The Company makes monthly premium payments to the UMWA Combined Benefit Fund (“CBF”), a multiemployer health plan neither controlled nor administered by the Company. The current amount of the monthly premiums is less than $400,000 and is recalculated annually each October. An action by the Social Security Administration in June 2003 could increase the Company’s premium by an estimated 10%. There is also a possibility that the CBF could seek to impose the increase retroactively to all premiums paid since 1995. The Company has joined other coal companies with CBF obligations in a complaint filed in the U.S. District Court for the Northern District of Alabama seeking injunctive and declaratory relief regarding the potential increase in CBF premiums.
The Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”) authorized the Trustees of the 1992 UMWA Benefit Plan to implement security provisions for the payment of future benefits. The Trustees set the level of security for each company at an amount equal to three years’ benefits. The bond amount and the amount to be secured are reviewed and adjusted on an annual basis. The amount of the cash collateral required by the Company’s bonding agent is periodically reviewed and subject to change. The Company has been notified that an additional $1.9 million bond is required with total additional cash collateral of $1.9 million. On April 23, 2003, the Company posted the bond and the cash collateral will be fully paid by the third quarter of 2003.
The Company is subject to certain financial ratio tests specified in a Contingent Promissory Note (the “Note”) executed in conjunction with the Master Agreement with the UMWA Health and Retirement Funds and others, which facilitated the Company’s discharge from Chapter 11 Bankruptcy in 1998. The Note terminates on January 1, 2005. The Company is in compliance as of June 30, 2003.
On August 11, 2003, the Company reached an agreement with the Funds, whereby, in exchange for a one-time payment of $225,000, the financial ratio tests, the Note, and security agreement were eliminated. The Company will continue to be obligated to meet its Coal Act obligations and certain other non-financial covenants to the Funds and other parties through the expiration of the Master Agreement on January 1, 2005.
A Medicare prescription drug benefit that covers Medicare-eligible beneficiaries covered by the Coal Act could reduce one of the Company’s largest costs. Of the over $20.0 million per year the Company paid for retirees’ health care costs in 2002, more than 50% was for prescription drugs. Creation of a prescription drug benefit continues to be debated on the national level, and both the House and Senate have passed a version of a prescription drug bill that provides an incentive for employers to maintain medical coverage that contain prescription drug benefits. A conference committee will attempt to resolve the differences in the two bills. At this time the exact form of final legislation is uncertain, however, there is momentum to put a Bill on the President’s desk for signature sometime in the fall and assuming that the employer incentive remains in any final bill, the Company may experience a 10-20% overall savings in medical costs beginning in 2006 compared to its potential costs in the absence of such litigation. There is no assurance at this time what, if any, new proposal will be enacted into law.
The Company’s acquisitions in 2001 greatly increased revenues and operating cash flow and returned the Company to general profitability, but the cash used and financing arranged to make those acquisitions could also create short-term liquidity issues during the term of the financing which must be managed. The acquisition financing facility restricts distributions to the Company to 75% of WML’s “excess cash flow”, as defined in the financing agreements, until the debt is paid off.
The final purchase price for the acquisition of Montana Power Company’s coal business is subject to adjustment. As discussed in Item 3 - Legal Proceedings of the Company’s 2002 Annual Report on Form 10-K, the Company and Montana Power Company were not able to agree on either the amount of the purchase price adjustment or the methodology to calculate the adjustment within the time frame provided for under the Stock Purchase Agreement. Due to the ongoing litigation surrounding this issue and the bankruptcy filing on June 18, 2003 by Touch America Holdings, Inc., Montana Power Company’s successor, and its subsidiary Entech, the ultimate outcome can not be predicted. If the purchase price is reduced, the Company and WML may be required to use the proceeds received from Entech and Montana Power Company to pay down the acquisition financing facility. In the unlikely event an additional purchase price payment is required it would likely be funded by the use of WML’s revolving credit facility.
The Company does not anticipate that its coal and power production will diminish materially as a result of the continued 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. (A baseload plant is used first to meet demand because of its location and lower cost of producing electricity.) In addition, most of the Company’s production is sold under long-term contracts, which help insulate the Company from reductions in tons sold. However, contract price reopeners, contract extensions, expirations and terminations, and market competition could affect future price and production levels. During the second quarter of 2003, the Company entered into an amended coal supply agreement to provide an additional 1.5 to 2.5 million tons annually for five years to an existing customer at the Rosebud Mine.
The Company’s largest customers also include companies, or their subsidiaries, who have suffered downgraded credit ratings which could affect the customers’ credit worthiness. The Company invoices its customers for coal sales either semi-monthly or monthly and limits its credit exposure by closely monitoring its accounts receivable. In certain cases, common customers of a generating plant are jointly liable for payment to the Company.
The Company has certain coal sales contract contingencies which may impact future income, sales, prices received and cost of operations. These include, but are not limited to:
| • | NWR’s dispute with TGN, the owner/operator of the Limestone Electric Generating Station discussed in Note 7 to the Company’s Consolidated Financial Statements. |
| • | Arbitration of a price adjustment which the Company believes it is due under the Company’s Coal Supply Agreement with the Colstrip Units 1 and 2 owners which calls for the price to be reopened on the contract’s thirtieth anniversary, which was July 30, 2001. |
| • | The Company’s claim under the Coyote Station Coal Agreement to recover an annual minimum net income specified in the contract. |
In addition, there are other issues regarding royalty payments, state income tax audits, property taxes and reclamation obligations and related bonding requirements, which may affect the Company, but their impact is not known at this time.
