SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period endedJune 30, 2005
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to ___________
Commission File Number
001-11155
WESTMORELAND COAL COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE | 23-1128670 | ||
(State or other jurisdiction | (I.R.S. Employer | ||
of incorporation or organization) | Identification No.) |
2 North Cascade Avenue 14th Floor Colorado Springs, Colorado | 80903 | ||
(Address of principal executive offices) | (Zip Code) |
Registrant's telephone number, including area code | 719-442-2600 |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X No ___
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of August 1, 2005: Common stock, $2.50 par value: 8,295,872
PART I — FINANCIAL INFORMATION
ITEM 1
FINANCIAL STATEMENTS
Westmoreland Coal Company and Subsidiaries | |||||
---|---|---|---|---|---|
Consolidated Balance Sheets | |||||
(Unaudited) | |||||
June 30, | December 31, | ||||
2005 | 2004 | ||||
(in thousands) | |||||
Assets | |||||
Current assets: | |||||
Cash and cash equivalents | $ | 9,142 | $ | 11,125 | |
Receivables: | |||||
Trade | 30,003 | 24,891 | |||
Other | 7,248 | 4,399 | |||
37,251 | 29,290 | ||||
Inventories | 17,681 | 14,952 | |||
Deferred overburden removal costs | 15,016 | 12,034 | |||
Restricted cash | 9,961 | 9,761 | |||
Deferred income taxes | 14,532 | 13,501 | |||
Other current assets | 6,205 | 6,239 | |||
Total current assets | 109,788 | 96,902 | |||
Property, plant and equipment: | |||||
Land and mineral rights | 21,991 | 22,234 | |||
Capitalized asset retirement cost | 118,474 | 118,474 | |||
Plant and equipment | 121,594 | 110,196 | |||
262,059 | 250,904 | ||||
Less accumulated depreciation, depletion and amortization | 90,938 | 82,276 | |||
Net property, plant and equipment | 171,121 | 168,628 | |||
Deferred income taxes | 74,766 | 71,195 | |||
Investment in independent power projects | 52,574 | 48,565 | |||
Excess of trust assets over pneumoconiosis benefit obligation | 3,177 | 4,463 | |||
Restricted cash and bond collateral | 23,653 | 22,921 | |||
Advanced coal royalties | 3,479 | 3,521 | |||
Deferred overburden removal costs | 2,235 | 3,910 | |||
Reclamation deposits | 56,958 | 55,561 | |||
Contractual third party reclamation obligations | 25,955 | 24,998 | |||
Other assets | 12,073 | 13,325 | |||
Total Assets | $ | 535,779 | $ | 513,989 | |
See accompanying Notes to Consolidated Financial Statements. | (Continued) |
2
Westmoreland Coal Company and Subsidiaries | |||||
---|---|---|---|---|---|
Consolidated Balance Sheets (Continued) | |||||
(Unaudited) | |||||
June 30, | December 31, | ||||
2005 | 2004 | ||||
(in thousands) | |||||
Liabilities and Shareholders' Equity | |||||
Current liabilities: | |||||
Current installments of long-term debt | $ | 11,930 | $ | 11,819 | |
Accounts payable and accrued expenses: | |||||
Trade | 33,497 | 24,769 | |||
Income taxes | 518 | 71 | |||
Production taxes | 19,272 | 18,316 | |||
Workers’ compensation | 1,438 | 1,288 | |||
Postretirement medical costs | 16,795 | 16,437 | |||
Asset retirement obligations | 6,954 | 5,284 | |||
Total current liabilities | 90,404 | 77,984 | |||
Long-term debt, less current installments | 110,111 | 105,440 | |||
Workers’ compensation, less current portion | 8,792 | 9,646 | |||
Postretirement medical costs, less current portion | 120,935 | 117,792 | |||
Pension and SERP costs | 11,555 | 10,637 | |||
Asset retirement obligations, less current portion | 137,464 | 135,509 | |||
Other liabilities | 8,888 | 12,819 | |||
Minority interest | 4,509 | 4,270 | |||
Commitments and contingent liabilities | |||||
Shareholders' equity: | |||||
Preferred stock of $1.00 par value | |||||
Authorized 5,000,000 shares; | |||||
Issued and outstanding 205,083 shares at June 30, 2005 and at | |||||
December 31, 2004 | 205 | 205 | |||
Common stock of $2.50 par value | |||||
Authorized 20,000,000 shares; | |||||
Issued and outstanding 8,287,684 shares at June 30, 2005 and | |||||
8,168,601 shares at December 31, 2004 | 20,719 | 20,421 | |||
Other paid-in capital | 76,779 | 75,366 | |||
Accumulated other comprehensive loss | (4,923 | ) | (5,117 | ) | |
Accumulated deficit | (49,659 | ) | (50,983 | ) | |
Total shareholders' equity | 43,121 | 39,892 | |||
Total Liabilities and Shareholders' Equity | $ | 535,779 | $ | 513,989 | |
See accompanying Notes to Consolidated Financial Statements.
