38,001 | ||
| Total assets | $ | 328,774 | $ | 651,258 |
| Liabilities and equity | ||||
| Current liabilities | $ | 28,213 | $ | 59,027 |
| Long-term debt and other liabilities | 250,075 | 388,295 | ||
| Equity | 50,486 | 203,936 | ||
| Total liabilities and equity | $ | 328,774 | $ | 651,258 |
| WEI’s share of equity | $ | 28,707 | $ | 54,723 |
| Impairment allowance | - | (4,632) | ||
| Other, net | - | (672) | ||
| WEI’s investment in independent power operations | $ | 28,707 | $ | 49,419 |
| Income Statements | ||||||
| For years ended December 31, | 2001 | 2000 | 1999 | |||
| (in thousands) | ||||||
| Revenues | $ | 124,946 | $ | 215,454 | $ | 203,082 |
| Operating income | 72,209 | 94,059 | 111,234 | |||
| Net income | 33,003 | 69,874 | 67,035 | |||
| WEI’s share of earnings | $ | 15,871 | $ | 32,260 | $ | 34,492 |
WEI performs project development and venture and asset management services for the partnerships and has recognized related revenues of $267,000, $294,000 and $365,000 for the years ended December 31, 2001, 2000 and 1999, respectively. Management fees, net of related costs, are recorded as other income when the service is performed.
ROVA I Project - WEI owns a 50% partnership interest in Westmoreland-LG&E Partners (the “ROVA Partnership”). The ROVA Partnership’s principal customer, Dominion Virginia Power, contracted to purchase the electricity generated by ROVA I, one of two units included in the ROVA Partnership, under a long-term contract (the “Power Purchase and Operating Agreement” or “PPOA”). From May 1994 through October 2000, that customer disputed the ROVA Partnership’s interpretation of provisions of the contract dealing with the payment of the capacity purchase price when the facility experiences a “forced outage” day. A forced outage day is a day when ROVA I is not able to generate a specified level of electrical output. The ROVA Partnership believed that the customer was required to pay the ROVA Partnership the full capacity purchase price unless forced outage days exceed a contractually stated allowed annual number. The customer asserted that it was not required to do so.
During that period, Dominion Virginia Power withheld payments during periods of forced outages. In October 2000, the ROVA partnership and Dominion Virginia Power resolved the issues regarding capacity payments during forced outages resulting in a payment to the ROVA partnership for amounts previously withheld plus accrued interest. WEI’s share was $14,900,000. In addition to settlement of the litigation, the ROVA Partnership and Virginia Power negotiated an amendment to the PPOA which clarified the provisions of the contract governing capacity payments and provides incentives for the Partnership to keep the ROVA unit available and on-line.
Virginia Projects - On March 23, 2001, the Company sold its 30% interests in three Virginia independent power projects. WEI’s share of earnings from these projects contributed approximately $1,286,000, $5,287,000, and $6,851,000 in 2001, 2000 and 1999, respectively. Refer to Note 2 – Acquisitions and Dispositions for additional information.
Rensselaer – On March 15, 1999, LG&E-Westmoreland Rensselaer (“LWR”) completed the sale of the Rensselaer Project to Fulton Cogeneration Associates, L.P. (“Fulton”). LWR received approximately $68,000,000 in cash as consideration and recognized a gain of approximately $35,200,000 for the sale of the Rensselaer plant and operating contracts. After payment of expenses and remaining debts, Westmoreland Energy Inc.‘s share of the proceeds was approximately $33,000,000 and it recognized its $17,600,000 portion of the gain in equity in earnings.
The amounts outstanding at December 31, 2001 under the Company’s lines of credit and long-term debt consist of the following (in thousands):
| WML revolving line of credit | $ | 8,000 |
| WML term debt | 109,000 | |
| Corporate revolving line of credit | 3,000 | |
| Other term debt | 2,910 | |
| 122,910 | ||
| Less current portion | (13,753) | |
| $ | 109,157 | |
WML has a $20 million revolving credit facility (the “Facility”) with PNC Bank, National Association, as Agent, which expires on April 27, 2004. The interest rate is either PNC Bank’s Base Rate plus 1.60% or Euro-Rate plus 3.10% (5.03% at December 31, 2001), 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. At December 31, 2001, WML had additional borrowing capacity of approximately $12,000,000 under the Facility.
WML also 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 bear interest at either a prime rate or LIBOR-based rate (5.52% at December 31, 2001) at WML’s option, and require quarterly principal repayments from September 2001 to June 2002, when the remaining outstanding balance is due. The Series B Notes bear interest at a rate of 9.39% and require quarterly principal repayments from September 2002 to December 2008, when the remaining outstanding balance is due. Both the Series A Notes and the Series B Notes require quarterly interest payments and 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, 2001, WML was in compliance with such covenants.
Under the terms of the Series A Notes and 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. WML must fund this account with its operating cash flows, after payment of principal, interest, capital expenditures, and certain other amounts. Based upon projected operating results and cash flows, the Company expects that this debt service reserve account will be fully funded in March 2002. After the debt service reserve account is fully funded, if the debt service coverage ratio, as defined in the agreements, is greater than or equal to 1.25 to 1, then 25% of any “Surplus Cash Flow” (as such term is defined in the agreement for the $120 million term loan) is applied to the prepayment of WML’s 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. Until the debt service reserve account is fully funded, WML may not distribute any earnings to the Company; however, for quarters ended on or before December 31, 2001, WML was permitted to distribute up to $1,250,000 per quarter to the Company. This $1,250,000 distribution was in addition to the $500,000 management fee that WML pays the Company each quarter. At December 31, 2001, WML had funded a balance of $8,371,000 in the debt service reserve account, which could be used for principal and interest payments. Those funds have been classified as restricted cash in the consolidated balance sheet.
WML also assumed outstanding notes payable of the acquired entities totaling $3,963,000 at the acquisition date related to the purchase of real property and mineral rights. These notes generally require annual payments through 2009 and bear interest at approximately 6%. The total amount outstanding under these notes as of December 31, 2001 was $2,910,000.
On December 14, 2001, the Company executed an agreement with First Interstate Bank for a two-year $7 million revolving line of credit. Interest is payable monthly at the Bank’s prime rate plus 1% (5.75% at December 31, 2001). The Company is required to maintain certain financial ratios. The credit 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. As of December 31, 2001, the Company had additional borrowing capacity of $4 million under this credit facility.
The maturities of all long-term debt and the revolving credit facility outstanding at December 31, 2001 are (in thousands):
| 2002 | $ | 13,753 |
| 2003 | 11,852 | |
| 2004 | 18,469 | |
| 2005 | 10,469 | |
| 2006 | 11,470 | |
| Thereafter | 56,897 | |
| $ | 122,910 | |
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, $642,000, $67,000 and $758,000 were charged to operations in 2001, 2000 and 1999, respectively. The cash payments for workers’ compensation benefits were $2,938,000, $3,003,000 and $3,354,000 in 2001, 2000 and 1999, 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, 2001 and 2000, $3,301,000 and $3,849,000, respectively, was held in the collateral accounts.
The Company is self-insured for federal and state pneumoconiosis benefits for current and 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, | 2001 | 2000 | ||
| (in thousands) | ||||
| Actuarial present value of benefit obligation: | ||||
| Expected claims from terminated employees | $ | 4,716 | $ | 5,454 |
| Claimants | 18,271 | 18,458 | ||
| Total present value of benefit obligation | 22,987 | 23,912 | ||
| Plan assets at fair value, primarily government-backed | ||||
| securities | 29,972 | 30,719 | ||
| Excess of trust assets over pneumoconiosis benefit | ||||
| obligation | $ | 6,985 | $ | 6,807 |
The discount rates used in determining the accumulated pneumoconiosis benefit as of December 31, 2001 and 2000 were 7.25% and 7.50%, respectively. Benefits paid from plan assets were $5,339,000 in 2001 and $5,867,000 in 2000.
In February 2000, the Company received $6,397,000 of the surplus from the trust and used the funds to pay postretirement medical expenses.
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 agreement. 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.
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, | 2001 | 2000 | ||
| (in thousands) | ||||
| Assumptions: | ||||
| Discount rate | 7.25% | 7.50% | ||
| Change in benefit obligation: | ||||
| Net benefit obligation at beginning of year | $ | 160,441 | $ | 155,819 |
| Service cost | 227 | 51 | ||
| Interest cost | 12,327 | 11,698 | ||
| Plan participant contributions | 62 | 69 | ||
| Actuarial (gain) loss | 32,459 | 4,528 | ||
| Benefit obligation assumed in acquisitions | 13,038 | - | ||
| Gross benefits paid | (12,990) | (11,724) | ||
| Net benefit obligation at end of year | 205,564 | 160,441 | ||
| Change in plan assets: | ||||
| Employer contributions | 12,928 | 11,655 | ||
| Plan participant contributions | 62 | 69 | ||
| Gross benefits paid | (12,990) | (11,724) | ||
| Fair value of plan assets at end of year | - | - | ||
| Funded status at end of year | (205,564) | (160,441) | ||
| Unrecognized net actuarial loss | 49,369 | 17,771 | ||
| Unrecognized net transition obligation | 45,102 | 49,202 | ||
| Net amount recognized at end of year (recorded as accrued benefit cost in the accompanying balance sheet) |
$ | (111,093) | $ | (93,468) |
The components of net periodic postretirement benefit cost are as follows:
| Year ended December 31, | 2001 | 2000 | 1999 | |||
| (in thousands) | ||||||
| Assumptions: | ||||||
| Discount rate | 7.50% | 7.50% | 7.75% | |||
| Components of net periodic benefit cost: | ||||||
| Service cost | $ | 227 | $ | 51 | $ | 62 |
| Interest cost | 12,327 | 11,698 | 11,334 | |||
| Amortization of: | ||||||
| Transition obligation | 4,100 | 4,100 | 4,100 | |||
| Actuarial loss | 861 | 501 | 261 | |||
| Total net periodic benefit cost | $ | 17,515 | $ | 16,350 | $ | 15,757 |
Of the total net periodic benefit cost of $17,515,000 in 2001, $16,722,000 relates to the Company’s former eastern mining operations and is included in heritage health benefit costs. The remainder of $793,000 relates to current operations and is included in selling and administrative costs.
| Sensitivity of retiree welfare results (in thousands): |
||
| Effect of a one percentage point increase in assumed health care cost trend |
||
| - - on total service and interest cost components | $ | 1,059 |
| - - on postretirement benefit obligation | $ | 21,660 |
| Effect of a one percentage point decrease in | ||
| assumed health care cost trend | ||
| - - on total service and interest cost components | $ | (897) |
| - - on postretirement benefit obligation | $ | (18,363) |
Postretirement benefits include medical benefits for retirees and their spouses (and Medicare Part B reimbursement for certain retirees) and retiree life insurance.
The health care cost trend assumed on covered charges was 10.0%, 5.5% and 6.0% for 2001, 2000 and 1999, respectively, decreasing to an ultimate trend of 5.0% in 2009 and beyond. This increase in the health care cost trend assumption is reflected as an unrecognized actuarial loss in the tables above and will be recognized as expense over the remaining service lives of the covered employees.
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. Prior to February 1993, the amount paid by the Company was based on hours worked or tons processed (depending on the source of the coal) in accordance with the national contract with the UMWA. Beginning February 1993 the Company was required by the Coal Act to make monthly premium payments into the CBF. These payments were 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 $38,711,000 at December 31, 2001. The Company expenses payments to the CBF when they are due. Payments are generally made on the due date.
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 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, 2001 and 2000 and the amounts recognized in the Company’s financial statements for both the defined benefit pension and SERP Plans:
| Qualified Pension Benefits | SERP Benefits | |||||||
| December 31, | 2001 | 2000 | 2001 | 2000 | ||||
| (in thousands) | ||||||||
| Assumptions: | ||||||||
| Discount rate | 7.25% | 7.50% | 7.25% | 7.50% | ||||
| Expected return on plan assets | 9.00% | 9.00% | 9.00% | 9.00% | ||||
| Rate of compensation increase | 4.50% | 5.00% | 4.50% | 5.00% | ||||
| Change in benefit obligation: | ||||||||
| Net benefit obligation at beginning of year | $ | 1,422 | $ | 1,379 | $ | 1,337 | $ | 1,300 |
| Service cost | 1,238 | 140 | 52 | 54 | ||||
| Interest cost | 1,551 | 98 | 105 | 93 | ||||
| Actuarial (gain) loss | 1,686 | (186) | 85 | (66) | ||||
| Benefit obligations assumed in acquisitions | 27,876 | - | - | - | ||||
| Gross benefits paid | (229) | (9) | (76) | (44) | ||||
| Net benefit obligation at end of year | 33,544 | 1,422 | 1,503 | 1,337 | ||||
| Change in plan assets: | ||||||||
| Fair value of plan assets at beginning of year | 5,892 | 5,469 | - | - | ||||
| Actual return on plan assets | (1,265) | 432 | - | - | ||||
| Employer contributions | - | - | 76 | 44 | ||||
| Transfer of assets from plans assumed in acquisitions |
29,195 | - | - | - | ||||
| Gross benefits paid | (229) | (9) | (76) | (44) | ||||
| Fair value of plan assets at end of year | 33,593 | 5,892 | - | - | ||||
| Funded status at end of year | 49 | 4,470 | (1,503) | (1,337) | ||||
| Unrecognized net actuarial (gain) loss | 4,655 | (467) | (478) | (621) | ||||
| Unrecognized prior service cost | 96 | 138 | 229 | 345 | ||||
| Unrecognized net transition asset | (17) | (23) | - | - | ||||
| Net amount recognized at end of year | 4,783 | 4,118 | (1,752) | (1,613) | ||||
| Amounts recognized in the accompanying balance sheet consist of: | ||||||||
| Prepaid benefit cost | 4,783 | 4,118 | - | - | ||||
| Accrued benefit cost (included in other liabilities) | - | - | (1,752) | (1,613) | ||||
| Net amount recognized at end of year | $ | 4,783 | $ | 4,118 | $ | (1,752) | $ | (1,613) |
The components of net periodic pension cost (benefit) are as follows:
| Qualified Pension Benefits | SERP Benefits | |||||||||||
| Year ended December 31, | 2001 | 2000 | 1999 | 2001 | 2000 | 1999 | ||||||
| (in thousands) | ||||||||||||
| Assumptions: | ||||||||||||
| Discount rate | 7.50% | 7.50% | 7.75% | 7.50% | 7.50% | 7.75% | ||||||
| Expected return on plan assets | 9.00% | 9.00% | 9.00% | N/A | N/A | N/A | ||||||
| Rate of compensation increase | 4.50% | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% | ||||||
| Components of net periodic benefit cost | ||||||||||||
| Service cost | $ | 1,238 | $ | 141 | $ | 204 | $ | 52 | $ | 54 | $ | 66 |
| Interest cost | 1,551 | 98 | 105 | 105 | 93 | 99 | ||||||
| Expected return on assets | (2,275) | (492) | (493) | - | - | - | ||||||
| Amortization of: | ||||||||||||
| Transition asset | (6) | (6) | (6) | - | - | - | ||||||
| Prior service cost | 42 | 42 | 42 | 116 | 116 | 116 | ||||||
| Actuarial gain | - | (4) | (1) | (40) | (86) | (45) | ||||||
| Total net periodic pension cost (benefit) | $ | 550 | $ | (221) | $ | (149) | $ | 233 | $ | 177 | $ | 236 |
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 neither controlled nor administered by the Company.