As discussed in Note 2 to the Consolidated Financial Statements, the Company sold its interest in DTA for $10.5 million and recorded a gain of $4.5 million effective June 30, 2003. At closing, the purchaser assumed all of the Company’s DTA partnership obligations. As a result, the Company will no longer incur DTA-related operating losses, which were $1.0 million during the first six months of 2003 and $2.1 million, excluding an impairment expense of $3.7 million, in the year ended December 31, 2002.
The Company is mindful of the need to manage costs with respect to the timing of receipts, and variations in distributions or expected performance. For instance, outages at customer’s power plants reduce the Company’s coal revenues during those periods. And the Jewett Mine’s transition to market-based pricing can be expected to produce more variability in revenues than compared to the cost-plus-fees mechanism previously in place. Therefore, the Company continues to take steps to conserve cash wherever possible. The Company has also taken steps to increase the availability of working capital. In January 2003, the Company amended its revolving line of credit for general corporate purposes, increasing it from $7.0 million to $10.0 million. The Company had borrowed $1.5 million as of June 30, 2003, all of which was repaid in early July 2003.
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The Company also aims to increase its sources of profitability and cash flow. Given possible future 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 ongoing and future business needs may also affect its liquidity. The Company’s growth plan is focused on acquiring profitable businesses and developing projects in the energy sector which complement the Company’s existing core operations and where America’s dual goals of low cost power and a clean environment can be effectively addressed. The Company has sought to do this in niche markets that minimize exposure to competition, maximize stability of long-term cash flows and provide opportunities for synergistic operation of existing assets and new opportunities. The Company seeks opportunities on an ongoing basis to make additional strategic acquisitions, to expand existing businesses and to enter related businesses. The Company considers potential acquisition opportunities as they are identified, but cannot be assured that it will be able to consummate any such acquisition. The Company anticipates that it would finance acquisitions by using its existing capital resources, by borrowing under existing bank credit facilities, by issuing equity securities or by incurring additional indebtedness. The Company may not have sufficient available capital resources or access to additional capital to execute potential acquisitions, and the Company may not find suitable acquisition candidates at acceptable prices. There is no assurance that the Company’s current or future acquisition efforts will be successful or that any such acquisition will be completed on terms that are favorable to the Company. Acquisitions involve risks, including difficulties in integrating acquired operations, diversions of management resources, debt incurred in financing such acquisitions and unanticipated problems and liabilities. Any of these risks could have a material adverse effect upon the Company’s business, financial condition and results of operations.
A key to the Company’s strategy is the availability of approximately $174.2 million in NOLs at the end of 2002. The availability of these NOLs 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). However, the availability of these tax benefits could be severely restricted if a 50% change of ownership by value would occur over any three-year period.
Sources of potential additional future liquidity may also include resolution of the NWR dispute with TGN and the price reopener with the owners of Colstrip Units 1 and 2 discussed above, the sale of non-strategic assets, and increased cash flow from existing operations.
The Company has three separate defined benefit pension plans for full-time employees after combining three of five prior plans effective for the 2002 plan year. The future funding of these plans could have a long-term impact on liquidity determined primarily by investment returns on the plans’ assets. During 2002, one of the plans required a contribution of $78,000 and increasing contributions could be required in future years unless investment returns materially improve. Based upon updated actuarial projections, contributions of $1.5 million are expected to be payable in 2004. The required minimum annual cash contributions are expected to grow unless investment returns improve or funding requirements change.
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In July 2000, the Company adopted a long-term incentive compensation plan to promote the successful implementation of its strategic plan for growth and link the compensation of its key managers to the appreciation in the price of the Company’s common stock. Because the Company had a limited number of qualified stock options available at that time, the Board of Directors adopted a performance unit plan and awarded the Company’s key executives approximately equal numbers of performance units and options to purchase shares of common stock. The value of the performance units awarded in 2000 is based on the absolute increase in market value of the Company’s common stock over the period July 1, 2000 to June 30, 2003. Under the 2000 Performance Unit Plan, the Company may pay the holders of the performance units in cash or stock at the Company’s option. The value of the performance units awarded in July 2000 was finally determinable on June 30, 2003. Because the value of the Company’s common stock appreciated considerably between June 30, 2000 and June 30, 2003, the value of the performance units granted in July 2000 was $6.4 million. The Company has elected to pay the amounts earned over time, beginning with an initial payment of approximately 20% of the amount due, or $750,000 cash and $375,000 in common stock. The Company has deferred the remainder of the obligation and expects to pay it over the next five years. The Company’s Board of Directors and Compensation & Benefits Committee will review that intention on an on-going basis and determine whether to pay the remainder of the obligation in cash or stock, based on the Company’s liquidity position, among other factors. In 2001 and 2002, the Compensation & Benefits Committee provided annual long-term incentives to the Company’s key managers by again awarding them stock options and performance units. Unlike the 2000 award, which was based on the actual appreciation in the stock price without limit, the 2001 and 2002 awards are based on the appreciation of the Company’s stock compared to that of its peer group and is capped. Like the performance units awarded in 2000, the performance units awarded in 2001 and 2002 vest over three-year periods and any value earned may be paid in cash or stock at the option of the Company. Based on the stock prices of the Company and its peer group as of June 30, 2003, the value of the performance units awarded in 2001 is currently $1.2 million and the value of the performance units awarded in 2002 is $2.6 million. The potential maximum value after three years of the performance units awarded in 2001 and 2002 is $2.9 million and $2.6 million, respectively. The final value of these performance units cannot be determined until June 30, 2004 and June 30, 2005 respectively, and could differ from the value of these units at June 30, 2003. Because stockholders had approved a Long-Term Stock Incentive Plan at the Company’s 2002 Annual Meeting, the Company was able to use stock options as the sole vehicle for the 2003 long-term incentive program.