3
Westmoreland Coal Company and Subsidiaries Consolidated Statements of Operations | |||||||||
---|---|---|---|---|---|---|---|---|---|
(Unaudited) | |||||||||
Three Months Ended | Six Months Ended | ||||||||
June 30, | June 30, | ||||||||
2005 | 2004 | 2005 | 2004 | ||||||
(in thousands except per share data) | |||||||||
Revenues: | |||||||||
Coal | $ | 85,701 | $ | 87,020 | $ | 171,800 | $ | 164,152 | |
Independent power projects — equity in earnings | 3,459 | 1,681 | 8,628 | 7,086 | |||||
89,160 | 88,701 | 180,428 | 171,238 | ||||||
Costs and expenses: | |||||||||
Cost of sales — coal | 71,350 | 66,115 | 139,108 | 126,318 | |||||
Depreciation, depletion and amortization | 4,742 | 3,601 | 9,476 | 7,421 | |||||
Selling and administrative | 8,531 | 6,954 | 14,865 | 14,677 | |||||
Heritage health benefit costs | 7,704 | 7,703 | 15,370 | 14,909 | |||||
Loss on sales of assets | 200 | 38 | 179 | 19 | |||||
92,527 | 84,411 | 178,998 | 163,344 | ||||||
Operating income (loss) | (3,367 | ) | 4,290 | 1,430 | 7,894 | ||||
Other income (expense): | |||||||||
Interest expense | (2,598) | (2,552) | (5,167) | (5,038) | |||||
Interest income | 909 | 1,377 | 1,632 | 2,321 | |||||
Minority interest | (267) | (321) | (559) | (603) | |||||
Other | 469 | 202 | 640 | 83 | |||||
(1,487) | (1,294) | (3,454) | (3,237) | ||||||
Income (loss) before income taxes | (4,854) | 2,996 | (2,024) | 4,657 | |||||
Income tax benefit | 1,380 | 1,829 | 3,758 | 2,704 | |||||
Net income (loss) | (3,474) | 4,825 | 1,734 | 7,361 | |||||
Less preferred stock dividend requirements | 436 | 436 | 872 | 872 | |||||
Net income (loss) applicable to common shareholders | $ | (3,910) | $ | 4,389 | $ | 862 | $ | 6,489 | |
Net income (loss) per share applicable to common shareholders: | |||||||||
Basic | $ | (.47) | $ | .54 | $ | .10 | $ | .81 | |
Diluted | $ | (.47) | $ | .51 | $ | .10 | $ | .76 | |
Weighted average number of common shares outstanding: | |||||||||
Basic | 8,269 | 8,082 | 8,231 | 8,046 | |||||
Diluted | 8,738 | 8,590 | 8,797 | 8,545 | |||||
See accompanying Notes to Consolidated Financial Statements.
4
Westmoreland Coal Company and Subsidiaries Consolidated Statement of Shareholders’ Equity and Comprehensive Income Six Months Ended June 30, 2005 (Unaudited) | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
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, 2004 (205,083 preferred shares and 8,168,601 common shares outstanding) | $ 205 | $20,421 | $75,366 | $(5,117 | ) | $(50,983 | ) | $ 39,892 | |||||
Common stock issued as compensation (41,483 shares) | - | 104 | 848 | - | - | 952 | |||||||
Common stock options exercised (77,600 shares) | - | 194 | 368 | - | - | 562 | |||||||
Dividends declared | - | - | - | - | (410 | ) | (410 | ) | |||||
Tax benefit of stock option exercises | - | - | 197 | - | - | 197 | |||||||
Net income | - | - | - | - | 1,734 | 1,734 | |||||||
Net unrealized change in interest rate swap | |||||||||||||
agreement, net of tax expense of $129 | - | - | - | 194 | - | 194 | |||||||
Comprehensive income | 1,928 | ||||||||||||
Balance at June 30, 2005 (205,083 preferred shares and 8,287,684 common shares outstanding) | $ 205 | $20,719 | $76,779 | $(4,923 | ) | $(49,659 | ) | $ 43,121 | |||||
See accompanying Notes to Consolidated Financial Statements.