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. In connection with the cessation of mining operations, the Company recorded an estimate of the liability the Company would incur upon withdrawal from the 1974 UMWA Pension plan. The actuarial estimate of this obligation was estimated by the 1974 UMWA Pension Plan at $13,800,000 in 1996. The 1974 UMWA Pension Plan has not provided the Company with an updated actuarial estimate of the withdrawal liability calculated as of June 30, 1998, the date of the asset valuation the Company believes should be used to determine the actual withdrawal liability, in accordance with the provisions of MPPA. The Company believes the liability at June 30, 1998 would be substantially less than $13,800,000 and is contesting the withdrawal liability through arbitration. In accordance with MPAA, the Company must amortize this withdrawal liability, with interest, during the arbitration process by making payments of approximately $172,500 per month. These payments have been made and will be recoverable to the extent the final assessed amount is less than the amounts paid. Should the Company be unsuccessful in the arbitration proceedings, it will be obligated to continue to make payments through March 2008. Of the $13,800,000 recorded in 1996, $9,409,000 remains outstanding as of December 31, 2001.
On January 4, 1999, pursuant to the consent judgments described in Note 1, the Company paid the Combined Benefit Fund and the 1992 Benefit Plan $17,230,000 and $16,518,000, respectively, plus interest of $5,258,000 for a total of $39,006,000. Included in the amount paid to the Combined Benefit Fund was a prepayment of approximately $1,515,000 for the first quarter of 1999. The Master Agreement also required certain other payments to general pre-petition creditors, the reimbursement of bankruptcy related costs incurred by the Funds and an annual installment to the 1974 UMWA Pension Plan. These amounts were $5,686,000 (including interest), $4,000,000, and $1,606,000 (including interest), respectively. The total amount paid on January 4, 1999, for all obligations was $50,298,000.
Income tax expense (benefit) attributable to income (loss) before income taxes consists of:
| 2001 | 2000 | 1999 | ||||||||
| (in thousands) | ||||||||||
| Current: | ||||||||||
| Federal | $ | - | $ | (599) | $ | - | ||||
| State | 908 | 162 | (82) | |||||||
| 908 | (437) | (82) | ||||||||
| Deferred: | ||||||||||
| Federal | (120) | - | - | |||||||
| State | (352) | - | - | |||||||
| (472) | - | - | ||||||||
| Income tax expense (benefit) | $ | 436 | $ | (437) | $ | (82) | ||||
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 (loss) from continuing operations as a result of the following:
| 2001 | 2000 | 1999 | ||||
| (in thousands) | ||||||
| Computed tax expense (benefit) at statutory rate | $ | 1,925 | $ | (44) | $ | 2,909 |
| Increase (decrease) in tax expense resulting from: | ||||||
| Tax depletion in excess of book | (2,412) | (563) | (417) | |||
| State income taxes, net | 842 | 106 | - | |||
| Change in valuation | ||||||
| allowance for net deferred tax assets | - | 11 | (2,951) | |||
| Other, net | 81 | 53 | 377 | |||
| Income tax expense (benefit) | $ | 436 | $ | (437) | $ | (82) |
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2001 and 2000 are presented below:
| 2001 | 2000 | |||
| Deferred tax assets: | (in thousands) | |||
| Net operating loss carryforwards | $ | 62,853 | $ | 68,618 |
| Alternative minimum tax credit carryforwards | 2,608 | 2,608 | ||
| Accruals for the following: | ||||
| Workers' compensation | 5,216 | 6,135 | ||
| Postretirement benefit obligation | 39,124 | 37,387 | ||
| Reclamation costs | 3,360 | 668 | ||
| 1974 UMWA pension plan obligation | 3,764 | 4,275 | ||
| Other accruals | 2,877 | 1,039 | ||
| Total gross deferred assets | 119,802 | 120,730 | ||
| Less valuation allowance | (31,270) | (86,870) | ||
| Net deferred tax assets | 88,532 | 33,860 | ||
| Deferred tax liabilities: | ||||
| Investment in independent power projects | $ | (13,769) | $ | (18,068) |
| Plant and equipment, differences due to depreciation and amortization |
(13,508) | (11,422) | ||
| Prepaid pension cost | (1,400) | (1,647) | ||
| Excess of trust assets over pneumoconiosis benefit obligation | (2,794) | (2,723) | ||
| Total gross deferred tax liabilities | (31,471) | (33,860) | ||
| Net deferred tax liability | $ | 57,061 | $ | - |
The net deferred tax asset is presented on the consolidated balance sheets at December 31, as follows (in thousands):
| 2001 | 2000 | |||
| Deferred income tax assets – current | $ | 15,859 | $ | - |
| Deferred income tax assets – long-term | $ | 41,202 | $ | - |
| $ | 57,061 | $ | - | |
An income tax benefit of $989,000 related to the exercise of stock options during 2001 was added to other paid-in capital.
Based on estimated taxable income generated during 2001, the Company expects to have used approximately $15,238,000 of its Federal net operating loss carryforwards. As of December 31, 2001, a minimum of $181,272,000 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 $119,802,000. As of December 31, 2001, the Company has available Federal net operating loss carryforwards to reduce future taxable income which expire as follows:
| Expiration Date | Regular Tax | |
| (in thousands) | ||
| 2009 | $ | 3,329 |
| 2010 | 52,081 | |
| 2011 | 36,479 | |
| 2012 | 449 | |
| 2018 | 28 | |
| after 2018 | 88,906 | |
| Total | $ | 181,272 |
The Company has alternative minimum tax credit carryforwards of $2,608,000 which are available indefinitely to offset future Federal taxes payable. For Alternative Minimum Tax purposes, the Company has net operating loss carryforwards of approximately $56,521,000 as of December 31, 2001. The Federal Alternative Minimum Tax regulations were recently changed to allow 100% utilization of net operating loss carryforwards in 2001 and 2002. As of December 31, 2001, the Company also has available an estimated $16,016,000 and $3,004,000 in net operating loss carryforwards in Montana and Colorado, respectively, to reduce future taxable income.
Preferred stock dividends at a rate of 8.5% per annum were paid quarterly from the third quarter of 1992 through the first quarter of 1994. The declaration and payment of preferred stock dividends was suspended in the second quarter of 1994 in connection with extension agreements with the Company’s principal lenders. Upon the expiration of these extension agreements, the Company paid a quarterly dividend on April 1, 1995 and July 1, 1995. Pursuant to the requirements of Delaware law, described below, the preferred stock dividend was suspended in the third quarter of 1995 as a result of recognition of losses and the subsequent shareholders’ deficit. The quarterly dividends which are accumulated but unpaid through and including January 1, 2002 amount to $12,862,000 in the aggregate ($61.63 per preferred share or $15.41 per depositary share). Common stock dividends may not be declared until the preferred stock dividends that are accumulated but unpaid are made current.
During 1999, the Company purchased 1,465,165 outstanding depositary shares, each representing one quarter of a share of its Series A Convertible Exchangeable Preferred Stock (“Series A Preferred Stock”), for $27,838,000. The depositary shares purchased were converted into shares of Series A Preferred Stock and retired. This reduced the number of shares of Series A Preferred Stock outstanding from 575,000 to 208,708, accumulated but unpaid dividends from $21,994,000 to $8,870,000, and the ongoing quarterly preferred dividend requirement from $1,222,000 to $444,000.
There are statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which the Company is incorporated. Under Delaware law, the Company is permitted to pay preferred stock dividends only: (1) out of surplus, surplus being the amount of shareholders’ equity in excess of the par value of the Company’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 $208,708 at December 31, 2001). The Company had shareholders’ equity at December 31, 2001 of $10,415,000 and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $18,996,000 at December 31, 2001.
As of December 31, 2001, the Company had options outstanding from three Incentive Stock Option (“ISOs”) Plans for employees and three Incentive Stock Option Plans for directors.
The 1985 employee Plan provides for the granting of ISOs and stock appreciation rights and the 1995 and 2000 employee Plans provide for the granting of ISOs and restricted stock. The 1985, 1995 and 2000 Plans also provide for the grant of non-qualified options, if so designated, and contain the terms specified for non-qualified options. Restricted stock is an award payable in shares of common stock subject to forfeiture under certain conditions. ISOs granted under the 1985, 1995 and 2000 Plans generally vest over two years and expire ten years from the date of grant and may not have an option price that is less than the fair market value of the stock on the date of grant. The maximum number of shares of the Company’s common stock that could be issued or granted under the 1985, 1995 and 2000 Plans is 400,000, 350,000 and 350,000, respectively.
The 1985 Plan expired on January 7, 1995. Therefore, no further grants may now be made from this plan. As of December 31, 2001, the 1995 and 2000 Plans have 70,000 and 40,700, respectively, shares available for future issue or grant.
The 1991 Non-Qualified Stock Option Plan for Non-Employee Directors provides for the granting on September 1 of each year of options to purchase 1,500 shares of the Company’s common stock. The maximum number of shares of the Company’s common stock that may be issued pursuant to options granted under the plan is 200,000 shares (141,500 shares are available for grants as of December 31, 2001) and the options expire ten years after the date of grant. Options granted pursuant to this plan vest after the completion of one year of board service following the date of grant. Grants under this plan were suspended in 1996 and resumed upon the Company’s dismissal from bankruptcy.
In 1996, the shareholders approved the 1996 Directors’ Stock Incentive Plan. The plan provides for the grant of non-qualified stock options to directors on an annual basis beginning on the date of the 1996 Annual Meeting with options for 20,000 shares to be granted to each director on that date or after a director is first elected or appointed, and options for 10,000 shares to be granted to each director after each annual meeting thereafter. The maximum number of shares of the Company’s common stock that may be issued or granted under the plan is 350,000 (none are available as of December 31, 2001) and the options expire no later than ten years after the date of grant. Options granted pursuant to this plan vest 25% per year over a four-year period. Options granted during a director’s period of active service continue to vest pursuant to this schedule if a director leaves the board due to reaching retirement age. In the event of a change of control of the Company, any option that was not previously exercisable and vested will become fully exercisable and vested.
In 2000, the Board of Directors adopted the 2000 Nonemployee Directors’ Stock Incentive Plan, and as permitted by applicable American Stock Exchange rules, did not seek shareholder approval of this plan. Like the 1996 Directors’ Plan, options for 20,000 shares are granted to each director when first elected or appointed, and options for 10,000 shares are granted after each annual meeting thereafter. The maximum number of shares that may be issued under the plan and the vesting, expiration and acceleration upon change-of-control provisions are the same as the 1996 Directors’ Plan. As of December 31, 2001, there are 160,000 shares available under this plan for future issue or grant.