In conclusion, there are many factors which can both positively or negatively affect the Company’s liquidity and cash flow. Management believes that cash flows from operations, including the possible sale of non-strategic assets if necessary, along with available borrowings, should be sufficient to pay the Company’s heritage health benefit costs, meet repayment requirements of the debt facilities, meet pension plan funding requirements, pay long-term performance plan obligations and fund ongoing business activities as long as currently anticipated surplus cash distributions from WML are received until the acquisition financing facility is paid off. At the same time, the Company continues to explore contingent sources of additional liquidity on an ongoing basis and to evaluate opportunities to expand and/or restructure its debt obligations and improve its capital structure.
Partner’s Proposed Sale of Its Interest in ROVA
Westmoreland Energy, LLC (“WELLC”) has been notified by its 50% partner, LG&E Power Inc. (“LPI”) of LPI’s possible interest in selling all of its independent power operations, including its 50% interest in the Westmoreland LG&E Partnership which owns the Roanoke Valley independent power plant (“ROVA”). LPI has initiated a process. WELLC has a right of first purchase for ROVA if the transaction proceeds as a sale of the LPI partnership interest. The bid process initiated by LPI is still underway, and it is uncertain if or how it will continue.
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Preferred Dividends and Stock Repurchase Plan
The depositary shares were issued on July 19, 1992. Each depositary share represents one-quarter of a share of Westmoreland’s Series A Convertible Exchangeable Preferred Stock. Dividends at a rate of 8.5% per annum were previously paid quarterly but were last suspended in the third quarter of 1995 pursuant to the requirements of Delaware law, described below, as a result of recognition of net losses, the violation of certain bank covenants, and a subsequent shareholders’ deficit. Westmoreland commenced payment of dividends to preferred shareholders on October 1, 2002 as described below. The quarterly dividends which are accumulated but unpaid through and including July 1, 2003 amount to $14.8 million in the aggregate ($71.97 per preferred share or $17.99 per depositary share). Common stock dividends may not be declared until the preferred stock dividends that are accumulated but unpaid are made current.
There are statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which Westmoreland is incorporated. Under Delaware law, Westmoreland is permitted to pay preferred stock dividends only: (1) out of surplus, surplus being the amount of shareholders’ equity in excess of the par value of Westmoreland’s two classes of stock; or (2) in the event there is no surplus, out of net profits for the fiscal year in which a preferred stock dividend is declared (and/or out of net profits from the preceding fiscal year), but only to the extent that shareholders’ equity exceeds the par value of the preferred stock (which par value was $205,000 at June 30, 2003). The Company had shareholders’ equity at June 30, 2003 of $22.0 million and the par value of all outstanding shares of preferred stock and shares of common stock aggregated $19.7 million at June 30, 2003.
The Board of Directors regularly reviews the subjects of current preferred stock dividends and the accumulated unpaid preferred stock dividends, and is committed to meeting its obligations to the preferred shareholders in a manner consistent with the best interests of all shareholders. As described in Note 4 to the Consolidated Financial Statements, quarterly dividends of $0.15 per depositary share have been paid for each of the four quarters beginning October 1, 2002 and increased to $0.20 per depositary share payable on October 1, 2003.
On August 9, 2002 Westmoreland’s Board of Directors authorized the repurchase of up to 10% of the outstanding depositary shares on the open market or in privately negotiated transactions with institutional and accredited investors between then and the end of 2004. The timing and amount of depositary shares repurchased will be determined by the Company’s management based on its evaluation of the Company’s capital resources, the price of the depositary shares offered to the Company and other factors. Any acquired shares will be converted into shares of Series A Convertible Exchangeable Preferred Stock and retired. The repurchase program will be funded from working capital which may be currently available, or become available to the Company. During the first quarter of 2003, 7,000 depositary shares were repurchased by the Company at a total cost of $212,800. From August 2002 through June 30, 2003, 14,500 depositary shares have been repurchased.
Resumption of a dividend payment and the repurchase plan reflect the reestablishment of profitability as a result of the Company’s successful initial implementation of its strategic plan for growth and the Company’s continuing commitment to preferred shareholders.
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RESULTS OF OPERATIONS
Quarter Ended June 30, 2003 Compared to Quarter Ended June 30, 2002
Coal Operations.