5
Westmoreland Coal Company and Subsidiaries Consolidated Statements of Cash Flows | |||||
---|---|---|---|---|---|
(Unaudited) | |||||
Six Months Ended June 30, | 2005 | 2004 | |||
(in thousands) | |||||
Cash flows from operating activities: | |||||
Net income | $ | 1,734 | $ | 7,361 | |
Adjustments to reconcile net income to net cash provided by operating | |||||
activities: | |||||
Equity in earnings from independent power projects | (8,628 | ) | (7,086 | ) | |
Cash distributions from independent power projects | 4,814 | 3,098 | |||
Deferred income tax benefit | (4,405 | ) | (3,359 | ) | |
Depreciation, depletion and amortization | 9,476 | 7,421 | |||
Stock compensation expense | 952 | 918 | |||
Loss on sales of assets | 179 | 19 | |||
Minority interest | 559 | 603 | |||
Net change in operating assets and liabilities | 2,797 | (11,903 | ) | ||
Net cash provided by (used in) operating activities | 7,478 | (2,928 | ) | ||
Cash flows from investing activities: | |||||
Additions to property, plant and equipment | (12,315 | ) | (5,725 | ) | |
Change in restricted cash and bond collateral and reclamation deposits | (2,329 | ) | (5,696 | ) | |
Net proceeds from sales of assets | 569 | 153 | |||
Net cash used in investing activities | (14,075 | ) | (11,268 | ) | |
Cash flows from financing activities: | |||||
Proceeds from long-term debt, net of debt issuance costs | - | 18,647 | |||
Repayment of long-term debt | (4,718 | ) | (6,025 | ) | |
Net borrowings (repayments) of revolving lines of credit | 9,500 | 7,500 | |||
Exercise of stock options | 562 | 634 | |||
Dividends paid to minority interest | (320 | ) | (320 | ) | |
Dividends on preferred shares | (410 | ) | (328 | ) | |
Net cash provided by financing activities | 4,614 | 20,108 | |||
Net increase (decrease) in cash and cash equivalents | (1,983 | ) | 5,912 | ||
Cash and cash equivalents, beginning of period | 11,125 | 9,267 | |||
Cash and cash equivalents, end of period | $ | 9,142 | $ | 15,179 | |
Supplemental disclosures of cash flow information: | |||||
Cash paid during the period for: | |||||
Interest | $ | 4,932 | $ | 4,850 | |
Income taxes | $ | 199 | $ | 491 | |
See accompanying Notes to Consolidated Financial Statements.
6
These quarterly consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004. The accounting principles followed by the Company are set forth in the Notes to the Company’s consolidated financial statements in that Annual Report. These accounting principles and other footnote disclosures previously made have been omitted in this report so long as the interim information presented is not misleading.
The consolidated financial statements of the Company have been prepared in accordance with generally accepted accounting principles and require use of management’s estimates. The financial information contained in this Form 10-Q is unaudited but reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the financial information for the periods shown. Such adjustments are of a normal recurring nature. The results of operations for such interim periods are not necessarily indicative of results to be expected for the full year.
1. | NATURE OF OPERATIONS |
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; and (ii) the development, ownership and management of interests in cogeneration and other non-regulated independent power plants.
2. | LINES OF CREDIT AND LONG-TERM DEBT |
The amounts outstanding at June 30, 2005 and December 31, 2004 under the Company’s lines of credit and long-term debt were:
June 30, 2005 | December 31, 2004 | ||||
(in thousands) | |||||
WML revolving line of credit with PNC Bank | $ 2,000 | $ - | |||
WML term debt: | |||||
Series B Notes | 73,050 | 78,200 | |||
Series C and D Notes | 35,000 | 35,000 | |||
Corporate revolving line of credit | 7,500 | - | |||
Other term debt | 4,491 | 4,059 | |||
Total debt outstanding | 122,041 | 117,259 | |||
Less current portion | (11,930 | ) | (11,819 | ) | |
Total long-term debt outstanding | $ 110,111 | $ 105,440 | |||
The Company has a $14.0 million revolving credit agreement with First Interstate Bank. Interest is payable monthly. Effective July 19, 2005, the interest rate on this line of credit was reduced 1%, to the bank’s prime rate, and the expiration date of this agreement was extended to June 30, 2007. The revolving credit agreement requires the Company to maintain certain financial ratios. The revolving credit agreement is collateralized by the Company’s stock in Westmoreland Resources, Inc. (“WRI”), the stock of Horizon Coal Services, Inc. (“Horizon”), and the dragline located at WRI’s Absaloka Mine in Big Horn County, Montana.
7
Westmoreland Mining LLC (“WML”) has a $12 million revolving facility (the “Facility”) with PNC Bank National, Association (“PNC”) which expires on April 27, 2007. The interest rate is either PNC’s Base Rate plus 1.50% or Euro-Rate plus 3.00%, at WML’s option. In addition, a commitment fee of ½ of 1% of the average unused portion of the available credit is payable quarterly. The amount available under the Facility is based upon, and any outstanding amounts are secured by, eligible accounts receivable.