Information for 2001, 2000 and 1999 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, 1998 | $2.63-20.00 | 349,500 | $ 6.72 |
| Granted in 1999 | 3.00-4.00 | 449,500 | 3.11 |
| Exercised in 1999 | 2.63 | (25,000) | 2.63 |
| Outstanding at December 31, 1999 | 2.63-20.00 | 774,000 | 4.76 |
| Granted in 2000 | 2.81-7.94 | 477,800 | 3.43 |
| Exercised in 2000 | 2.625 | (2,000) | 2.625 |
| Expired or forfeited in 2000 | 14.276 | (75,000) | 14.276 |
| Outstanding at December 31, 2000 | $2.63-20.00 | 1,174,800 | 3.64 |
| Granted in 2001 | 12.04-18.189 | 135,500 | 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 | $2.63-18.189 | 882,350 | 5.51 |
Information about stock options outstanding as of December 31, 2001 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 | 684,850 | 6.1 | $2.95 | 405,450 | $2.94 |
| 5.01-10.00 | 59,000 | 6.4 | 7.13 | 29,000 | 6.85 |
| 10.01-15.00 | 14,000 | 7.4 | 12.20 | 3,000 | 12.38 |
| 15.01-18.189 | 124,500 | 9.4 | 18.06 | - | - |
| $2.63-18.189 | 882,350 | 6.6 | $5.51 | 437,450 | $3.26 |
The Company applies APB Opinion 25 and related Interpretations in accounting for its plans. Accordingly, no compensation cost has been recognized for its stock option plans. Had compensation cost for the Company’s three stock-based compensation plans been determined based on the fair value at the grant dates for awards under those plans consistent with the FASB Statement 123, the Company’s net income (loss) and income (loss) per share would have been reduced to the pro forma amounts indicated below:
| 2001 | 2000 | 1999 | ||||
| (in thousands, except per share data) | ||||||
| Net income (loss) applicable to common shareholders: | ||||||
| As reported | $ | 3,451 | $ | (1,468) | $ | 5,645 |
| Pro forma | $ | 1,986 | $ | (2,140) | $ | 5,227 |
| Income (loss) per share applicable to common shareholders: | ||||||
| As reported, basic | $ | 0.48 | $ | (0.21) | $ | 0.80 |
| Pro forma, basic | $ | 0.26 | $ | (0.30) | $ | 0.74 |
| As reported, diluted | $ | 0.43 | $ | (0.21) | $ | 0.79 |
| Pro forma, diluted | $ | 0.25 | $ | (0.30) | $ | 0.73 |
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 2001, 2000 and 1999. The weighted average fair value of options granted in 2001, 2000 and 1999 was $17.58, $3.26 and $.89, respectively.
| Options Granted | Dividend Yield | Volatility | Risk-Free Rate | Expected Life |
| 2001 | None | 272% | 4.89 - 5.39% | 10 years |
| 2000 | None | 257-304% | 5.8-6.13% | 8-10 years |
| 1999 | None | 55-61% | 4.76-6.11% | 8-10 years |
The Company’s operations have been classified into three segments: coal, independent power operations and terminal operations. The coal segment includes the production and sale of coal from Eastern Montana, North Dakota and Texas. The independent power operations include the ownership of interests in cogeneration and other non-regulated independent power plants. The terminal operation segment consists of the leasing of capacity at Dominion Terminal Associates, a coal storage and vessel loading facility. The “Corporate” classification noted in the tables represents all costs not otherwise classified, including corporate office charges, heritage health benefit costs, business development expenses and all residual costs of the idled Virginia Division. Summarized financial information by segment for 2001, 2000 and 1999 is as follows:
Year ended December 31, 2001
| Coal | Independent Power | Terminal Operations | Corporate | Total | ||||||
| (in thousands) | ||||||||||
| Revenues: | ||||||||||
| Coal revenue | $ | 231,048 | $ | - | $ | - | $ | - | $ | 231,048 |
| Equity in earnings (share of losses) |
- | 15,871 | (1,922) | - | 13,949 | |||||
| 231,048 | 15,871 | (1,922) | - | 244,997 | ||||||
| Costs and expenses: | ||||||||||
| Cost of sales - coal | 177,304 | - | - | - | 177,304 | |||||
| Depreciation, depletion, and amortization |
9,124 | 11 | - | 30 | 9,165 | |||||
| Selling and administrative expense |
13,184 | 376 | 58 | 9,722 | 23,340 | |||||
| Heritage health benefit costs | - | - | - | 23,773 | 23,773 | |||||
| Pension benefit | - | - | - | (211) | (211) | |||||
| Doubtful account recoveries | (428) | - | - | (18) | (446) | |||||
| Loss (gains) on sales of assets | - | 440 | - | - | 440 | |||||
| Operating income (loss) | $ | 31,864 | $ | 15,044 | $ | (1,980) | $ | (33,296) | $ | 11,632 |
| Capital expenditures | $ | 5,388 | $ | 4 | $ | - | $ | 41 | $ | 5,433 |
| Property, plant and equipment (net) |
$ | 195,968 | $ | 45 | $ | - | $ | 1,258 | $ | 197,271 |
Year ended December 31, 2000
| Coal | Independent Power | Terminal Operations | Corporate | Total | ||||||
| (in thousands) | ||||||||||
| Revenues: | ||||||||||
| Coal revenue | $ | 35,137 | $ | - | $ | - | $ | - | $ | 35,137 |
| Equity in earnings (share of losses) |
- | 32,260 | (1,800) | - | 30,460 | |||||
| 35,137 | 32,260 | (1,800) | - | 65,597 | ||||||
| Costs and expenses: | ||||||||||
| Cost of sales - coal | 30,250 | - | - | - | 30,250 | |||||
| Depreciation, depletion, and | ||||||||||
| amortization | 1,847 | 29 | - | 96 | 1,972 | |||||
| Selling and administrative expense |
900 | 456 | 362 | 6,068 | 7,786 | |||||
| Heritage health benefit costs | - | - | - | 21,503 | 21,503 | |||||
| Pension benefit | - | - | - | (585) | (585) | |||||
| Doubtful account recoveries | - | - | - | (400) | (400) | |||||
| Impairment charge | - | 4,632 | - | - | 4,632 | |||||
| Loss (gains) on sales of assets | - | (2) | - | 8 | 6 | |||||
| Operating income (loss) | $ | 2,140 | $ | 27,145 | $ | (2,162) | $ | (26,690) | $ | 433 |
| Capital expenditures | $ | 621 | $ | 10 | $ | - | $ | 16 | $ | 647 |
| Property, plant and equipment (net) |
$ | 34,587 | $ | 60 | $ | - | $ | 46 | $ | 34,693 |
Year ended December 31, 1999
| Coal | Independent Power | Terminal Operations | Corporate | Total | ||||||
| (In Thousands) | ||||||||||
| Revenues: | ||||||||||
| Coal revenue | $ | 38,539 | $ | - | $ | - | $ | - | $ | 38,539 |
| Equity in earnings (share of losses) |
- | 34,492 | (1,464) | - | 33,028 | |||||
| 38,539 | 34,492 | (1,464) | - | 71,567 | ||||||
| Costs and expenses: | ||||||||||
| Cost of sales - coal | 33,637 | - | - | - | 33,637 | |||||
| Depreciation, depletion, and | ||||||||||
| amortization | 1,425 | 29 | - | 117 | 1,571 | |||||
| Selling and administrative expense |
770 | 1,020 | 732 | 7,138 | 9,660 | |||||
| Heritage health benefit costs | - | - | - | 18,737 | 18,737 | |||||
| Pension expense | - | - | - | (149) | (149) | |||||
| Doubtful account recoveries | - | - | - | (174) | (174) | |||||
| Gains on sales of assets | (433) | - | - | - | (433) | |||||
| Operating income (loss) | $ | 3,140 | $ | 33,443 | $ | (2,196) | $ | (25,669) | $ | 8,718 |
| Capital expenditures | $ | 1,999 | $ | 29 | $ | - | $ | 41 | $ | 2,069 |
| Property, plant and equipment (net) |
$ | 36,343 | $ | 81 | $ | 8 | $ | 126 | $ | 36,558 |
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:
| 2001 | 2000 | 1999 | |||
| (in thousands) | |||||
| Customer A | $ 92,626 | $ - | $ - | ||
| B | 46,104 | - | - | ||
| C | 28,784 | 23,636 | 19,392 | ||
| Percentage of total revenue | 68% | 36% | 27% | ||
As discussed in Note 2, in connection with the acquisitions completed in the second quarter, WML assumed future reclamation obligations of approximately $135,152,000 at April 30, 2001, on an undiscounted basis. As of December 31, 2001, WML had $47,924,000 of cash reserved and invested to use for future reclamation activities first at the Rosebud Mine.
As of December 31, 2001 the Company has reclamation bonds in place in Montana, North Dakota, Texas, and Virginia, to assure that operations comply with all applicable regulations and to assure the completion of final reclamation activities. The amount of the bonds exceeds the estimated cost of final reclamation activities of approximately $235,321,000, of which the Company’s obligation is estimated at $171,521,000. As of December 31, 2001, $139,648,000 has been recognized.
At NWR, WECO and WRI, certain customers and the contract miner are contractually obligated to either perform or reimburse the Company for certain reclamation activities as they are performed at certain of the Company’s other operations. Final reclamation obligations at NWR’s Jewett Mine, estimated at approximately $50,000,000, are contractually the responsibility of its customer, which has a reclamation bond for that amount. A certain customer at WECO is responsible for an estimated final reclamation cost of $9,900,000. WRI has an agreement with its mining contractor and 20% owner of WRI, Washington Group International, Inc. (“WGI”), which contractually limits the Company’s maximum liability for reclamation costs associated with final mine closure of the Absaloka mine. It calls for WRI to pay approximately $1,700,000 over a 15-year period, which began in December 1990. All remaining liability at WRI is that of WGI. These reclamation activities are estimated to cost approximately $13,800,000.
The Company believes its mining operations are in compliance with applicable federal, state and local environmental laws and regulations, including those relating to surface mining and reclamation, and it is the policy of the Company to operate in compliance with such standards. The Company maintains compliance primarily through the performance of reclamation, maintenance and monitoring activities.
During 2001, WRI’s mining contractor and 20% owner, WGI, filed a petition seeking to reorganize its debts pursuant to Chapter 11 of the Bankruptcy Code. WGI filed its petition in the bankruptcy court in Reno, Nevada. Prior to the time that the bankruptcy petition was filed, WRI had filed suit against WGI seeking to recover costs associated with certain repair and replacement of components of WRI’s dragline. WGI’s bankruptcy petition stayed that litigation. On February 15, 2002, the bankruptcy court lifted the automatic stay and remanded the dragline litigation to the U.S. District Court in Montana. WRI has filed other claims against WGI; these claims allege, among other things, that WGI overcharged for the cost of mining, failed to provide a competitive cost of mining, and failed to provide adequate assurances that contractually required reclamation will be done. WRI has also requested reimbursement of alleged unpaid royalties and objected to assumption of the mining contracts between WGI and WRI pursuant to which WGI provides contract mining and reclamation services to WRI. No date has been set to resolve WRI’s claims.
The contracts between WRI and WGI are executory and must either be assumed or rejected in the bankruptcy proceeding. Each of WRI’s alleged claims reflects a potential breach of those contracts. If WGI assumes the mining contracts it must either cure the existing breaches of contract or demonstrate to the Bankruptcy Court’s satisfaction an ability to satisfy any adverse decision arising from litigation of the alleged breach of contract claims. It is currently believed that WGI intends to assume the mining contracts; however, WGI has reserved the right to reject any executory contracts at any time prior to final resolution of its bankruptcy case. If WGI rejects the mining contracts, they will be terminated and WRI will have an unsecured claim for damages. In that event, WRI will be prepared to continue coal production at the mine and to comply with regulatory and environmental requirements.
On September 24, 2001, WRI gave WGI notice of a dispute regarding past and future pricing for contract mining services. WRI believes the price per ton should be substantially reduced. If the parties are unable to resolve the dispute through negotiation or unless resolved by the Bankruptcy Court, binding arbitration will follow. WRI has also begun discussions with its largest customer regarding extension or replacement of the term of the coal supply agreement which expires December 31, 2002. Another customer of WRI has requested consideration of the acceleration of a contract reopener provision from 2003 into 2002 and requested that WRI provide price and extended term information for discussion.
NWR, as part of a settlement of pending litigation entered into an Amended Lignite Supply Agreement (“LSA”) in 1998 with Reliant Energy, Inc. (“Reliant”) for its Limestone Electric Generating Station (“LEGS”). The LSA preserved the existing cost-plus contract structure through June 30, 2002, when the price shifts to a market-based price derived by comparison to the value of Powder River Basin (“PRB”) spot coal delivered to LEGS. The price must be between a minimum and a maximum as determined in the LSA. The contract provides for NWR to make its annual tonnage commitments one year in advance and six months before the price is determined. LEGS is obligated to take NWR’s committed tonnage. NWR has nominated tonnages it will deliver to LEGS through December 31, 2003; however, the price for the nominated tonnage will not be set until July 1, 2002. NWR always has the right to supply nominated volumes as well as any additional fuel required by LEGS as long as it meets the price equivalent to the value of PRB coal at LEGS. In the event that NWR elects not to match the equivalent PRB value on all or any portion of the LEGS fuel requirement, Reliant may purchase PRB coal.
NWR has begun discussions with Reliant to resolve pricing for the eighteen month supply of lignite it has nominated to supply through December 31, 2003. It is expected that NWR will make similar tonnage nominations until the contract expires in 2015. In addition, NWR and Reliant are discussing impacts of changes to LEGS and construction of a rail unloader. To protect its contract rights and, if necessary, obtain guidance on interpreting the LSA in the changed circumstances, NWR has filed a declaratory judgment action in Freestone County, Texas. The litigation has only recently been filed and it is too early to predict any likelihood of success. If the cost of delivering PRB coal became such that NWR determined that produced lignite was uneconomic, Reliant would be obligated to begin performance of final reclamation activities. Refer to Item 3 – Legal Proceedings for further information.
WECO’s Coal Supply Agreement with the Colstrip units 1 and 2 owners contains a provision calling for a price reopener in July 2001. The parties have begun discussions to attempt to reach a consensual agreement about future price; however, in the event the parties are unable to reach an agreement, the Coal Supply Agreement provides for a binding arbitration to resolve the issue.