The decrease in coal revenues to $66.3 million in the second quarter of 2003 from $81.9 million in 2002’s second quarter is primarily the result of the new market-based price effective July 1, 2002 at the Jewett Mine which was, as expected, less than the previous cost-plus-fees price and reduced tons sold as a result of expected, significant scheduled maintenance outages at certain customers’ power plants. Specifically, fewer tons were sold at the Rosebud Mine due to an unplanned outage at the customer’s plant and at the Beulah Mine in North Dakota because of a longer than expected scheduled outage at the Coyote Station plant. The reduction in coal revenues at the Jewett Mine was partially offset by increased tons sold at the Jewett, Absaloka and Savage Mines. Increase in tons sold at these mines, including some lower margin tons, partially mitigated the loss of sales of higher margin tons due to customers’ power plant outages in the second quarter of 2003, which were greater than anticipated due to forced outages on top of expected scheduled major maintenance outages. The Jewett Mine sold more tons during second quarter 2003 than the comparable quarter in 2002 which had suffered from reduced demand due to mild weather and the economic slowdown. Almost all of the tons sold in both quarters were under long-term contracts to owners of power plants located adjacent to or near the mines, other than at the Absaloka Mine. Equivalent tons sold include petroleum coke sales.
Costs as a percentage of revenues for all mines increased to 80% in the second quarter of 2003 compared to 76% during the second quarter of 2002. Cost of sales decreased 16% in the second quarter of 2003 compared to second quarter of 2002, but revenues decreased even more as a result of the new market-based contract at the Jewett Mine and the mix of tons shipped from the Company’s other mines. Specific costs increased in 2003 for equipment maintenance and repairs at certain other mines and non-cash accretion costs at all mines for future reclamation activities required by SFAS No. 143, “Accounting for Asset Retirement Obligations,” the new accounting standard for recording reclamation liabilities.
The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods:
| | Quarter Ended | |
| | June 30, | |
| | 2003 | | 2002 | Change |
|
|
|
|
|
|
| | | | | | |
| Revenues – thousands | $ | 66,262 | $ | 81,888 | (19)% |
| | | | | | |
| Volumes – millions of equivalent coal tons | | 6.062 | | 6.283 | (4)% |
| | | | | | |
| Cost of sales – thousands | $ | 52,777 | $ | 62,617 | (16)% |
The Company’s business is subject to weather and some seasonality. The Company supplies coal 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 anticipated.
Depreciation, depletion and amortization were $3.0 million in both the second quarter 2003 and 2002.
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Independent Power. Equity in earnings from independent power operations was $4.2 million in the second quarter 2003 compared to $1.8 million in the quarter ended June 30, 2002. For the quarter ended June 30, 2003 and 2002, the ROVA projects produced 420,000 and 360,000 megawatt hours, respectively, and achieved average capacity factors of 92% and 79%, respectively. The increase in 2003 earnings, production, and capacity factors reflect a scheduled outage at the smaller ROVA II plant in 2003 compared to a scheduled outage which occurred in second quarter 2002 at the larger ROVA I plant.
Costs and Expenses.Selling and administrative expenses were $10.7 million in the quarter ended June 30, 2003 compared to $7.0 million in the quarter ended June 30, 2002 including non-cash compensation expense of $2.9 million for the long-term employee performance incentives in the second quarter of 2003 compared to a credit of $650,000 in the second quarter of 2002. Long-term incentive expense increases when the Company’s common stock price increases, which it did materially in the second quarter of 2003. The overall increase in selling and administrative expenses in the second quarter of 2003 is net of a benefit from the elimination of expenses in 2003 at the Jewett Mine and net of reduced medical claims under the Company’s self-insured plan for active employees which was redesigned for 2003. Costs of $720,000 for severance benefits increased selling and administrative expenses during the second quarter of 2003.
Heritage health benefit costs increased 20% or $1.3 million in the second quarter 2003 compared to second quarter 2002 as a result of higher costs for postretirement medical plans and an unfavorable actuarial valuation adjustment to the pneumoconiosis benefit obligation, caused primarily by a reduction in the discount rate used to value the benefit obligations.
During 2003‘s second quarter, there was a gain of $451,000 from sales of non-strategic property rights in Colorado that were acquired as part of the coal operations acquisitions in 2001. For the quarter ended June 30, 2002 there were no gains or losses from sales of assets.
Interest expense was $2.5 million and $2.7 million for the quarters ended June 30, 2003 and 2002, respectively. The decrease was mainly due to the smaller term debt balance on the acquisition financing as a result of continuing installment repayments. Interest income decreased in 2003 due to lower rates despite the larger amounts the Company holds in interest-bearing accounts.