WML has a term loan agreement as described in the Company’s 2004 Annual Report on Form 10-K with $73.1 million in Series B Notes, $20.4 million in Series C Notes and $14.6 million in Series D Notes outstanding as of June 30, 2005. The Series B Notes bear interest at a fixed interest rate of 9.39%, Series C Notes at a fixed rate of 6.85%, and the Series D Notes have a variable rate based upon LIBOR plus 2.90%. The Company incurred the indebtedness represented by the Series B Notes in connection with its acquisition of the Rosebud, Jewett, Beulah and Savage Mines in 2001, and we occasionally refer to this indebtedness as our acquisition debt. The Series C and D Notes were added in 2004 and we refer to them as WML “add-on” debt. All of the Notes are secured by assets of WML and the term loan agreement subjects the Company to certain covenants and financial ratio requirements. WML was not in compliance with certain of these financial ratios at June 30, 2005 due to the accelerated receipt of the arbitration award in 2004 for the Colstrip Units 1 & 2 compared to forecasts at the time the ratios were set. However, the lenders provided a waiver for the quarter. The Company expects to be in compliance with its covenants for the next twelve months.
Pursuant to the WML term loan agreement, WML is required to maintain debt service reserve and long-term prepayment accounts. As of June 30, 2005, there was a total of $10.0 million in the debt service reserve account, which could be used for principal and interest payments, and $12.1 million in the long-term prepayment account, which account will be used to fund a $30.0 million payment due December 31, 2008 for the Series B Notes. Those funds have been classified as restricted cash on the consolidated balance sheet.
The maturities of all long-term debt and the revolving credit facilities outstanding at June 30, 2005 are:
In thousands | |||
2005 | $ 5,855 | ||
2006 | 12,462 | ||
2007 | 22,592 | ||
2008 | 45,447 | ||
2009 | 12,272 | ||
Thereafter | 23,413 | ||
$ 122,041 | |||
3. | PENSION AND POSTRETIREMENT MEDICAL BENEFITS |
The Company provides pension and postretirement medical and life insurance benefits to qualifying full-time employees and retired employees and their dependents. A very large majority of these benefits are mandated by the Federal Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”) and provided to former miners at the Company’s previously owned operations and their dependents. The Company incurred costs of providing these benefits during the six-month periods ended June 30, 2005 and 2004 as follows:
8
Pension Benefits | Postretirement Medical and Life Insurance Benefits | ||||||||
2005 | 2004 | 2005 | 2004 | ||||||
(in thousands) | |||||||||
Service cost | $ 1,344 | $ 1,232 | $ 258 | $ 252 | |||||
Interest cost | 1,804 | 1,652 | 7,277 | 7,394 | |||||
Expected return on plan assets | (1,700 | ) | (1,386 | ) | - | - | |||
Amortization of deferred items | 495 | 450 | 4,572 | 4,168 | |||||
Net periodic cost | $ 1,943 | $ 1,948 | $12,107 | $11,814 | |||||
The Company expects to contribute approximately $1.8 million to its pension plans during 2005. Of that amount, $1.1 million was contributed in the first six months.
4. | CAPITAL STOCK |
Each depositary share represents one-quarter of a share of Westmoreland’s Series A Convertible Exchangeable Preferred Stock (“Series A Preferred Stock”). The full amount of the quarterly dividend is $2.125 per preferred share or $0.53 per depositary share. Partial dividends have been declared and paid since October 1, 2002, including a dividend of $0.25 per depositary share paid on January 1, 2005, April 1, 2005, and July 1, 2005. A dividend of $0.25 per depositary share was declared on July 29, 2005, payable October 1, 2005. The quarterly dividends which are accumulated but unpaid through and including July 1, 2005 amount to $16.8 million in the aggregate ($81.97 per preferred share or $20.49 per depositary share). Common stock dividends may not be declared until the preferred stock dividends that are accumulated but unpaid are made current.
Incentive Stock Options
The Company applies the intrinsic-value-based method of accounting prescribed by Accounting Principles Board (“APB”) Opinion No. 25,Accounting for Stock Issued to Employees, and related interpretations, to account for its fixed-plan stock options. Under this method, compensation expense is recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. Statement of Financial Accounting Standards No. 123,Accounting for Stock-Based Compensation (“SFAS No. 123”), established accounting and disclosure requirements using a fair-value-based method of accounting for stock-based employee compensation plans. As allowed under SFAS No. 123, the Company has elected to continue to apply the intrinsic-value-based method of accounting described above, and has adopted only the disclosure requirements of SFAS No. 123. The following table illustrates the pro forma effect on net income and net income per share as if the compensation cost for the Company’s fixed-plan stock options had been determined based on the fair value at the grant dates consistent with SFAS No. 123:
9
Three Months Ended | Six Months Ended | ||||||||
---|---|---|---|---|---|---|---|---|---|
June 30, | June 30, | ||||||||
2005 | 2004 | 2005 | 2004 | ||||||
(in thousands, except per share data) | |||||||||
Net income (loss) applicable to common | |||||||||
shareholders, as reported | $ | (3,910) | $ | 4,389 | $ | 862 | $ | 6,489 | |
Less: Total stock-based employee compensation | |||||||||
expense determined under fair value based | |||||||||
method for all awards, net of related tax | |||||||||
effects | 57 | 220 | 169 | 422 | |||||
Net income (loss) applicable to common shareholders, pro forma | $ | (3,967) | $ | 4,169 | $ | 693 | $ | 6,067 | |
Net income (loss) per share applicable to | |||||||||
common shareholders: | |||||||||
Basic - as reported | $ | (.47) | $ | .54 | $ | .10 | $ | .81 | |
Basic - pro forma | $ | (.48) | $ | .52 | $ | .08 | $ | .75 | |
Diluted - as reported | $ | (.47) | $ | .51 | $ | .10 | $ | .76 | |
Diluted - pro forma | $ | (.48) | $ | .49 | $ | .08 | $ | .71 | |
Earnings per Share
The following table provides a reconciliation of the number of shares used to calculate basic and diluted earnings per share (EPS):
Three Months Ended | Six Months Ended | |||||||
---|---|---|---|---|---|---|---|---|
June 30, | June 30, | |||||||
2005 | 2004 | 2005 | 2004 | |||||
(in thousands) | ||||||||
Number of shares of common stock: | ||||||||
Basic | 8,269 | 8,082 | 8,231 | 8,046 | ||||
Effect of dilutive option shares | 469 | 508 | 566 | 499 | ||||
Diluted | 8,738 | 8,590 | 8,797 | 8,545 | ||||
Number of shares not included in diluted EPS that | ||||||||
would have been antidilutive because exercise price | ||||||||
of options was greater than the average market | ||||||||
price of the common shares | 11 | - | 1 | - |
10
5. | INCOME TAXES |
Income tax (expense) benefit attributable to income before income taxes consists of:
Three Months Ended | Six Months Ended | |||||||
---|---|---|---|---|---|---|---|---|
June 30, | June 30, | |||||||
2005 | 2004 | 2005 | 2004 | |||||
(in thousands) | ||||||||
Current: | ||||||||
Federal | $ | - | $ | (263) | $ | (168) | $ | (334) |
State | (178) | (232) | (479) | (321) | ||||
(178) | (495) | (647) | (655) | |||||
Deferred: | ||||||||
Federal | 1,175 | 2,155 | 3,970 | 3,170 | ||||
State | 383 | 169 | 435 | 189 | ||||
1,558 | 2,324 | 4,405 | 3,359 | |||||
Income tax (expense) benefit | $ | 1,380 | $ | 1,829 | $ | 3,758 | $ | 2,704 |
The deferred income tax benefit recorded for the three months and six months ended June 30, 2005 included an expense of $1.0 million and a benefit of $1.5 million, respectively, due to an increase or reduction in the deferred income tax asset valuation allowance as a result of changes in the amount of Federal net operating loss carryforwards expected to be used by the Company prior to their expiration through 2023. The deferred income tax benefit recorded for the three months and six months ended June 30, 2004 included a benefit of $1.2 million and $2.1 million, respectively, due to a reduction in the deferred income tax asset valuation allowance.
6. | BUSINESS SEGMENT INFORMATION |
The Company’s operations have been classified into two segments: coal and independent power. The coal segment includes the production and sale of coal from Montana, North Dakota and Texas. The independent power operations include the ownership of interests in cogeneration and other non-regulated independent power plants. The “Corporate” classification noted in the tables represents all costs not otherwise classified, including corporate office charges, heritage health benefit costs and business development expenses. Summarized financial information by segment for the quarters ended June 30, 2005 and 2004 is as follows:
11
Coal | Independent Power | Corporate | Total | |||||
(in thousands) | ||||||||
Revenues: | ||||||||
Coal | $ | 85,701 | $ | - | $ | - | $ | 85,701 |
Equity in earnings | - | 3,459 | - | 3,459 | ||||
85,701 | 3,459 | - | 89,160 | |||||
Costs and expenses: | ||||||||
Cost of sales – coal | 71,350 | - | - | 71,350 | ||||
Depreciation, depletion and amortization | 4,687 | 6 | 49 | 4,742 | ||||
Selling and administrative | 6,639 | 710 | 1,182 | 8,531 | ||||