The Company is subject to certain financial ratio tests under the terms of an agreement with the UMWA (the “Master Agreement”), which facilitated the Company’s discharge from Chapter 11 Bankruptcy in 1998. The Company’s obligations under the Master Agreement are secured by a Contingent Promissory Note (the “Note”) in an initial principal amount of $12 million; the principal amount of the Note decreases to $6 million in 2002. The Note is payable only in the event the Company does not meet its Coal Act obligations, fails to meet certain ongoing financial ratio tests specified in the Note, fails to maintain the required balance of $6 million in the escrow account through 2001 or fails to comply with certain covenants set forth in a security agreement. The Note also gives the Company certain rights to cure a default that would otherwise ripen into an “Event of Default”: on no more than two occasions, the Company may cure a default that arises from the Company’s failure to satisfy the financial ratios in a quarter by complying with the financial ratios in the immediately following quarter. The Company did not satisfy the financial ratio test which measures operating income versus debt service requirements for the quarter ended June 30, 2001 because of its acquisitions. The Company’s financial results for that period reflected only two months of operating income from the acquisitions, while the debt service amount included the full effect of the acquisition financing. The Company has cured any default that existed at June 30, 2001, by complying with the financial ratios at September 30 and December 31, 2001. The Note terminates on January 1, 2005. The Company believes it will comply with the financial ratios in the Note through its expiration.
As discussed in Note 2, the final purchase price for the acquisition of Montana Power’s coal business is subject to adjustment. In the unlikely event additional payments are required to be made, they would likely be funded through borrowings under the Facility described in Note 4. Pursuant to the credit agreements, if the purchase price is reduced, amounts received are required to be applied to the acquisition debt, as explained in Note 4. Any change in the purchase price will result in a change to the preliminary purchase price allocation disclosed in Note 2 and is not expected to have a material adverse effect on the Company’s results of operations or liquidity.
The Company is a party to numerous 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 $21,729,000, $2,898,000 and $3,115,000 in 2001, 2000 and 1999, respectively.
The Company has operating lease commitments expiring at various dates, primarily for real property and equipment. Rental expense under operating leases during 2001, 2000 and 1999 totaled $3,150,000, $44,000 and $42,000, respectively. Minimum future rental obligations existing under these leases at December 31, 2001 are as follows (in thousands):
| Lease Obligations | |
| 2002 | $ 3,515 |
| 2003 | 1,118 |
| 2004 | 899 |
| 2005 | 620 |
| 2006 and thereafter | - |
The following table presents total sales tonnage the Company expects to ship under existing long-term contracts from the Company’s mining operations (in thousands):
| Projected Sales Tonnage Under | ||
| Existing Long-Term Contracts | ||
| 2002 | 27,120 | |
| 2003 | 22,883 | |
| 2004 | 22,850 | |
| 2005 | 22,850 | |
| 2006 | 21,850 | |
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 term notes entered into by WML for that purpose significantly restrict the cash and other assets available for distribution or dividend to the parent company or other entities in the consolidated group. See Note 4 for a more detailed discussion of the restrictions and the amount of cash that is available for general use. Due to the recognition of a $55,600,000 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 year ended December 31, 2001, WML paid $3,750,000 of dividends and $1,500,000 of management fees to its parent.
The following are the condensed consolidated financial statements of WML and its subsidiaries as of and for the year ended December 31, 2001 (in thousands):
| Condensed Consolidated Balance Sheet as of December 31, 2001 |
||
| Cash and cash equivalents | $ | 624 |
| Accounts receivable, net | 32,573 | |
| Restricted cash | 8,371 | |
| Other current assets | 18,466 | |
| Property, plant and equipment, net | 216,173 | |
| Deferred tax assets | 402 | |
| Reclamation deposits | 47,924 | |
| Reclamation receivable | 10,360 | |
| Other assets | 20,920 | |
| Total Assets | $ | 355,813 |
| Current portion of long-term debt | $ | 13,753 |
| Accounts payable and accrued expenses | 29,225 | |
| Payable to parent | 10,068 | |
| Other current liabilities | 2,818 | |
| Line of credit | 8,000 | |
| Long-term debt, less current portion | 98,157 | |
| Reclamation obligations | 137,748 | |
| Other liabilities | 9,409 | |
| Member’s equity | 46,635 | |
| Total Liabilities and Member’s Equity | $ | 355,813 |
| Condensed Consolidated Statement of Operations for the Eight Months Ended December 31, 2001 |
||
| Coal revenues | $ | 187,021 |
| Cost of sales – coal | (139,915) | |
| Depreciation and amortization expense | (9,825) | |
| Selling and administrative expense | (11,559) | |
| Management fees to parent | (1,500) | |
| Operating income | 24,222 | |
| Interest expense | (7,616) | |
| Interest and other income | 1,999 | |
| Income before income taxes | 18,605 | |
| Income tax expense | (7,269) | |
| Net income | $ | 11,336 |
| Condensed Consolidated Statement of Cash Flows for the Eight Months Ended December 31, 2001 |
||
| Net income | $ | 11,336 |
| Depreciation and amortization expense | 9,825 | |
| Deferred income tax benefit | (402) | |
| Changes in operating assets and liabilities | 12,540 | |
| Cash provided by operating activities | 33,299 | |
| Cash paid for acquisitions | (164,980) | |
| Increase in restricted cash | (8,371) | |
| Fixed asset additions | (5,291) | |
| Cash used in investing activities | (178,642) | |
| Proceeds from borrowings of long-term debt, net | 114,719 | |
| Repayment of long-term debt | (12,053) | |
| Contributions from parent | 39,051 | |
| Borrowings under line of credit, net | 8,000 | |
| Dividends to parent | (3,750) | |
| Cash provided by financing activities | 145,967 | |
| Net increase in cash and cash equivalents | 624 | |
| Cash and cash equivalents, beginning of year | - | |
| Cash and cash equivalents, end of year | $ | 624 |
WRI has a coal mining contract with WGI, its 20% stockholder. Mining costs incurred under the contract were $21,466,000, $17,507,000 and $19,445,000 in 2001, 2000 and 1999, respectively.
Summarized quarterly financial data for 2001 and 2000 are as follows:
| Three Months Ended | ||||||||
| March 31 | June 30 | Sept. 30 | Dec. 31 | |||||
| (in thousands except per share data) | ||||||||
| 2001 | ||||||||
| Revenues | $ | 16,342 | $ | 53,339 | $ | 89,887 | $ | 85,429 |
| Costs and expenses | 18,578 | 53,480 | 78,735 | 82,572 | ||||
| Operating income (loss) | (2,236) | (141) | 11,152 | 2,857 | ||||
| Income (loss) from continuing | ||||||||
| operations before income taxes | (2,118) | (1,428) | 8,870 | 339 | ||||
| Income tax (expense) benefit | (89) | 500 | (2,661) | 1,814 | ||||
| Net income (loss) | (2,207) | (928) | 6,209 | 2,153 | ||||
| Less preferred stock dividend | ||||||||
| requirements | (444) | (444) | (444) | (444) | ||||
| Income (loss) applicable to common | ||||||||
| shareholders | $ | (2,651) | $ | (1,372) | $ | 5,765 | $ | 1,709 |
| Income (loss) per share applicable to common shareholders: |
||||||||
| Basic | $ | (0.37) | $ | (0.19) | $ | 0.79 | $ | 0.23 |
| Diluted | $ | (0.37) | $ | (0.19) | $ | 0.73 | $ | 0.21 |
| Weighted average number of common and common equivalent shares outstanding: |
||||||||
| Basic | 7,075 | 7,144 | 7,264 | 7,471 | ||||
| Diluted | 7,075 | 7,144 | 7,859 | 8,069 | ||||
| Three Months Ended | ||||||||
| March 31 | June 30 | Sept. 30 | Dec. 31 | |||||
| (in thousands except per share data) | ||||||||
| 2000 | ||||||||
| Revenues | $ | 12,665 | $ | 14,495 | $ | 14,128 | $ | 24,309 |
| Costs and expenses | (14,538) | (16,312) | (14,972) | (19,342) | ||||
| Operating income (loss) | (1,873) | (1,817) | (844) | 4,967 | ||||
| Income from continuing operations | ||||||||
| before income taxes | (2,491) | (2,079) | (1,035) | 5,476 | ||||
| Income tax (expense) benefit | - | - | - | 437 | ||||
| Net income (loss) | (2,491) | (2,079) | (1,035) | 5,913 | ||||
| Less preferred stock dividend | ||||||||
| requirements | (444) | (444) | (444) | (444) | ||||
| Income (loss) applicable to common | ||||||||
| shareholders | $ | (2,935) | $ | (2,523) | $ | (1,479) | $ | 5,469 |
| Income (loss) per share applicable to | ||||||||
| common shareholders | $ | (0.42) | $ | (0.35) | $ | (0.21) | $ | 0.77 |
| Weighted average number of common and common equivalent shares outstanding |
7,068 | 7,070 | 7,070 | 7,070 | ||||
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, 2001 and 2000, 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, 2001. 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, 2001 and 2000, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.
KPMG LLP
Denver, Colorado
March 8, 2002
This item is not applicable.
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.
| a) 1. | The financial statements filed herewith are the Consolidated Balance Sheets of the Company and subsidiaries as of December 31, 2001 and December 31, 2000, 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, 2001 together with the Summary of Significant Accounting Policies and Notes, which are contained on pages 58 through 95 inclusive. |
| 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. | ||
| (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. | |
| (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. | ||
| (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. | ||
| (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. | ||
| (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) | Rights Agreement, dated as of January 28, 1993, between Westmoreland Coal Company and the First Chicago Trust Company of New York. Reference is hereby made to Exhibit 4 to Westmoreland’s Form 8-K filed February 1, 1993, which Exhibit is incorporated herein by reference. | ||
| (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). | ||
| (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, 2001 (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, 2001 (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). | ||
| (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). | ||
| (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 Credit Agreement, the Banks under the Credit Agreement, and PNC Bank, National Association, as Agent, and filed herewith as Exhibit 10(w). | ||
| (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, and filed herewith as Exhibit 10(x). | ||
| (y) | Second Amendment to Term Loan Agreement dated February 27, 2002 among 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). | ||
| (z) | 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). | ||
| (aa) | Pledge Agreement dated as of April 27, 2001, by and among Westmoreland Coal Company, Westmoreland Mining LLC, the other entities from time to time party thereto as pledgors, and Firstar Bank, N.A., as collateral agent for the banks in connection with the Revolving Credit Agreement is incorporated herein by reference to Exhibit 99.5 to the Registrant’s Current Report on Form 8-K dated May 15, 2001 (SEC File #001-11155). | ||
| (bb) | 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). |
| (cc) | 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). | ||
| (dd) | 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). | ||
| (ee) | 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) | ||
| (ff) | Westmoreland Coal Company 2000 Performance Unit Plan is filed herewith as Exhibit 10(ff). | ||
| (21) | Subsidiaries of the Registrant | ||
| (23) | Consent of Independent Certified Public Accountants | ||
| b) | Reports on Form 8-K. | ||
| (1) | On October 24, 2001, the Company filed a report on Form 8-K regarding its shareholders’ letter for the quarter ended June 30, 2001 and its expected range of earnings per share for the quarter ended September 30, 2001. | ||
| (2) | On December 19, 2001, the Company filed a report on Form 8-K regarding the execution on December 14, 2001 of a Loan Agreement with First Interstate Bank, a Montana corporation, for a two-year $7 million Revolving Line of Credit. | ||
| (3) | On January 3, 2002, the Company filed a report on Form 8-K announcing that it had recently adopted a policy that provides for the use of pre-arranged trading plans by persons subject to the Company’s insider trading policy as provided for under the Securities and Exchange Commission’s new Rule 10b5-1. | ||
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 27, 2002 | By: /s/ Ronald H. Beck |
| Ronald H. Beck | |
| Vice President of Finance and Treasurer | |
| (A Duly Authorized Officer) | |
| Date: March 27, 2002 | 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 27, 2002 |
| Christopher K. Seglem |
|
|
| Directors: | ||
| /s/ Michael Armstrong |
Director |
March 27, 2002 |
| Michael Armstrong | ||
| /s/ Thomas J. Coffey |
Director |
March 27, 2002 |
| Thomas J. Coffey | ||
| /s/ Pemberton Hutchinson |
Director |
March 27, 2002 |
| Pemberton Hutchinson | ||
| /s/ Robert E. Killen |
Director |
March 27, 2002 |
| Robert E. Killen | ||
| /s/ William R. Klaus |
Director |
March 27, 2002 |
| William R. Klaus | ||
| /s/ Thomas W. Ostrander |
Director |
March 27, 2002 |
| Thomas W. Ostrander | ||
| /s/ James W. Sight |
Director |
March 27, 2002 |
| James W. Sight | ||
| /s/ William M. Stern |
Director |
March 27, 2002 |
| William M. Stern | ||
The Board of Directors and Shareholders
Westmoreland Coal Company:
Under date of March 8, 2002, we reported on the consolidated balance sheets of Westmoreland Coal Company and subsidiaries as of December 31, 2001 and 2000, 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, 2001, which report appears in the December 31, 2001, 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
March 8, 2002
Schedule II
Valuation Accounts
Years Ended December 31, 2001, 2000 and 1999
(in thousands)
| Balance at beginning of year | Deductions credited to earnings | Other Additions | Balance at end of year | ||||
| Year ended December 31, 2001: | |||||||
| Allowance for doubtful accounts | $ | 3,301 | (446) | 102 | $ | 2,957 | (A) |
| Year ended December 31, 2000: | |||||||
| Allowance for doubtful accounts | $ | 3,602 | (400) | 99 | $ | 3,301 | (A) |
| Year ended December 31, 1999: | |||||||
| Allowance for doubtful accounts | $ | 3,776 | (174) | - | $ | 3,602 | (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. |
EXHIBIT 21
Subsidiaries of the Registrant for the year ended December 31, 2001:
| 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, Inc. | 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 |
| WCCO-KRC Acquisition Corp. | Delaware |
| Westmoreland Mining LLC | Delaware |
| Dakota Westmoreland Corporation | Delaware |
| Western Energy Company | Montana |
| Northwestern Resources Co. | Montana |
| Basin Resources, Inc. | Colorado |
| North Central Resources, Inc. | Colorado |
| Horizon Coal Services, Inc. | Montana |
| Westmoreland Power, Inc. | Delaware |
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 and No. 333-66698) on Form S-8 of Westmoreland Coal Company of our reports dated March 8, 2002, relating to the consolidated balance sheets of Westmoreland Coal Company and subsidiaries as of December 31, 2001 and 2000, 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, 2001, and the related schedule, which reports appear in the December 31, 2001, Annual Report on Form 10-K of Westmoreland Coal Company.