As a result of the acquisitions made in 2001, the Company recognized a $55.6 million deferred income tax asset in April 2001 which assumes that a portion of previously unrecognized net operating loss carryforwards will be utilized because of the projected generation of future taxable income. The deferred tax asset increased to $68.1 million as of June 30, 2003 from $65.1 million at December 31, 2002 because of temporary differences (such as accruals for pension and reclamation expense, which are not deductible for tax purposes until paid) arising during the intervening period and due to a reduction of the deferred income tax valuation allowance discussed above. Deferred tax assets are comprised of both a current and long-term portion. When taxable income is generated, the deferred tax asset relating to 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 benefit for 2003 represents a current income tax obligation for State income taxes, and the utilization of a portion of the Company’s net operating loss carryforwards, net of the impact of changes in deferred tax assets and liabilities. The sale of DTA in 2003 increases the expected utilization of federal NOLs due both to the gain on sale and a reduction in future losses. This contributed to a reduction in the valuation allowance related to Federal NOLs and increased the tax benefit and net earnings. Likewise, an amended coal contract which increased future annual sales, benefited earnings in the second quarter of 2003. A tax loss in North Dakota that increased state NOLs and deferred tax assets was offset for the same amount by an increase in the valuation allowance since those losses are not expected to be utilized. The Federal Alternative Minimum Tax regulations were changed to allow 100% utilization of net operating loss carryforwards in 2001 and 2002 thereby eliminating all of the Company’s current Federal income tax expense.
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Terminal Operations.Losses continued until June 30, 2003, due to low throughput volume at DTA as a result of continued weakness in the export market and partnership cost-sharing obligations. The Company’s share of operating losses from DTA was $515,000 in the second quarter of 2003 compared to $534,000 in the 2002 quarter. No further operating losses should be incurred from DTA. As discussed in Note 2 to the consolidated financial statements, effective June 30, 2003 the Company sold its interest in DTA and recognized a pre-tax gain of approximately $4.5 million. The Company’s consolidated financial statements for 2003 and earlier periods reflect DTA as discontinued operations.
Cumulative Effect of Change in Accounting Principle.The Company adopted SFAS No. 143 during first quarter 2003 as described in the section on “Critical Accounting Policies” above. The cumulative effect of change was a gain of $161,000, net of tax expense of $108,000. SFAS No. 143 requires that the present value of retirement costs for which the Company has a legal obligation be recorded as liabilities, called asset retirement obligation. Also, capitalized asset retirement costs of $97,384,000 were recorded with changes to land and mineral rights, plant and equipment, accumulated depreciation and depletion and contractual reclamation obligations of third parties. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. When reclamation activities occur, the obligation is decreased and a gain or loss recognized for any difference between the previously recorded liability and the actual costs incurred.
Other Comprehensive Income. The other comprehensive income of $615,000 (net of income taxes of $410,000) recognized during the quarter ended June 30, 2003 represents the change in the unrealized loss on an interest rate swap agreement on the ROVA debt caused by changes in market interest rates during the period. This compares to other comprehensive loss of $218,000 (net of income taxes of $145,000) recognized during the quarter ended June 30, 2002. 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 reverse previously recorded losses.
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Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002
Coal Operations. Coal revenues decreased to $140.1 million for the six months ended June 30, 2003 from $160.3 million for the six months ended June 30, 2002. Although tons sold increased in 2003 compared to 2002 decreased revenue is primarily the result of the previously mentioned new market-based price at the Jewett Mine. Tons sold increased in 2003 compared to 2002 at all mines except the Beulah Mine. Costs, as a percentage of revenues, were 79% in 2003 compared to 76% in 2002. Costs during the six months of 2003 were affected for the same reasons discussed above in the quarterly comparisons.
The results of coal operations for the first six months of 2003 were negatively affected by the outages at the power generating stations discussed above: (1) at the Colstrip Station, which affected shipments from the Rosebud Mine, and (2) at the Coyote Station, which affected shipments from the Beulah Mine. These decreases were partially offset by an increase in tons sold from the Jewett Mine.
The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods:
| | Six Months Ended | |
| | June 30, | |
| | 2003 | | 2002 | Change |
|
|
|
|
|
|
| | | | | | |
| Revenues – thousands | $ | 140,775 | $ | 160,304 | (12)% |
| | | | | | |
| Volumes – millions of equivalent coal tons | | 13.060 | | 12.859 | 2% |
| | | | | | |
| Cost of sales – thousands | $ | 110,967 | $ | 121,482 | (9)% |
Independent Power.Equity in earnings from the independent power projects was $8.0 million and $6.6 million for the six months ended June 30, 2003 and 2002, respectively. For the six months ended June 30, 2003 and 2002, the ROVA projects produced 843,000 and 803,000 megawatt hours, respectively, and achieved capacity factors of 92% in 2003 and 88% in 2002. The increase in 2003 was due to the scheduled outage at the ROVA I plant during 2003 lasting fewer days than in 2002. The ROVA II plant operated at the same capacity during both periods.
Costs and Expenses. Selling and administrative expenses were $17.8 million for the six months ended June 30, 2003 compared to $15.6 million for the six months ended June 30, 2002. The increase in 2003 includes non–cash compensation expense for the Company’s Performance Unit Plan which was $4.2 million in the first six months of 2003 compared to $2.4 million in 2002. The characteristics of this plan are discussed in the quarter-to-quarter comparison above.
Heritage health benefit costs increased 16% or $2.1 million in the 2003 six-month period compared to 2002 as a result of increased actuarially determined costs for postretirement medical plans.
During 2003 there was a gain of $451,000 from sales of non-strategic property rights in Colorado that were acquired as part of the coal operations acquisitions in 2001. During the first six months of 2002, there was a $40,000 gain from the sale of used mine equipment.