Heritage health benefit costs | - | - | 7,704 | 7,704 | ||||
Loss (gain) on sales of assets | 282 | - | (82) | 200 | ||||
Operating income (loss) | $ | 2,743 | $ | 2,743 | $ | (8,853) | $ | (3,367) |
Capital expenditures | $ | 7,328 | $ | 10 | $ | 277 | $ | 7,615 |
Property, plant and equipment, net | $ | 169,307 | $ | 83 | $ | 1,731 | $ | 171,121 |
Quarter ended June 30, 2004
Coal | Independent Power | Corporate | Total | |||||
(in thousands) | ||||||||
Revenues: | ||||||||
Coal | $ | 87,020 | $ | - | $ | - | $ | 87,020 |
Equity in earnings | - | 1,681 | - | 1,681 | ||||
87,020 | 1,681 | - | 88,701 | |||||
Costs and expenses: | ||||||||
Cost of sales – coal | 66,115 | - | - | 66,115 | ||||
Depreciation, depletion and amortization | 3,546 | 5 | 50 | 3,601 | ||||
Selling and administrative | 4,735 | 406 | 1,813 | 6,954 | ||||
Heritage health benefit costs | - | - | 7,703 | 7,703 | ||||
Loss on sales of assets | 38 | - | - | 38 | ||||
Operating income (loss) | $ | 12,586 | $ | 1,270 | $ | (9,566) | $ | 4,290 |
Capital expenditures | $ | 3,395 | $ | 16 | $ | 220 | $ | 3,631 |
Property, plant and equipment, net | $ | 149,043 | $ | 54 | $ | 665 | $ | 149,762 |
12
Coal | Independent Power | Corporate | Total | |||||
(in thousands) | ||||||||
Revenues: | ||||||||
Coal | $ | 171,800 | $ | - | $ | - | $ | 171,800 |
Equity in earnings | - | 8,628 | - | 8,628 | ||||
171,800 | 8,628 | - | 180,428 | |||||
Costs and expenses: | ||||||||
Cost of sales – coal | 139,108 | - | - | 139,108 | ||||
Depreciation, depletion and amortization | 9,380 | 10 | 86 | 9,476 | ||||
Selling and administrative | 11,685 | 1,036 | 2,144 | 14,865 | ||||
Heritage health benefit costs | - | - | 15,370 | 15,370 | ||||
Loss (gain) on sales of assets | 261 | - | (82) | 179 | ||||
Operating income (loss) | $ | 11,366 | $ | 7,582 | $ | (17,518) | $ | 1,430 |
Capital expenditures | $ | 11,172 | $ | 18 | $ | 1,125 | $ | 12,315 |
Property, plant and equipment, net | $ | 169,307 | $ | 83 | $ | 1,731 | $ | 171,121 |
Six months ended June 30, 2004
Coal | Independent Power | Corporate | Total | |||||
(in thousands) | ||||||||
Revenues: | ||||||||
Coal | $ | 164,152 | $ | - | $ | - | $ | 164,152 |
Equity in earnings | - | 7,086 | - | 7,086 | ||||
164,152 | 7,086 | - | 171,238 | |||||
Costs and expenses: | ||||||||
Cost of sales – coal | 126,318 | - | - | 126,318 | ||||
Depreciation, depletion and amortization | 7,332 | 10 | 79 | 7,421 | ||||
Selling and administrative | 10,001 | 614 | 4,062 | 14,677 | ||||
Heritage health benefit costs | - | - | 14,909 | 14,909 | ||||
Loss on sales of assets | 19 | - | - | 19 | ||||
Operating income (loss) | $ | 20,482 | $ | 6,462 | $ | (19,050) | $ | 7,894 |
Capital expenditures | $ | 5,424 | $ | 16 | $ | 285 | $ | 5,725 |
Property, plant and equipment, net | $ | 149,043 | $ | 54 | $ | 665 | $ | 149,762 |
13
7. | CONTINGENCIES |
Protection of the Environment
As of June 30, 2005 the Company has reclamation bonds in place for its active mines in Montana, North Dakota and Texas. The Company also has reclamation bonds in place for inactive mining sites in Virginia and Colorado which are now awaiting final bond release. These government-required bonds assure that coal mining operations comply with applicable Federal and State regulations relating to the performance and completion of final reclamation activities. The Company currently estimates that the cost of final reclamation for its mines when they are closed at some point in the future will total approximately $315.5 million (on an undiscounted basis), or $144.4 million expressed on a present value basis. The Company’s customers and the contract operator of the Absaloka Mine are responsible for $187.3 million of these reclamation costs (on an undiscounted basis) and have secured a portion of these obligations by providing a $50 million corporate guarantee to assure performance of such final reclamation and by funding reclamation escrow accounts in the amount of approximately $57.0 million as of June 30, 2005. The reclamation escrow accounts are restricted funds and have been classified as Reclamation Deposits on the Consolidated Balance Sheets. In addition, the Absaloka contract mine operator is funding a separate reclamation escrow account that is approximately $4 million as of June 30, 2005.The present value of obligations of certain other customers and the Absaloka contract mine operator has been classified as contractual third party reclamation obligations on the Consolidated Balance Sheets. The Company’s estimated obligation for final reclamation that is not the contractual responsibility of others is $128.1 million (on an undiscounted basis) at June 30, 2005.