KPMG LLP
Denver, Colorado
March 22, 2002
Exhibit 10(w)
THIS AMENDMENT NO. 2 TO CREDIT AGREEMENT (“Amendment”), dated as of February 27, 2002, is made by and among WESTMORELAND MINING LLC, a Delaware limited liability company (the “Borrower”), the Guarantors (defined as each of the parties to this Amendment which is designated as a “Guarantor” on the signature pages hereof) and each of the Banks (defined as each of the parties to this Amendment which is designated as a “Bank” on the signatures page hereof) party to the Credit Agreement (defined below).
WITNESSETH:
WHEREAS, the parties hereto entered into that certain Credit Agreement dated as of April 27, 2001, as amended by that certain First Amendment to Credit Agreement dated as of August 15, 2001, by and among the Borrower, the Guarantors and the Banks (the “Credit Agreement”). Capitalized terms not otherwise defined herein shall have the respective meanings given to them under the Credit Agreement;
WHEREAS, the Borrower has requested that the Banks amend certain provisions of the Credit Agreement and the Collateral Agency Agreement; and
WHEREAS, the parties hereto agree to amend the Credit Agreement on the terms and conditions set forth below.
NOW, THEREFORE, the parties hereto, in consideration of the mutual covenants and agreements herein contained and intending to be legally bound hereby, covenant and agree as follows:
1. Amendment to Definitions.
(a) Amended Definition. The definition of Consolidated Net Worth set forth in Section 1.1 to the Credit Agreement shall be amended and restated as follows:
| “Consolidated Net Worth shall mean as of any date of determination consolidated stockholders’ equity of the Borrower and its Subsidiaries as of such date determined and consolidated in accordance with GAAP, but specifically excluding the cumulative effect on stockholders’ equity arising from the Non-Cash Income Tax Expense.” |
(b) Additional Definition. Section 1.1 to the Credit Agreement shall be amended by inserting the following definition alphabetically into the list of defined terms:
| “Non-Cash Income Tax Expense shall mean deferred income taxes which are tax expenses of the Borrower and the Guarantors to any Person (including without limitation, any member of the Parent Group) other than payments due and payable to governmental tax agencies on behalf of the Borrower or the Guarantors.” |
2. Amendments to Credit Agreement.
(a) Subordination of Management Fees; Payment of Management Fees [Section 8.1.19]. Section 8.1.19 of the Credit Agreement shall be amended and restated as follows:
"8.1.19 Subordination of Management Fees; Payment of Management Fees.
The Borrower shall cause any fees or charges, of whatever nature, payable by the Loan Parties to any member of the Parent Group, including without limitation, the Non-Cash Income Tax Expense and all fees and charges in connection with the management of the operations of the Borrower, to be subordinated to the payment of the Notes, with the subordination in the case of payments to the Parent to be pursuant to the Management Fee Subordination Agreement and with the subordination in the case of payments to any other Affiliate of the Borrower to be subordinated to the Obligations, with the terms of such subordination to be satisfactory to the Required Banks. The Loan Parties agree that the payment of any fees or charges to the Parent or any other member of the Parent Group, all of which are subordinated in accordance with the preceding sentence, may be made by the Loan Parties only if such payments are in accordance with the following: (i) prior to and after giving effect to the payment thereof, no Event of Default or Potential Default is in existence; (ii) the payments consist solely of the Management Fee, plus Third Party Services Payments; and (iii) such payments shall be otherwise permitted by and in accordance with the Management Fee Subordination Agreement; provided that, notwithstanding anything contained in this Subsection or the Management Fee Subordination Agreement to the contrary, in the event that the Borrower is permitted to make a dividend or distribution in accordance with Section 8.2.5, the Borrower shall be permitted, in lieu of making such permitted distribution or dividend, to apply such permitted dividend or distribution to reduce the payable arising from the Non-Cash Income Tax Expense."
(b) Capital Expenditures and Leases [Section 8.2.16]. Section 8.2.16 of the Credit Agreement shall be amended and restated as follows:
"8.2.16 Capital Expenditures and Capitalized Leases.
Each of the Loan Parties shall not, and shall not permit any of its Subsidiaries to, make any payments exceeding the amounts indicated on Schedule 8.2.16 hereto in the aggregate in any fiscal year on account of the purchase or lease of any assets which are required to be capitalized on the financial statements of such Loan Party in accordance with GAAP (“Capital Expenditures”), and all such purchases and leases shall be made under usual and customary terms and in the ordinary course of business, provided that, any amounts not expended by the Loan Parties for Capital Expenditures in any given fiscal year may be carried forward and used in a subsequent year. The amount of the Capital Expenditures permitted by Schedule 8.2.16 for each fiscal year shall be increased by the Operating Lease Availability (as defined in Section 8.2.20) for such fiscal year, provided, however, that the Operating Lease Availability if not used for Capital Expenditures in the same year shall not be carried forward to increase the amount of Capital Expenditures in subsequent years.”
(c) Operating Leases [Section 8.2.20]. Section 8.2.20 of the Credit Agreement shall be amended and restated as follows:
"8.2.20 Operating Leases.
The Loan Parties shall not enter into or be obligated under operating leases having aggregate payments per year in excess of the amounts set forth on Schedule 8.2.20. In the event that the Loan Parties’ operating lease payments in any given fiscal year are less than the limitation set forth on Schedule 8.2.20, the difference between the limitation and the actual operating lease payments is referred to as “Operating Lease Availability.” If and to the extent that on any date during a given fiscal year the Loan Parties (or any one or more of them) shall utilize the Operating Lease Availability to make Capital Expenditures in addition to the amount thereof that would be permitted for such fiscal year pursuant to Section 8.2.16 in the absence of such Operating Lease Availability, then for such year the aggregate amount of payments under operating leases for which the Loan Parties may thereafter be or become obligated pursuant to the first sentence of this Section 8.2.20 in respect of such fiscal year shall be reduced pro tanto.”
(d) Maximum Leverage Ratio [Section 8.2.18]. Section 8.2.18 of the Credit Agreement shall be amended and restated as follows:
"8.2.18 Maximum Leverage Ratio.
The Loan Parties shall not permit the ratio of Consolidated Total Indebtedness of the Borrower and its Subsidiaries to Consolidated EBITDA to exceed the ratio set forth below for the periods specified below, calculated as of the end of each fiscal quarter during each such period based upon the immediately preceding four fiscal quarters (provided, however, for periods ending on or before March 31, 2002, in lieu of using the preceding four fiscal quarters, the above computation shall be determined by annualizing the Consolidated EBITDA for the period from the Closing Date through the date of determination):
| Period | Ratio |
| Closing Date through December 31, 2001 | 2.25 to 1.00 |
| January 1, 2002 through December 31, 2003 | 2.00 to 1.00 |
| January 1, 2004 through December 31, 2004 | 1.75 to 1.00 |
| January 1, 2005 through December 31, 2005 | 1.50 to 1.00 |
| January 1, 2006 and thereafter | 1.00 to 1.00 |
3. Representations and Warranties.
A. Warranties Under the Credit Agreement. The representations and warranties of the Borrower contained in the Credit Agreement are true and correct on and as of the date hereof with the same force and effect as though made by the Borrower on such date, except to the extent that any such representation or warranty expressly relates solely to a previous date or is the subject of transactions permitted under the Credit Agreement. The Borrower is in compliance with all terms, conditions, provisions, and covenants contained in the Credit Agreement.
B. Power and Authority; Validity and Binding Effect; No Conflict. The Borrower and each other Loan Party has full power to enter into, execute, deliver and carry out this Amendment, and such actions have been duly authorized by all necessary proceedings on its part. This Amendment has been duly and validly executed and delivered by the Borrower and each other Loan Party. This Amendment constitutes the legal, valid and binding obligation of the Borrower and each other Loan Party which is enforceable against Borrower and each other Loan Party in accordance with its terms, except to the extent that enforceability thereof may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforceability of creditors' rights generally or by general equitable principles limiting the availability of specific performance or other equitable remedies. Neither the execution and delivery of this Amendment, nor the consummation of the transactions herein contemplated will conflict with, constitute a default under or result in any breach of (i) the terms and conditions of any organizational documents of Borrower or any other Loan Party or (ii) any Law or any agreement or instrument or other obligation to which Borrower or any other Loan Party is a party or by which it or any of the other Loan Parties is bound, or result in the creation or enforcement of any Lien upon any property of Borrower or any other Loan Party other than as set forth in the Security Documents.
C. Consents and Approvals; No Event of Default. No consent, approval, exemption, order or authorization of any person or entity other than, as the case may be, the parties hereto is required by any Law or any agreement in connection with the execution, delivery and carrying out of this Amendment. No event has occurred and is continuing and no condition exists or will exist after giving effect to this Amendment which constitutes an Event of Default.
D. Authorized Officer. The individual executing this Amendment on behalf of the Borrower and each other Loan Party, is authorized to execute and deliver this Amendment on behalf of the Borrower and each other Loan Party, and holds the office(s) with the Borrower and each other Loan Party, as the case may be, set forth below his signature to this Amendment.
4. Conditions Precedent.
The Borrower, the Guarantors and the Banks acknowledge that this Amendment shall not be effective until each of the following conditions precedent has been satisfied (as determined by the Required Banks in their sole discretion):
(a) Execution. The Borrower, the Guarantors and the Required Banks shall have executed this Amendment and each of the Banks shall have received a counterpart original or a true and correct copy hereof;
(b) Amendment of Term Loan Agreement. The Company, the Guarantors and the note holders party to the Term Loan Agreement shall have entered into an amendment to the Term Loan Agreement providing for amendments to the terms thereof consistent with the amendments to the Credit Agreement provided for herein; such amendment shall be in form and substance reasonably acceptable to the Banks and shall be in full force and effect; and each Bank shall have received a true and correct copy thereof;
(c) Representations and Warranties. Each of the representations and warranties under Section 3 hereof are true and correct on the date hereof; and
(d) Authorization by Loan Parties. There shall be delivered to the Banks evidence of appropriate action taken by the Borrower and the other Loan Parties relative to approval of this Amendment.
5. Incorporation into Credit Agreement.
This Amendment shall be incorporated into the Credit Agreement by this reference. All representations, warranties, Events of Default and covenants set forth herein shall be a part of the Credit Agreement as if originally contained therein.
6. Reimbursement of Expenses.
The Borrower unconditionally agrees to pay and reimburse each of the Banks and save each of the Banks harmless against liability for the payment of all out-of-pocket costs, expenses and disbursements, including without limitation, reasonable fees and expenses of counsel incurred by any of the Banks in connection with the development, preparation, execution, administration, interpretation or performance of this Amendment and all other documents or instruments to be delivered or recorded in connection herewith.
7. Severability.
Any provision of this Amendment that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall (to the full extent permitted by law) not invalidate or render unenforceable such provision in any other jurisdiction.
8. Entire Agreement.
This Amendment sets forth the entire agreement and understanding of the parties with respect to the amendment to the Credit Agreement contemplated hereby and supersedes all prior understandings and agreements, whether written or oral, between the parties hereto relating to such amendment. No representation, promise, inducement or statement of intention has been made by any party which is not embodied in this Amendment, and no party shall be bound by or liable for any alleged representation, promise, inducement or statement of intention not set forth herein.
9. Force and Effect.
The Borrower reconfirms, restates, and ratifies the Credit Agreement, and all other documents executed in connection therewith except to the extent any such documents are expressly modified by this Amendment and Borrower confirms that all such documents have remained in full force and effect since the date of their execution.
10. Governing Law.
This Amendment shall be deemed to be a contract under the laws of the State of New York and for all purposes shall be governed by and construed and enforced in accordance with the internal laws of the State of New York.