Interest expense was $5.0 million and $5.5 million for the six months ended June 30, 2003 and 2002, respectively. The decrease was mainly due to partial repayment of the acquisition financing obtained during the second quarter of 2001. Interest income decreased in 2003 due to lower rates earned and despite the larger deposits acquired in the acquisitions.
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When taxable income is generated, the deferred tax asset relating to the Company’s net operating loss carryforwards is reduced and a deferred tax expense (non-cash) is recognized although no regular Federal income taxes are paid. Current income tax expense in both 2003 and 2002 relate to state income tax obligations. During the first six months of 2003, the deferred tax benefit of $2.8 million includes a $2.9 million benefit recognized for the reduction of the valuation allowance associated with unused Federal net operating loss carryforwards which are expected to be utilized.
Terminal Operations. The Company’s share of operating losses from DTA was $785,000 in the six months ended June 30, 2003 compared to $1,064,000 in the 2002 six-month period. No further operating losses should be incurred from DTA as discussed above in the second quarter comparisons.
Other Comprehensive Income.The other comprehensive income of $746,000 (net of income taxes of $497,000) recognized during the six months ended June 30, 2003 represents the change in the unrealized loss on an interest rate swap agreement on the ROVA debt caused by changes in market interest rates during the period. This compares the other comprehensive income of $58,000 (net of income taxes of $39,000) for the six months ended June 30, 2002.
ITEM 3
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company is exposed to market risk, including the effects of changes in commodity prices and interest rates as discussed below.
Commodity Price Risk
Westmoreland, through its subsidiaries Westmoreland Resources, Inc. and Westmoreland Mining LLC, produces and sells coal to third parties from coal mining operations in Montana, Texas and North Dakota, and through its subsidiary, Westmoreland Energy, LLC, 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 although some of the Company’s contracts are adjusted periodically based upon market prices. The Company has not entered into derivative contracts to manage its exposure to changes in commodity prices, and was not a party to any such contracts at June 30, 2003.
Interest Rate Risk
The Company is subject to interest rate risk on its debt obligations. Long-term debt obligations have only fixed interest rates, and the Company’s revolving lines of credit have a variable rate of interest indexed to either the prime rate or LIBOR. Based on the balances outstanding on these instruments as of June 30, 2003, a one percent increase in the prime interest rate or LIBOR would increase interest expense by $25,000 on an annual basis. The Company’s heritage health benefit costs are also impacted by interest rate changes because its pension, pneumoconiosis and post-retirement medical benefit obligations are recorded on a discounted basis.
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ITEM 4
CONTROLS AND PROCEDURES
The Company’s management, with the participation of the Company’s chief executive officer and chief financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) as of June 30, 2003. Based on this evaluation, the Company’s chief executive officer and chief financial officer concluded that, as of June 30, 2003, the Company’s disclosure controls and procedures were (1) designed to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to the Company’s chief executive officer and chief financial officer by others within those entities, particularly during the period in which this report was being prepared, and (2) effective, in that they provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
No change in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended June 30, 2003 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II - OTHER INFORMATION
ITEM 1
LEGAL PROCEEDINGS
As described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, “Item 3 - Legal Proceedings,” and in the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, “Part II, Item 1 – Legal Proceedings,” the Company has litigation which is still pending.
NWR – TGN Contract Dispute Issues
On May 6, 2003, NWR filed an amended petition in the District Court of Limestone County, Texas, which seeks damages for TGN’s failure to take agreed volumes of lignite in 2002 and for TGN’s purchases of PRB coal without providing NWR its contractual rights of first refusal. In addition, the petition claims failure to comply with test burn procedures that TGN had agreed to on June 18, 2002, seeks clarification of certain provisions of the ALSA, and seeks a declaratory judgment regarding the interpretation of certain contract provisions. Also on May 6, 2003, TGN filed a complaint against NWR in the District Court of Harris County, Texas, seeking payment of disputed royalties, alleging that it was owed a management fee under the old Lignite Supply Agreement, and requesting a declaratory judgment regarding the application of certain disputed contract provisions.
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1974 Pension Plan Arbitration
One element of heritage health benefit costs is pensions under the 1974 UMWA Retirement Plan (“1974 Plan”). Since this 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 when the Company terminated its last covered employees and withdrew from the Plan. However, the Plan claims that the Company withdrew from the Plan on an earlier date and that the Plan was not fully funded. The Company recognized $13.8 million asserted liability in 1998 but has vigorously contested the Plan’s claim as provided for under ERISA. On June 16, 2003, an arbitrator issued a decision that the Company’s withdrawal date was earlier than the date on which the Company terminated its last covered UMWA employee. The Company believes this finding is erroneous. However, before an appeal can be considered, the arbitrator must determine the amount, if any, that the 1974 Plan was unfunded at the date of withdrawal. Westmoreland believes that its obligation regarding unfunded liability is substantially less than the $13.8 million the 1974 Plan claims is due. 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 the arbitration is completed. At the conclusion of arbitration, the Company may be entitled to a refund or could be required to pay a reduced amount in installments through 2008. It is expected that the second part of the arbitration will commence in the second quarter of 2004.