Changes in the Company’s asset retirement obligations from January 1, 2005 to June 30, 2005 (in thousands) were:
Asset retirement obligation — beginning of year | $ 140,793 | ||
Accretion | 4,854 | ||
Settlements (final reclamation performed) | (1,732 | ) | |
Loss on settlements | 503 | ||
Asset retirement obligation — June 30, 2005 | $ 144,418 | ||
Royalty Claims
The Company has received demand letters from the Montana Department of Revenue (“DOR”), as agent for the Minerals Management Service (“MMS”) of the U.S. Department of the Interior, asserting underpayment of certain royalties allegedly due in connection with coal produced at the Rosebud Mine. The claims relate to the fees the Company receives to transport coal from the contract delivery point to the customer, certain “take or pay” payments the Company received when its customers did not require coal, and adjustments for certain taxes. The total amount of the claims is approximately $12.4 million, including penalties and interest, which continues to accrue. The Company continues to receive transportation fees and expects the DOR to assert claims for additional underpayment and to issue more demand letters until the appeal process is completed, which could increase the total claims to $35-40 million. The Company believes that the transportation fees and payments are not part of the price of the coal and therefore that the DOR/MMS claims are improper and is vigorously contesting them, first through the administrative appeal process. On March 28, 2005, the MMS denied in part, and granted in part, the Company’s appeal of the pending royalty claims. On April 28, 2005, the Company filed a notice of appeal with the Department of Interior’s Office of Hearings and Appeals. If the appeal is unsuccessful, the Company can bring an action in Federal court. The appeal process may take several years. In the event of a final adverse outcome with DOR and MMS, certain of the Company’s customers are contractually obligated to reimburse the Company for any claims paid plus legal expenses. The Company has not accrued any amount for the claims.
14
Tax Assessments
Halifax County
The ROVA project is located in Halifax County, North Carolina and is the County’s largest taxpayer. In 2002, the County hired an independent consultant to review and audit the property tax returns for the previous five years. In May 2002, the County advised the ROVA project that its returns were being scrutinized for potential underpayment due to undervaluation of property subject to tax. ROVA responded to the County that its valuation was consistent with a preconstruction agreement reached with the County in 1996. In late 2002, the ROVA project received notice of an assessment of $3.2 million for the years 1997 to 2001. Since that date the County has increased the amount of its claim to $5.4 million, which adds tax years 1996, 2002, 2003 and 2004. With penalty and interest, the total amount claimed due by the County is $8.6 million, which amount has been withheld from distributions by the project lender. The ROVA project filed a protest of the assessment for 1996 to 2001 with the Property Tax Commission. On May 26, 2004, the Tax Commission denied the ROVA project’s protest and issued an order sustaining the County’s assessment. The ROVA project appealed the Tax Commission’s decision to the North Carolina Intermediate Court of Appeals on June 24, 2004. On April 20, 2005, the case was heard. The Court has 120 days to reach a decision. The ROVA project also filed a protest of the assessment for 2002 to 2004 with the County Board of Equalization and Review, including a claim for a refund on its 2005 real estate taxes. The Board of Equalization and Review denied the ROVA project’s protest. On July 20, 2005, the ROVA project appealed that decision to the North Carolina Tax Commission.
The term “LG&E” refers to LG&E Energy LLC and its subsidiaries. LG&E has agreed that, if we complete the ROVA acquisition, LG&E will indemnify the ROVA Project for one-half of the taxes, penalties, and interest assessed by Halifax County for the period through December 31, 2003 and for one-half of our reasonable attorneys’ fees and expenses incurred in settling or otherwise resolving Halifax County’s claims for this period. The ROVA project accrued a liability of $4 million for the claims in 2004 of which one-half is the Company’s share.
Rensselaer
Niagara Mohawk Power Corporation (“NIMO”) was party to power purchase agreements with independent power producers, including the Rensselaer project, in which we owned an interest. In 1997, the New York Public Service Commission approved NIMO’s plan to terminate or restructure 29 power purchase contracts. The Rensselaer project agreed to terminate its Power Purchase and Supply Agreement after NIMO threatened to seize the project under its power of eminent domain. NIMO and the Rensselaer project executed a settlement agreement in 1998 with a payment to the project. On February 11, 2003, the North Carolina Department of Revenue notified us that it had disallowed the exclusion of gain as non-business income from the settlement agreement between NIMO and the Rensselaer project. The State of North Carolina has assessed a current tax of $3.5 million, interest of $1.3 million (through 2004), and a penalty of $0.9 million. We have filed a protest. The North Carolina Department of Revenue held a hearing on May 28, 2003. In November 2003, we submitted further documentation to the State to support our position. On January 14, 2005, the North Carolina Department of Revenue concluded that the additional assessment is statutorily correct. On July 27, 2005, the Company responded to the North Carolina Department of Revenue providing additional information. Unless an acceptable settlement can be reached, the Company may pursue a formal hearing with the Department of Revenue and/or appeal the Department’s assessment to the Superior Court of North Carolina. The Company believes its position will be determined to be correct and has accrued no amount for the assessment.