11. Counterparts.
This Amendment may be signed in any number of counterparts each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto by their officers duly authorized, have executed this Amendment as of the day and year first above written with the intention that it constitute a sealed instrument.
| WESTMORELAND MINING LLC | |
| By: /s/ W. Michael Lepchitz | |
| Title: Vice President, General Counsel and Assistant Secretary | |
| Name: W. Michael Lepchitz |
| WESTERN ENERGY COMPANY, an | |
| Loan Party and Guarantor | |
| By: /s/ W. Michael Lepchitz | |
| Title: Vice President, General Counsel and Assistant Secretary | |
| Name: W. Michael Lepchitz |
| NORTHWESTERN RESOURCES CO., | |
| an Loan Party and Guarantor | |
| By: /s/ W. Michael Lepchitz | |
| Title: Vice President, General Counsel and Assistant Secretary | |
| Name: W. Michael Lepchitz |
| DAKOTA WESTMORELAND CORPORATION, an | |
| Loan Party and Guarantor | |
| By: /s/ W. Michael Lepchitz | |
| Title: Vice President, General Counsel and Assistant Secretary | |
| Name: W. Michael Lepchitz |
| WCCO-KRC ACQUISITION CORP., | |
| an Loan Party and Guarantor | |
| By: /s/ W. Michael Lepchitz | |
| Title: Vice President, General Counsel and Assistant Secretary | |
| Name: W. Michael Lepchitz |
Each of the following is a "Bank", and collectively, the "Banks":
| PNC BANK, NATIONAL ASSOCIATION, | |
| individually and as Agent | |
| By: /s/ R. Kane Kiester | |
| Title: Chief Benefit Officer | |
| Name: R. Kane Kiester |
| FIRSTAR BANK, N.A. | |
| By: /s/ Eric Hartman | |
| Title: Vice President | |
| Name: Eric Hartman |
| NATIONAL CITY BANK | |
| By: /s/ Jennifer R. Hammerlund | |
| Title: Assistant Vice President | |
| Name: Jennifer R. Hammerlund |
| NM ROTHSCHILD & SONS LIMITED | |
| By: /s/ C. Coleman | |
| Title: Director | |
| Name: C. Coleman |
| By: /s/ N.A. Wood | |
| Title: Assistant Director | |
| Name: N.A. Wood |
Exhibit 10(x)
THIS SECOND AMENDMENT TO TERM LOAN AGREEMENT (“Amendment”), dated as of February 27, 2002, is made by and among WESTMORELAND MINING LLC, a Delaware limited liability company (the “Company”), the Guarantors (defined as each of the parties to this Amendment which is designated as a “Guarantor” on the signature pages hereof) and each of the Purchasers (defined as each of the parties to this Amendment which is designated as a “Purchaser” on the signatures page hereof) party to the Term Loan Agreement (defined below);
WITNESSETH:
WHEREAS, the parties hereto entered into that certain Term Loan Agreement dated as of April 27, 2001, as amended by that certain First Amendment to Term Loan Agreement dated as of August 15, 2001, by and among the Company, the Guarantors and the Purchasers (the “Term Loan Agreement”). Capitalized terms not otherwise defined herein shall have the respective meanings given to them under the Term Loan Agreement;
WHEREAS, the Company has requested that the Purchasers amend certain provisions of the Term Loan Agreement; and
WHEREAS, the parties hereto agree to amend the Term Loan Agreement on the terms and conditions set forth below;
NOW, THEREFORE, the parties hereto, in consideration of the mutual covenants and agreements herein contained and intending to be legally bound hereby, covenant and agree as follows:
| (a) | Amended Definition. The definition of Consolidated Net Worth set forth in Schedule B to the Term Loan Agreement shall be amended and restated as follows: |
| “Consolidated Net Worth shall mean as of any date of determination consolidated stockholders’ equity of the Company and its Subsidiaries as of such date determined and consolidated in accordance with GAAP, but specifically excluding the cumulative effect on stockholders’ equity arising from the Non-Cash Income Tax Expense.” |
| (b) | Additional Definition. Schedule B to the Term Loan Agreement shall be amended by inserting the following definition alphabetically into the list of defined terms: |
| ““Non-Cash Income Tax Expense” shall mean deferred income taxes which are tax expenses of the Company and the Obligors to any Person (including without limitation, any member of the Parent Group) other than payments due and payable to governmental tax agencies on behalf of the Company or the Obligors.” |
| (a) | Payments from the Company [Section 9.1(m)]. Subsection 9.1(m)(iv) of the Term Loan Agreement shall be amended and restated as follows: |
| “(iv) | to the payment of income tax expense for such period to the extent that such payments are payable to governmental tax agencies for or on behalf of the Company or the Obligors;" |
| (b) | Subordination of Management Fees; Payment of Management Fees [Section 9.1(r)]. Section 9.1(r) of the Term Loan Agreement shall be amended and restated as follows: |
| “(r) | Subordination of Management Fees; Payment of Management Fees. |
| The Company shall cause any fees or charges, of whatever nature, payable by the Obligors to any member of the Parent Group, including without limitation, the Non-Cash Income Tax Expense and all fees and charges in connection with the management of the operations of the Company, to be subordinated to the payment of the Notes, with the subordination in the case of payments to the Parent to be pursuant to the Management Fee Subordination Agreement and with the subordination in the case of payments to any other Affiliate of the Company to be subordinated to the Obligations, with the terms of such subordination to be satisfactory to the Required Combined Holders. The Obligors agree that the payment of any fees or charges to the Parent or any other member of the Parent Group, all of which are subordinated in accordance with the preceding sentence, may be made by the Obligors only if such payments are in accordance with the following: (i) prior to and after giving effect to the payment thereof, no Event of Default or Potential Default is in existence; (ii) the payments consist solely of the Management Fee, plus Third Party Services Payments; and (iii) such payments shall be otherwise permitted by and in accordance with the Management Fee Subordination Agreement; provided that, notwithstanding anything contained in this Subsection or the Management Fee Subordination Agreement to the contrary, in the event that the Company is permitted to make a dividend or distribution of the Company Share of Surplus Cash Flow in accordance with Section 10.5, the Company shall be permitted, in lieu of making such permitted distribution or dividend of the Company Share of Surplus Cash Flow, to apply such permitted dividend or distribution to reduce the payable arising from the Non-Cash Income Tax Expense." |
| (c) | Capital Expenditures and Leases [Section 10.16]. Section 10.16 of the Term Loan Agreement shall be amended and restated as follows: |
| "10.16 Capital Expenditures and Capitalized Leases. |
| Each of the Obligors shall not, and shall not permit any of its Subsidiaries to, make any payments exceeding the amounts indicated on Schedule 10.16 hereto in the aggregate in any fiscal year on account of the purchase or lease of any assets which are required to be capitalized on the financial statements of such Obligor in accordance with GAAP (“Capital Expenditures”), and all such purchases and leases shall be made under usual and customary terms and in the ordinary course of business, provided that, any amounts not expended by the Obligors for Capital Expenditures in any given fiscal year may be carried forward and used in a subsequent year. The amount of the Capital Expenditures permitted by Schedule 10.16 for each fiscal year shall be increased by the Operating Lease Availability (as defined in Section 10.17) for such fiscal year, provided, however, that the Operating Lease Availability if not used for Capital Expenditures in the same year shall not be carried forward to increase the amount of Capital Expenditures in subsequent years.” |
| (d) | Operating Leases [Section 10.17]. Section 10.17 of the Term Loan Agreement shall be amended and restated as follows: |
| "10.17 Operating Leases. |
| The Obligors shall not enter into or be obligated under operating leases having aggregate payments per year in excess of the amounts set forth on Schedule 10.17. In the event that the Obligors’ operating lease payments in any given fiscal year are less than the limitation set forth on Schedule 10.17, the difference between the limitation and the actual operating lease payments is referred to as “Operating Lease Availability.” If and to the extent that on any date during a given fiscal year the Obligors (or any one or more of them) shall utilize the Operating Lease Availability to make Capital Expenditures in addition to the amount thereof that would be permitted for such fiscal year pursuant to Section 10.16 in the absence of such Operating Lease Availability, then for such year the aggregate amount of payments under operating leases for which the Obligors may thereafter be or become obligated pursuant to the first sentence of this Section 10.17 in respect of such fiscal year shall be reduced pro tanto.” |
| (e) | Maximum Leverage Ratio [Section 10.19]. Section 10.19 of the Term Loan Agreement shall be amended and restated as follows: |
| "10.19 Maximum Leverage Ratio. |
| The Obligors shall not permit the ratio of Consolidated Total Indebtedness of the Company and its Subsidiaries to Consolidated EBITDA to exceed the ratio set forth below for the periods specified below, calculated as of the end of each fiscal quarter during each such period based upon the immediately preceding four fiscal quarters (provided, however, for periods ending on or before March 31, 2002, in lieu of using the preceding four fiscal quarters, the above computation shall be determined by annualizing the Consolidated EBITDA for the period from the Closing Date through the date of determination): |
| Period | Ratio |
| Closing Date through December 31, 2001 | 2.25 to 1.00 |
| January 1, 2002 through December 31, 2003 | 2.00 to 1.00 |
| January 1, 2004 through December 31, 2004 | 1.75 to 1.00 |
| January 1, 2005 through December 31, 2005 | 1.50 to 1.00 |
| January 1, 2006 and thereafter | 1.00 to 1.00 |
A. Warranties Under the Agreement. The representations and warranties of the Company contained in the Term Loan Agreement are true and correct on and as of the date hereof with the same force and effect as though made by the Company on such date, except to the extent that any such representation or warranty expressly relates solely to a previous date or is the subject of transactions permitted under the Term Loan Agreement. The Company is in compliance with all terms, conditions, provisions, and covenants contained in the Term Loan Agreement.
B. Power and Authority; Validity and Binding Effect; No Conflict. The Company and each other Obligor has full power to enter into, execute, deliver and carry out this Amendment and the CAA Amendment (as defined in Section 5 hereof), and such actions have been duly authorized by all necessary proceedings on its part. Each of this Amendment and the CAA Amendment and the Collateral Agency Agreement as amended thereby has been duly and validly executed and delivered by the Company and each other Obligor. Each of this Amendment, the Term Loan Agreement as amended hereby, the CAA Amendment and the Collateral Agency Agreement as amended thereby constitutes the legal, valid and binding obligation of Company and each other Obligor which is enforceable against Company and each other Obligor in accordance with its terms, except to the extent that enforceability thereof may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforceability of creditors' rights generally or by general equitable principles limiting the availability of specific performance or other equitable remedies. Neither the execution and delivery of this Amendment or the CAA Amendment, nor the consummation of the transactions herein and therein contemplated will conflict with, constitute a default under or result in any breach of (i) the terms and conditions of any organizational documents of Company or any other Obligor or (ii) any Law or any agreement or instrument or other obligation to which Company or any other Obligor is a party or by which it or any of the other Obligors is bound, or result in the creation or enforcement of any Lien upon any property of Company or any other Obligor other than as set forth in the Security Documents.
C. Consents and Approvals; No Event of Default. No consent, approval, exemption, order or authorization of any person or entity other than, as the case may be, the parties hereto or the parties to the CAA Amendment is required by any Law or any agreement in connection with the execution, delivery and carrying out of this Amendment and the CAA Amendment. No event has occurred and is continuing and no condition exists or will exist after giving effect to this Amendment which constitutes an Event of Default.
D. Authorized Officer. The individual executing this Amendment and the CAA Amendment on behalf of the Company and each other Obligor, is authorized to execute and deliver this Amendment or the CAA Amendment, as the case may be, on behalf of the Company and each other Obligor, and holds the office(s) with the Company and each other Obligor, as the case may be, set forth below his signature to this Amendment.
The Company, the Guarantors and the Purchasers acknowledge that this Amendment shall not be effective until each of the following conditions precedent has been satisfied (as determined by the Required Combined Holders in their sole discretion):
(a) Execution. The Company, the Guarantors and the Required Combined Holders shall have executed this Amendment and each of the Purchasers shall have received a counterpart original or a true and correct copy hereof;
(b) Amendment of Bank Credit Agreement. The Company, the Guarantors and the banks party to the Bank Credit Agreement shall have entered into an amendment to the Bank Credit Agreement providing for amendments to the terms thereof consistent with the amendments to the Term Loan Agreement provided for herein; such amendment shall be in form and substance reasonably acceptable to the Purchasers and shall be in full force and effect; and each Purchaser shall have received a true and correct copy thereof;
(c) Representations and Warranties. Each of the representations and warranties under Section 3 hereof are true and correct on the date hereof; and
(d) Authorization by Obligors. There shall be delivered to the Purchasers evidence of appropriate action taken by the Company and the other Obligors relative to approval of this Amendment.
Contemporaneously with the execution and delivery of this Amendment, a certain Amendment No. 1 to Collateral Agency Agreement, in the form attached to this Amendment as Exhibit "A" (the "CAA Amendment"), is being circulated for execution by the Obligors, all of the Purchasers and the Collateral Agent. In the event that it is duly approved, executed and delivered by all of the parties thereto, the CAA Amendment shall become effective.
This Amendment shall be incorporated into the Term Loan Agreement by this reference. All representations, warranties, Events of Default and covenants set forth herein shall be a part of the Term Loan Agreement as if originally contained therein.
The Company unconditionally agrees to pay and reimburse each of the Purchasers and save each of the Purchasers harmless against liability for the payment of all out-of-pocket costs, expenses and disbursements, including without limitation, reasonable fees and expenses of counsel incurred by any of the Purchasers in connection with the development, preparation, execution, administration, interpretation or performance of this Amendment and all other documents or instruments to be delivered or recorded in connection herewith.
Any provision of this Amendment that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall (to the full extent permitted by law) not invalidate or render unenforceable such provision in any other jurisdiction.
This Amendment sets forth the entire agreement and understanding of the parties with respect to the amendment to the Term Loan Agreement and the Schedule B thereto contemplated hereby and supersedes all prior understandings and agreements, whether written or oral, between the parties hereto relating to such amendments. No representation, promise, inducement or statement of intention has been made by any party which is not embodied in this Amendment, and no party shall be bound by or liable for any alleged representation, promise, inducement or statement of intention not set forth herein.
The Company reconfirms, restates, and ratifies the Term Loan Agreement, and all other documents executed in connection therewith except to the extent any such documents are expressly modified by this Amendment and Company confirms that all such documents have remained in full force and effect since the date of their execution.
This Amendment shall be deemed to be a contract under the laws of the State of New York and for all purposes shall be governed by and construed and enforced in accordance with the internal laws of the State of New York.