Entech, Inc.
On July 1, 2003, the New York Court of Appeals reversed the decision of the trial and intermediate courts which had ordered Entech to proceed with the Purchase Price Adjustment as required by the Stock Purchase Agreement, and determined that many of Westmoreland’s objections to the Entech closing certificate were in reality allegations of a breach of the representations and warranties that Entech made in the Stock Purchase Agreement. The case was remanded to the trial court to evaluate Westmoreland’s objections and determine which should be treated as breach of representation or warranty claims and which should be resolved through the contractually mandated Purchase Price Adjustment process. With the recent Entech Chapter 11 filing in Delaware it is unclear what the next steps in the New York litigation will be. The bankruptcy automatic stay provisions prevent the Company from prosecuting any claim, without relief from the stay. The Entech bankruptcy was filed in Delaware on June 18, 2003, and has been consolidated with Touch America’s bankruptcy, also filed on June 18, 2003. It is anticipated that the Company will file a protective proof of claim for the purchase price adjustment when the time is proper. Although there can be no assurance as to the ultimate outcome of this dispute, the Company believes its claims are meritorious.
McGreevey Litigation
In mid-November, 2002, the Company was served with a complaint (Plaintiff’s Fourth Amended Complaint) filed on October 4, 2002 in a case styled McGreevey et al. v. Montana Power Company et al. in a Montana State court. Plaintiffs filed their first complaint on August 16, 2001. The Fourth Amended Complaint added Westmoreland as a defendant to a shareholder suit against Montana Power Company, various officers of Montana Power Company, the Board of Directors of Montana Power Company, financial advisors and lawyers representing Montana Power Company and the purchasers of some of the businesses formerly owned by Montana Power Company and Entech, Inc., a subsidiary of Montana Power Company. The plaintiffs were granted certification as a class before Westmoreland was added as a party to the litigation. Plaintiffs seek to rescind the sale by Montana Power of its generating, oil and gas, and transmission businesses, and the sale by Entech of its coal business or to compel the purchasers to hold these businesses in trust for the shareholders. Westmoreland has filed an answer, various affirmative defenses and a counterclaim against the plaintiffs. On June 20, 2003, defendants filed a motion with the Montana Supreme Court seeking to have the current trial judge disqualified for bias. The Montana Supreme Court has appointed a judge from another jurisdiction to investigate the defendant’s petition seeking disqualification. A hearing had been set for July 31, 2003. However, on July 18, 2003, both Touch America Holdings, Inc., the successor to Montana Power, and Entech sought bankruptcy protection in the United States Bankruptcy Court in Delaware.
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One defendant has unsuccessfully sought removal of the case to Federal Court. On July 17th, another removal petition by all defendants was filed with the U.S. District Court in Montana asserting that resolution of these cases is critical to the estates of Touch America and Entech. It is anticipated that the plaintiffs will object to the removal and seek to have the case remanded to the state court. All defendants have also filed a motion with the Montana Supreme Court seeking to have the current trial judge disqualified. No decision on removal is expected until late in the third quarter. In addition to the defendant’s motion to remove the case, Touch America and Entech have filed notices of the pending bankruptcies with the Montana State Court which will prevent any further action until the stay has been lifted by the Bankruptcy Court.
Western Energy Company
Western Energy Company’s coal supply agreement with the Colstrip Units l and II owners contains a provision that calls for the price to be reopened on the contract’s thirtieth anniversary, which was July 30, 2001. The parties had six months to negotiate a new price for delivered coal. If the parties were unable to agree on a new price, the issue is to be submitted to an arbitrator for resolution. The parties attempted to negotiate through June 2002 a new contract price. After a year of unsuccessful negotiations, the Company demanded that the binding arbitration begin. A three judge panel has now been selected and discovery has begun. The case is scheduled to be heard in April 2004. While the Company believes it is due a price increase effective July 30, 2001, as with any arbitration the outcome is uncertain.
Combined Benefit Fund Litigation
On June 10, 2003, the Social Security Administration (“SSA”) notified the Trustees of the UMWA Combined Benefit Fund (“CBF”) of a premium increase for beneficiaries assigned to companies under the Coal Act. The Company makes monthly premium payments to the UMWA Combined Benefit Fund (“CBF”), a multiemployer health plan neither controlled nor administered by the Company. The current amount of the monthly premiums is less than $400,000 and is recalculated annually each October. The SSA’s action could increase the Company’s premium by an estimated 10%. There is also a possibility that the CBF could seek to impose the increase retroactively to all premiums paid since 1995. The Company has joined other coal companies with CBF obligations in a complaint filed in the U.S. District Court for the Northern District of Alabama seeking injunctive and declaratory relief regarding the potential increase in CBF premiums.
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ITEM 3
DEFAULTS UPON SENIOR SECURITIES
See Note 4 “Capital Stock” to the Consolidated Financial Statements, which is incorporated by reference herein.
ITEM 4
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
An Annual Meeting of Shareholders was held on May 22, 2003. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934. Two proposals were voted upon at the meeting.