This Amendment may be signed in any number of counterparts each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto, by their officers thereunto duly authorized, have executed this Second Amendment to Term Loan Agreement as of the day and year first above written with the intention that it constitute a sealed instrument.
| WESTMORELAND MINING LLC | |
| By: /s/ W. Michael Lepchitz | |
| Name: W. Michael Lepchitz | |
| Title: Vice President, General Counsel and Assistant Secretary |
| WESTERN ENERGY COMPANY, an | |
| Obligor and Guarantor | |
| By: /s/ W. Michael Lepchitz | |
| Name: W. Michael Lepchitz | |
| Title: Vice President, General Counsel and Assistant Secretary |
| NORTHWESTERN RESOURCES CO., | |
| an Obligor and Guarantor | |
| By: /s/ W. Michael Lepchitz | |
| Name: W. Michael Lepchitz | |
| Title: Vice President, General Counsel and Assistant Secretary |
| DAKOTA WESTMORELAND CORPORATION, an | |
| Obligor and Guarantor | |
| By: /s/ W. Michael Lepchitz | |
| Name: W. Michael Lepchitz | |
| Title: Vice President, General Counsel and Assistant Secretary |
| WCCO-KRC ACQUISITION CORP., | |
| an Obligor and Guarantor | |
| By: /s/ W. Michael Lepchitz | |
| Name: W. Michael Lepchitz | |
| Title: Vice President, General Counsel and Assistant Secretary |
| NM ROTHSCHILD & SONS LIMITED | TEACHERS INSURANCE AND ANNUITY ASSOCIATION OF AMERICA |
| By: /s/ C. Coleman | By: /s/ Estelle Simsolo |
| Name: C. Coleman | Name: Estelle Simsolo |
| Title: Director | Title: Director - Private Placements |
| NATIONAL CITY BANK | PACIFIC LIFE INSURANCE COMPANY |
| By: /s/ Wilmer J. Jacobs | By: /s/ Violet Aosterberg |
| Name: Wilmer J. Jacobs | Name: Violet Aosterberg |
| Title: Vice president | Title: Asst. Vice President |
| By: /s/ Audrey L. Milfs | |
| Name: Audrey L. Milfs | |
| Title: Corporate Secretary |
| FIRSTAR BANK, N.A. | AMERICAN GENERAL INTERNATIONAL |
| INVESTMENTS, INC. | |
| By: /s/ Eric Hartman | |
| Name: Eric Hartman | AMERICAN GENERAL ANNUITY |
| Title: Vice President | INSURANCE COMPANY |
| By: /s/ C. Scott Inglis | |
| Name: C. Scott Inglis | |
| Title: Investment Officer |
| NATIONWIDE INDEMNITY COMPANY | THE TRAVELERS INSURANCE COMPANY |
| NATIONWIDE MUTUAL FIRE INSURANCE COMPANY | |
| By: /s/ Robert M. Mills | |
| NATIONWIDE MUTUAL INSURANCE COMPANY | Name: Robert M. Mills |
| Title: Investment Officer | |
| By: /s/ Mark W. Poeppelman | |
| Name: Mark W. Poeppelman | |
| Title: Associate Vice President |
| METROPOLITAN LIFE INSURANCE COMPANY | COLUMBUS LOAN FUNDING LTD. |
| By: Travelers Asset Management International Company LLC | |
| By: /s/ Erik V. Savi | By: /s/ Robert M. Mills |
| Name: Erik V. Savi | Name: Robert M. Mills |
| Title: Director | Title: Investment Officer |
| TRAVELERS CORPORATE LOAN FUND INC. | |
| By: Travelers Asset Management International Company LLC | |
| By: /s/ Robert M. Mills | |
| Name: Robert M. Mills | |
| Title: Investment Officer |
Exhibit 10(ff)
Westmoreland Coal Company (the “Company”), a corporation organized under the laws of the State of Delaware, by resolution of the Board of Directors of the Company at a regularly scheduled meeting duly held on June 9, 2000, adopted this 2000 Performance Unit Plan (the “Plan”).
Section 1.1 The purpose of the Plan is to provide a financial incentive for key executives to encourage and reward desired performance on key financial measures that will further the growth, development and financial success of the Company, to align the interests of the Company’s key executives and shareholders and to enhance the Company’s ability to maintain a competitive position in attracting and retaining qualified key personnel who contribute, and are expected to contribute, materially to the success of the Company.
Section 2.1 Whenever the following terms are used in this Plan, they shall have the meaning specified below unless the context clearly indicates to the contrary. The masculine pronoun shall include the feminine and neuter and the singular shall include the plural, where the context so indicates.
“Affiliate” shall mean (i) any entity that, directly or indirectly, is controlled by the Company, (ii) any entity in which the Company has a significant equity interest , (iii) an affiliate of the Company, as defined in Rule 12b-2 promulgated under Section 12 of the Exchange Act, and (iv) any entity in which the Company has at least twenty percent (20%) of the combined voting power of the entity’s outstanding voting securities, in each case as designated by the Board as being a participating employer in the Plan.
“Assigned Value” shall mean the value assigned by the Committee, in its sole and absolute discretion, to a Performance Unit which is valued other than by reference to the Fair Market Value of the Common Stock, for the attainment of each of Threshold Performance, Target Performance and Maximum Performance in any Performance Period.
“Award” shall mean a Performance Unit granted under the Plan to a Participant by the Committee pursuant to such terms, conditions, restrictions and/or limitations, if any, as the Committee may establish that are not inconsistent with the provisions of this Plan.
“Award Agreement” shall mean any written agreement, contract, or other instrument or document evidencing any Award, which may, but need not, be executed or acknowledged by a Participant.
“Base Value” shall mean the average of the Daily Price of the Common Stock for the twenty (20) consecutive trading days immediately preceding the commencement of the Performance Period on which one or more trades occurs.
“Board” shall mean the Board of Directors of the Company.
“Cause” shall mean, unless otherwise defined in the applicable Award Agreement, (i) the engaging by the Participant in willful misconduct that is injurious to the Company or its Subsidiaries or Affiliates, or (ii) the embezzlement or misappropriation of funds or property of the Company or its Subsidiaries or Affiliates by the Participant, or the final conviction of the Participant of a felony or the entrance of a plea of guilty or nolo contendere by the Participant to a felony. For purposes of this paragraph, no act, or failure to act, on the Participant’s part shall be considered “willful” unless done, or omitted to be done, by the Participant not in good faith and without reasonable belief that the Participant’s action or omission was in the best interest of the Company. Any determination of Cause shall be made by the Committee in its sole discretion and shall be final and binding on a Participant.
“Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.
“Committee” shall mean a committee of the Board composed of not less than two Non-Employee Directors all of whom shall be “nonemployee directors” with respect to the Plan within the meaning of Section 16 and all of whom may be “outside directors” for purposes of Section 162(m) of the Code. The members of the Committee shall be appointed by and serve at the pleasure of the Board. In the absence of a resolution of the Board determining otherwise, “Committee” shall mean the Compensation and Benefits Committee of the Board.
“Common Stock” shall mean the common stock of the Company, par value $2.50 per share, and any equity security of the Company issued or authorized to be issued in the future, but excluding any preferred stock and any warrants, options or other rights to purchase common Stock.
“Common Stock Appreciation” shall mean the difference between the Fair Market Value of the Common Stock and the Base Value of a Performance Unit at the expiration of the Performance Period for that Performance Unit.
“Company#148; shall mean Westmoreland Coal Company or any successor thereto.
“Covered Officer” shall mean at any date (i) any individual who, with respect to the previous tax year of the Company, was a “covered employee” of the company within the meaning of Code Section 162(m), excluding any such individual whom the Committee, in its discretion, reasonably expects not to be a “covered employee” with respect to the current tax year of the Company and (ii) any individual who was not a “covered employee” under Code Section 162(m) for the previous tax year of the Company, but whom the Committee, in its discretion, reasonably expects to be a “covered employee” with respect to the current tax year of the Company or with respect to the tax year of the Company in which any applicable Award will be paid.
“Daily Price” shall mean the average of the highest and lowest sale price occurring during any given trading day on which the Common Stock of the Company is traded.
“Disability” shall mean the disability of a Participant under the terms of the then effective long term disability plan of the Company.
“Employee” shall mean any employee (as defined in accordance with Section 3401(c) of the Code) of the Company or an Affiliate or Subsidiary, whether such employee is so employed at the time this Plan is adopted or becomes so employed subsequent to the adoption of this Plan.
“Employer” shall mean the company or an Affiliate or Subsidiary, whichever at the time employs the Employee.
“Fair Market Value” shall mean the average of the Daily Price of the Common Stock for the last twenty (20) consecutive trading days of a Performance Period on which one or more trades of Common Stock occurs.
“Maximum Award” shall mean the Award payable under the Plan for Maximum Performance in any Performance Period.
“Maximum Performance” shall mean the Performance Goals established for any Performance Period, the attainment of which is necessary for the payment of the Maximum Award of a Target Award with an Assigned Value for that Performance Period.
“Non-Employee Director” shall mean a member of the Board who is not an Employee or officer of the Company or any of its Subsidiaries or Affiliates.
“Participant” shall mean an Employee who is selected to participate in the Plan.
“Performance Goals” shall mean performance goals or objectives established by the Committee for each Performance Period pursuant to this Plan, the attainment of which is necessary for the payment of an Award to a Participant at the completion of the Performance Period. Performance Goals may be described in terms of Company-wide objectives or objectives that are related to the performance of the individual Participant or the Affiliate, Subsidiary, or division, department or function within the Company, Affiliate or Subsidiary in which the Participant is employed. Any Performance Goals applicable to the Awards intended to qualify as “performance-based compensation” under Section 162(m) of the Code shall be limited to specified levels of, or increases in, the Company’s, Affiliate’s or Subsidiary’s market share, sales, costs, return on equity, earnings per share, earnings before interest and taxes, earnings before interest, taxes, depreciation and amortization, earnings growth, return on capital, return on assets, total shareholder return and/or increase in the Fair Market Value of the Common Stock , measurements of safety performance or any combination thereof. Each Performance Goal may be expressed on an absolute and/or relative basis, may be based on or otherwise employ comparisons based on internal targets, the past performance of the Company and/or the past or current performance of other companies, and in the case of earnings-based measures, may use or employ comparisons relating to capital, shareholders’ equity and/or Shares outstanding, or to assets or net assets. Except in the case of Performance Goals related to an Award intended to qualify under Section 162(m) of the Code, if the Committee determines that a change in the business, operations, corporate structure or capital structure of the Company, or the manner in which it conducts its business, or other events or circumstances render the Performance Goals unsuitable, the Committee, after the commencement of a Performance Period, may modify such Performance Objectives, in whole or in part, as the Committee deems appropriate and equitable.
“Performance Period” shall mean the period of time specified in an Award Agreement to be used in measuring the degree to which the Performance Goals relating to Performance Units granted under that Award Agreement have been met; provided, however, that for purposes of the initial Performance Period of the Plan, Performance Period shall mean the period commencing on July 1, 2000 and ending June 30, 2003.
“Performance Unit” shall mean a right that is (i) denominated in cash or Common Stock, (ii) valued, as determined by the Committee, either in accordance with the achievement of such Performance Goals during such Performance Periods as the Committee shall establish or with reference to the Fair Market Value of the Common Stock, and (iii) payable at such time and in such form as the Committee shall determine in accordance with the terms and conditions of Article VI hereof.
“Plan” shall mean the 2000 Performance Unit Plan, as amended from time to time.
“Retirement” shall mean the Termination of Employment of a Participant from the employ or service of the Company or any of its Affiliates or Subsidiaries in accordance with the terms of the applicable Company retirement plan, or if a Participant is not covered by any such plan, the Termination of Employment of a Participant on or after the earliest to occur of the following:
(a) the attainment by the Participant of the age of 65 or the achievement of five years of employment or service with the Company, whichever occurs later; or
(b) the attainment by the Participant of the age of 62 and twenty years of employment or service with the Company.
“Section 16” shall mean Section 16 of the Exchange Act and the rules promulgated thereunder and any successor provision thereto as in effect from time to time.
“Section 162(m)” shall mean Section 162(m) of the Code and the rules promulgated thereunder or any successor provision thereto as in effect from time to time.
“Subsidiary” shall mean any corporation in an unbroken chain of corporations beginning with the Company if each of the corporations other than the last corporation in the unbroken chain then owns stock possessing 50% or more of the total combined voting power of all classes of stock in one of the other corporations in such chain.
“Target Award” shall mean the Award payable under the Plan for Target Performance in any Performance Period.
“Target Performance” shall mean the Performance Goals established for any Performance Period, the attainment of which is necessary for the payment of a Target Award with an Assigned Value for that Performance Period.
“Termination of Employment” shall mean the time when the employee-employer relationship between a Participant and the Employer is terminated for any reason, with or without Cause, including, but not by way of limitation, a termination by resignation, discharge, death, Disability, Early Retirement or Retirement, but excluding (i) terminations where there is a simultaneous reemployment or continuing employment of a Participant by the Employer; (ii) at the discretion of the Committee, terminations which result in a temporary severance of the employee-employer relationship; and (iii) at the discretion of the Committee, terminations which are followed by the simultaneous establishment of a consulting relationship by the Employer with the former Employee. Notwithstanding the foregoing, the Committee, in its absolute discretion, shall determine the effect of all matters and questions relating to Termination of Employment, including, but not by way of limitation, the question of whether a Termination of Employment resulted from a discharge for good cause, and all questions of whether particular leaves of absence constitute Terminations of Employment. However, notwithstanding any provision of this Plan, the Employer has an absolute and unrestricted right to terminate an Employee’s employment at any time for any reason whatsoever, with or without Cause, except to the extent expressly provided otherwise in writing.
“Threshold Performance” shall mean the level of attainment of a Performance Goal necessary for the payment of any Award with an Assigned Value upon the completion of any Performance Period for that Award.
Section 3.1 Subject to the authority and powers of the Board in relation to the Plan as hereinafter provided, the Plan shall be administered by the Committee; provided, however, that the Committee may not exercise any authority otherwise granted to it hereunder if such action would have the effect of increasing the amount of any Award payable hereunder to any Covered Officer. All determinations by the Committee shall be made by the affirmative vote of a majority of its members, but any determination reduced to writing and signed by a majority of the members of the Committee shall be as fully effective as if it had been made by a majority vote at a meeting duly called and held. All decisions by the Committee pursuant to the provisions of the Plan and all orders or resolutions of the Board pursuant thereto shall be final, conclusive and binding on all persons, including but not limited to the Participants, the Company and its Affiliates and Subsidiaries and their respective equity holders, heirs, successors and personal representatives.
Section 3.2 The Committee, on behalf of the Participants, shall have full authority to interpret and enforce this Plan in accordance with its terms and shall have all powers necessary for the accomplishment of that purpose, including, but not by way of limitation, the following powers:
(a) To select the Participants;
(b) To make Awards to Participants with respect to each Performance Period, subject to the terms and conditions set forth in the Plan.;
(c) To establish the terms and conditions under which any Award granted hereunder may be earned and paid, subject to the terms and conditions set forth in the Plan, including, without limitation, the Performance Period, Assigned Value (if any) and vesting schedule of each Award;
(c) To establish the terms and conditions of any Award Agreement evidencing an Award granted hereunder, subject to the terms and conditions set forth in the Plan;
(d) To interpret, construe, approve and adjust all terms, provisions, conditions and limitations of this Plan;
(e) To decide any questions arising as to the interpretation or application of any provision of the Plan;
(f) To prescribe forms and procedures to be followed by Employees for participation in the Plan, or for other occurrences in the administration of the Plan;
(g) To adopt such rules and regulations for the administration of the Plan not inconsistent with the terms of the Plan as it may deem appropriate in its sole and absolute discretion; and
(h) To waive any conditions or rights under, amend any terms of, or alter, suspend, discontinue, cancel or terminate an Award theretofore granted, prospectively or retroactively; provided, however, that any such waiver, amendment, alteration, suspension, discontinuance or termination that would adversely affect the rights of any Participant or holder or beneficiary of any vested Award theretofore granted shall not to that extent be effective without the consent of the affected Participant, holder or beneficiary.
Section 3.3 No member of the Committee shall be liable for anything done or omitted to be done by him or by any member of the Committee in connection with the performance of any duties under this Plan, except for his own willful misconduct or as expressly provided by statute.
Section 3.4 All actions which may be taken by the Committee hereunder may also be taken by the Board except for actions with regard to any Award intended to qualify under Section 162(m) of the Code which would cause such Award not to qualify under said section.
Section 4.1 Subject to the provisions of the Plan, the Committee may from time to time select any Employee who is a salaried employee of the Company or of an Affiliate or Subsidiary to be granted Awards under the Plan. Eligible Employees hired by the Company after the commencement of a Performance Period may be granted Performance Units hereunder for the Performance Period which commenced in the twelve (12) month period preceding the date on which the Employee became employed by the Company. No Employee shall at any time have the right (a) to receive an Award upon the expiration of a Performance Period which commenced prior to the twelve (12) month period preceding the date on which they became an employee (b) to be selected as a Participant in the Plan for any Performance Period, (c) if selected as a Participant in the Plan, to be entitled to an Award, or (d) if selected as a Participant in one Performance Period, to be selected as a Participant in any subsequent Performance Period.
Section 5.1 For Performance Units measured by an Assigned Value, the Committee shall establish Performance Goals for such Performance Units, including the Threshold Performance, Target Performance and Maximum Performance, within 90 days of the commencement of a Performance Period, and an Award for that Performance Period shall be paid or otherwise deliverable upon the completion of the Performance Period solely on account of the attainment of such Performance Goals. The degree to which the Company achieves such Performance Goals shall serve as the basis for the Committee’s determination of the Award payable to a Participant upon the completion of a Performance Period. Awards will be prorated for Company performance results occurring between stated performance levels. For Performance Units measured by an Assigned Value, Company performance below the Threshold Performance in any Performance Period will result in the forfeiture of such Performance Units awarded for that Performance Period, without any Award payment.
Section 5.2 Awards payable at the expiration of a Performance Period shall be the product of (a) the number of Performance Units in the Award and (b) the Common Stock Appreciation, if the Performance Units are measured by the Fair Market Value of the Common Stock, or the appropriate Assigned Value based upon Company performance, if the Performance Units are measured by Assigned Value.
Section 5.3 In the case of all Awards measured by Assigned Value, no Participant may receive in any one fiscal year an Award under the Plan of an amount greater than $2.5 million. In the case of all Awards measured by Common Stock Appreciation, no Participant may receive in any one fiscal year an Award under the Plan of a number of Performance Units greater than 500,000.
Section 5.4 The Company shall maintain a bookkeeping account for each Participant recording the current value of Performance Units awarded hereunder. Each Participant shall receive an annual statement reflecting the number of Performance Units awarded to that Participant hereunder, the number of Performance Units which have vested as of the date of the statement, and the Base Value or Assigned Value, as appropriate, assigned to each Performance Unit.
Section 5.5 At the Committee’s discretion, the effect of one-time charges and extraordinary, nonrecurring events unrelated to the performance of a Participant such as asset write-downs, litigation judgments or settlements, changes in tax laws, accounting principles or other laws or provisions affecting reported results, accruals for reorganization or restructuring, and any other extraordinary non-recurring items, acquisitions or divestitures and any foreign exchange gains or losses may be disregarded for purposes of determining the attainment of Performance Goals.
Section 6.1 Upon completion of each Performance Period, the Committee shall review Company performance results as compared to the established Performance Goals for that Performance Period, and shall certify (either by written consent or as evidenced by the minutes of a meeting) the specified Performance Goals achieved for the Performance Period (if any) and direct which Award payments are payable under the Plan, if any.
Section 6.2 Vested Performance Units may be paid in a lump sum or in installments following the close of the Performance Period or, in accordance with the procedures established by the Committee, on a deferred basis. The Committee shall have sole and absolute authority and discretion to determine the time and manner in which Awards, if any, shall be paid under this Plan; provided, however, that unless the time and manner of payment and the Committee’s discretion with regard thereto are otherwise set forth in the Award Agreement, payment shall be in a single payment, whether cash or Company Common Stock, and shall be made as reasonably promptly following the end of a Performance Period. The following provisions may apply to any Performance Unit:
(a) Form of Payment: Payment of vested Awards may be made in cash, or at the option of the Committee, in whole or in part in Company Common Stock, and may be subject to such restrictions as the Committee shall determine.
(b) Date of Payment: Payment of vested Awards shall be made as soon as practicable (as determined by the Committee) following the close of the Performance Period (the “Payment Date”), except as otherwise provided in Section 6.2(d) below.
(c) Vesting: Except as provided in subsections (d) and (e) below, Participants shall vest in Performance Units as set forth in the Award Agreement.
(d) Retirement, Death, Disability or Involuntary Termination without Cause: In the event of a Participant’s Termination of Employment by the Company, its Affiliate or Subsidiary prior to the close of a Performance Period due to Retirement, death, Disability or Involuntary Termination without Cause, a pro rata portion of the Participant’s outstanding Performance Units shall vest based on the number of full months which have elapsed in each Performance Period as of the date of such Termination of Employment. Payments under this Section 6.2(d) shall be made as soon as practicable following the date of the Participant’s Termination of Employment, but no later than 30 days after such date, unless the amount of such payments cannot be determined under the terms of the Award until the close of the Performance Period, in which case, payment shall me made reasonably promptly after the close of the Performance Period.
(e) Voluntary Termination or Involuntary Termination with Cause: In the event of a Participant’s Termination of Employment for Cause prior to the close of a Performance Period by the Company, its Affiliate or Subsidiary, or by the Participant for reasons other than Retirement, death or Disability, then the Participant shall forfeit all unvested Performance Units. Vested Performance Units shall be paid at their full value upon the close of each Performance Period in accordance with this Section.
Section 6.3 The Committee shall not have discretion or authority to increase the amount payable hereunder pursuant to an Award in a manner inconsistent with the requirements for qualified performance-based compensation under Code Section 162(m).
Section 7.1 The Board may at any time terminate or suspend the Plan, in whole or in part, and from time to time, subject to the stockholder approval requirements of Section 162(m), amend or modify the Plan, provided that, except as otherwise provided in the Plan, no such amendment, modification, suspension or termination shall adversely affect the rights of any Participant under any vested Award previously earned but not yet paid to such Participant without the consent of such Participant. In the event of such termination, in whole or in part, of the Plan, the Committee may, subject to the foregoing, direct the payment to Participants of any amounts specified in Article V and theretofore not paid out, prior to the respective dates upon which payments would otherwise be made hereunder to such Participants, and in a lump sum or installments as the Committee shall prescribe with respect to each such Participant. Notwithstanding the foregoing, any such payment to a Covered Officer must be discounted to reflect the present value of such payment using a rate equal to the average yield of a 5-year treasury security for the month prior to the month in which the payment is made. The Board may at any time and from time to time delegate to the Committee any or all of its authority under this Article VII.
Section 8.1 The existence of outstanding Awards shall not affect in any manner the right or power of the Company or its shareholders to make or authorize any or all adjustments, recapitalizations, reorganizations or other changes in the capital stock of the Company or its business or any merger or consolidation of the Company, or any issue of bonds, debentures, preferred or prior preference stock (whether or not such issue is prior to, on a parity with or junior to the common stock of the Company) or the dissolution or liquidation of the Company, or any sale or transfer of all or any part of its assets or business, or any other corporate act or proceeding of any kind, whether or not of a character similar to that of the acts or proceedings enumerated above.
Section 8.2 In the event of any consolidation or merger of the Company with another corporation or entity or the adoption by the Company of a plan of exchange affecting the common stock of the company or any distribution to holders of Company common stock of securities or property (other than normal cash dividends or dividends payable in Company common stock), or a capital reorganization or reclassification or other transaction involving a significant increase or decrease in the capitalization of the Company, the Committee shall make such adjustment or other provision as it may deem equitable, including adjustments to the Base Value assigned to outstanding Awards, to give proper effect to such event.
Section 9.1 Unless otherwise determined by the Committee and provided in the Award Agreement, no Award or any other benefit under this Plan shall be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered by a Participant, except by will or the laws of descent and distribution. Any attempted assignment of an Award or any other benefit under this Plan in violation of this Section 9.1 shall be null and void. A Participant may designate in writing a beneficiary (including the trustee or trustees of a trust) who shall upon the death of such Participant be entitled to receive all amounts payable under the provisions of Section 6.2(c) to such Participant. A Participant may rescind or change any such designation at any time. No transfer of an Award by will or by laws of descent and distribution shall be effective to bind the Company unless the Company shall be furnished with written notice thereof and an authenticated copy of the will and/or such other evidence as the Committee may deem necessary or appropriate to establish the validity of the transfer.
Section 9.2 The Company shall have the right to withhold applicable taxes from any Award payment and to take such other action as may be necessary in the opinion of the Company to satisfy all obligations for withholding of such taxes.
Section 9.3 No Employee or other person shall have any claim or right to be granted an Award under this Plan, and there is no obligation for uniformity of treatment of Participant or holders or beneficiaries of Awards. Neither the Plan nor any action taken thereunder shall be construed as giving an Employee any right to be retained in the employ of the Company or an Employer and the right of the Company or Employer to dismiss or discharge any such Participant is specifically reserved. The benefits provided for Participants under the Plan shall be in addition to, and shall in no way preclude, other forms of compensation to or in respect of such Participants. No Participant shall have any lien on any assets of the Company or an Employer by reason of any Award made under this Plan.
Section 9.4 At the discretion of the Committee, the Award payments under this Plan may be considered compensation under any deferred compensation plan adopted by the Company after the effective date of this Plan.
Section 9.5 Each Award hereunder shall be evidenced by an Award Agreement that shall be delivered to the Participant and may specify the terms and conditions of the Award and any rules applicable thereto. In the event of a conflict between the terms of the Plan and any Award Agreement, the terms of the Plan shall prevail.
Section 9.6 This Plan and all determinations made and actions taken pursuant thereto, shall be governed by and construed in accordance with, the laws of the State of Colorado, without giving effect to conflicts of laws principles.
Section 9.7 If any provision of the Plan or any Award is, or becomes, or is deemed to be invalid, illegal, or unenforceable in any jurisdiction or as to any Participant or Award, or would disqualify the Plan or any Award under any law deemed applicable by the Committee, such provision shall be construed or deemed amended to conform to the applicable laws, or if it cannot be construed or deemed amended without, in the determination of the Committee, materially altering the intent of the Plan or the Award, such provision shall be stricken as to such jurisdiction, Participant or Award and the remainder of the Plan and any such Award shall remain in full force and effect.
Section 9.8 Neither the Plan nor any Award shall create or be construed to create a trust or separate fund of any kind or a fiduciary relationship between the Company or any subsidiary or affiliate of the Company and a Participant or any other person. To the extent that any person acquires a right to receive payments from the Company or any subsidiary or affiliate of the Company pursuant to an Award, such right shall be no greater than the right of any unsecured general creditor of the Company or any subsidiary or affiliate.
Section 9.9 This Plan shall be binding upon and inure to the benefit of the Company, its successor and assigns and each Participant and his legal representatives.
Section 10.1 The Plan shall be effective as of June 1, 2000 and shall remain effective until May 31, 2010.
Section 10.2 No new Awards shall be granted under the Plan after the termination of the Plan. Unless otherwise expressly provided in the Plan or in an applicable Award Agreement, any Award granted hereunder may, and the authority of the Board or Committee to amend, alter, adjust, suspend, discontinue, or terminate any such Award or to waive any conditions or rights under any such Award shall, continue after the termination of the Plan for so long as Awards remain outstanding under the Plan.
IN WITNESS WHEREOF, the Company has executed this Plan this 19th day of April, 2001, but effective as of June 1, 2000.
| By /s/ Paul W. Durham | |
| Name: Paul W. Durham | |
| Title: Vice President - Human Resources |
ATTEST:
Charles Finkenstadt
__________