The first proposal was the election by the holders of Common Stock of seven members of the Board of Directors. The tabulation of the votes cast with respect to each of the nominees for election as a Director is set forth as follows:
|
|
|
| Name | Votes For | Votes Withheld |
|
|
|
| Pemberton Hutchinson | 7,326,003 | 99,831 |
| Thomas W. Ostrander | 7,315,297 | 110,537 |
| Christopher K. Seglem | 7,314,990 | 110,844 |
| Thomas J. Coffey | 7,288,009 | 137,825 |
| Robert E. Killen | 7,288,109 | 137,725 |
| James W. Sight | 7,288,409 | 137,425 |
| Donald A. Tortorice | 7,315,195 | 110,639 |
|
|
|
Messrs. Hutchinson, Ostrander, Seglem, Coffey, Killen, Sight and Tortorice were elected.
There were no abstentions or broker non-votes.
The second proposal was the election by the holders of Depositary Shares of two members of the Board of Directors. Each Depositary Share represents one-quarter of a share of the Company’s Series A Convertible Exchangeable Preferred Stock (“Series A Preferred Stock”), the terms of which entitle the holders to elect two directors if six or more Preferred Stock dividends have accumulated. The tabulation of the votes cast with respect to each of the nominees for election as a Director, expressed in terms of the number of Depositary Shares, is as follows:
|
|
|
| Name | Votes For | Votes Withheld |
|
|
|
| Michael Armstrong | 791,099 | 4,265 |
| William M. Stern | 791,299 | 4,065 |
|
|
|
Messrs. Armstrong and Stern were elected.
There were no abstentions or broker non-votes.
ITEM 5
OTHER INFORMATION
The Company decided to hire a new Chief Financial Officer. Rather than accept a different position within the Company, the current Senior Vice President - Finance and Development, Mr. Robert J. Jaeger, elected to take advantage of benefits under the Company’s Executive Severance Policy adopted prior to the restructuring program begun in the early 1990’s. Pursuant to a negotiated termination agreement, Mr. Jaeger will leave the Company on August 31, 2003 and receive severance benefits over a ten-year period. A search for his replacement as CFO is in process. If a replacement is not hired before Mr. Jaeger’s last day with the Company, Mr. Ronald H. Beck, Vice President, Finance and Treasurer will serve as Acting Chief Financial Officer. Mr. Douglas P. Kathol, formerly Senior Vice President of Finance and Strategy at NorWest Corp., will join the Company in August as Vice President-Development.
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ITEM 6
EXHIBITS AND REPORTS ON FORM 8-K
| | |
| | | 10.1 | Approved Westmoreland Coal Company 2000 Performance Unit Plan, dated May 22, 2003. |
| | |
| | | 10.2 | First Amendment to Westmoreland Coal Company 2000 Non-employee Directors' Stock Incentive Plan dated May 22, 2003. |
| | |
| | | 10.3 | Termination Agreement for Robert J. Jaeger, Chief Financial Officer. |
| | |
| | | 10.4 | Westmoreland Coal Company Deferred Compensation Plan effective May 1, 2003. |
| | |
| | | 31 | Rule 13a-14(a)/15d-14(a) Certifications. |
| | |
| | | 32 | Certifications pursuant to 18 U.S.C. Section 1350. |
| | | (1) | On May 9, 2003, the Company filed a report on Form 8-K announcing its Board of Directors authorized a dividend of $0.15 per depositary share payable on July 1, 2003 to holders of record as of June 10, 2003. |
| | | | |
| | | (2) | On July 2, 2003, the Company filed a report on Form 8-K announcing the sale of its interest in Dominion Terminal Associates and associated industrial revenue bonds to Dominion Energy Terminal Company, Inc. |
| | | (3) | On July 9, 2003, the Company filed a report on Form 8-K disclosing the pro forma effect to the change in accounting principle as if the Financial Accounting Standards Board "Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations" had been in effect during the Company's three most recent fiscal years. |
| | | | |
| | | (4) | On August 5, 2003, the Company filed a report on Form 8-K announcing its Board of Directors authorized a dividend of $0.20 per depositary share payable on October 1, 2003 to holders of record as of September 10, 2003. |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| WESTMORELAND COAL COMPANY |
| | |
| Date: August 13, 2003 | /s/ Ronald H. Beck |
| Ronald H. Beck |
| Vice President - Finance and |
| Treasurer |
| (A Duly Authorized Officer) |
| | |
| | /s/ Thomas S. Barta |
| Thomas S. Barta |
| Controller |
| (Principal Accounting Officer) |
| | |
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Westmoreland Coal Company
Exhibit index
| | | 10.1 | Approved Westmoreland Coal Company 2000 Performance Unit Plan, dated May 22, 2003. |
| | |
| | | 10.2 | First Amendment to Westmoreland Coal Company 2000 Non-employee Directors' Stock Incentive Plan dated May 22, 2003. |
| | |
| | | 10.3 | Termination Agreement for Robert J. Jaeger, Chief Financial Officer. |
| | |
| | | 10.4 | Westmoreland Coal Company Deferred Compensation Plan effective May 1, 2003. |
| | |
| | | 31 | Rule 13a-14(a)/15d-14(a) Certifications. |
| | |
| | | 32 | Certifications pursuant to 18 U.S.C. Section 1350. |
44