15
McGreevey Litigation
In late 2002, the Company was served with a complaint in a case styled McGreevey et al. v. Montana Power Company et al. in a Montana State court. The plaintiffs are former stockholders of Montana Power who filed their first complaint on August 16, 2001. This was the Plaintiffs’ Fourth Amended Complaint which added Westmoreland as a defendant to a suit against Montana Power Company, various officers of Montana Power Company, the Board of Directors of Montana Power Company, financial advisors and lawyers representing Montana Power Company and the purchasers of some of the businesses formerly owned by Montana Power Company and Entech, Inc., a subsidiary of Montana Power Company. The plaintiffs seek to rescind the sale by Montana Power of its generating, oil and gas, and transmission businesses, and the sale by Entech of its coal business or to compel the purchasers to hold these businesses in trust for the shareholders. The Plaintiffs contend that they were entitled to vote to approve the sale by Entech to the Company even though they were not shareholders of Entech. Westmoreland has filed an answer, various affirmative defenses and a counterclaim against the plaintiffs.
The litigation was transferred to the U.S. District Court in Billings, Montana. On July 12, 2004, the plaintiffs filed a status report with the U.S. District Court. In the status report, the plaintiffs stated that the insurance companies that insure the former officers and directors of Montana Power had agreed to pay $67 million into escrow, pending approval of a settlement agreement and a determination by the bankruptcy court that no other claimant or class of claimants is entitled to any portion of the settlement proceeds. As part of the proposed settlement, the McGreevey plaintiffs would dismiss their claims against us and our subsidiaries, among others. The parties continue to negotiate the terms of the proposed settlement. Regardless of the outcome the Company has a claim for indemnification against Entech if it incurs any losses as a result of the McGreevey litigation. The Company has not accrued any amount for the claims.
Combined Benefit Fund
The Company makes monthly premium payments to the UMWA Combined Benefit Fund (“CBF”), a multiemployer health plan neither controlled nor administered by the Company. In 1996, a Federal Court ordered a decrease in the premiums charged by the CBF as a result of a finding that the formula being used by the government to determine reimbursement for health benefits under the Coal Act had been discontinued and that the actual amounts received by the CBF should be used instead. In connection with a separate case brought by the CBF, the Trustees of the CBF obtained notice of a premium increase on June 10, 2003 for beneficiaries assigned to companies under the Coal Act from the Social Security Administration (“SSA”). The CBF seeks to impose the increase retroactively to 1995 and has imposed a retroactive “catch-up” premium equal to the entire amount alleged to be due for the period from 1995 through October 2003, payable over the twelve months commencing October 2003. The net effect of these assessments increased the Company’s monthly payments to the CBF to $859,000 for the twelve months ending September 2004. The Company paid the higher monthly invoices and is vigorously pursuing its legal remedies. The Company accrued the entire retroactive portion of the CBF premiums in 2003. In late 2004, the parties to this case filed motions for summary judgment and the Company is currently awaiting the Court’s decision. Through September 2003, we paid a monthly premium of approximately $400,000. This amount is recalculated each October. Commencing October 2004, the Company resumed paying approximately $396,000 per month to the CBF.
16
1992 UMWA Benefit Plan Surety Bond
On May 11, 2005, XL Specialty Insurance Company and XL Reinsurance America, Inc. (referred to together as “XL”) filed in the U.S. District Court, Southern District of New York, a Complaint for Declaratory Judgment against Westmoreland Coal Company and named Westmoreland Mining LLC as a co-defendant. The Complaint asks the Court to declare that (1) the plaintiffs have the right to cancel a $21.3 million bond that secures Westmoreland’s obligation to provide benefits to the UMWA 1992 Plan, (2) Westmoreland must immediately pay $21.3 million to XL and (3) after cancellation of the bond, Westmoreland must indemnify XL for all claims, demands, losses and expenses in conjunction with termination of the bond.
It is our position that XL has no right to cancel the bond and, if it chooses to unilaterally cancel the bond, the UMWA Plan Trustees can draw the full amount of bond, which is approximately $21.3 million. We further believe that in the event of such a draw, the Company is under no obligation to reimburse XL for the amount drawn unless the Company has defaulted on its payment obligations relating to the UMWA 1992 Plan. No such default has occurred, nor do we anticipate defaulting on any of our obligations under the UMWA 1992 Plan. Therefore, we will contest vigorously the request by XL for a Declaratory Judgment. In addition, we do not believe that Westmoreland Mining LLC should have been named as a co-defendant, and we do not believe that the plaintiffs have any basis for a claim against Westmoreland Mining LLC. We have also filed a motion asking the court to dismiss on the grounds that New York is not the appropriate venue for the case.
The Company is a party to other claims and lawsuits with respect to various matters in the normal course of business. The ultimate outcome of these matters is not expected to have a material adverse effect on the Company’s financial condition, results of operations or liquidity.
8. | ROVA ACQUISITION |
On August 25, 2004, we signed an Interest Purchase Agreement with a subsidiary of LG&E Energy LLC. In that agreement, the Company agreed to acquire LG&E’s 50% interest in the ROVA project for (1) a cash payment to LG&E at closing of approximately $22 million and (2) the assumption by the Company’s subsidiaries of LG&E’s portion of the ROVA project’s debt. LG&E’s share of this debt is approximately $103 million at December 31, 2004. In addition, the Company must post cash or letters of credit with a value of approximately $9.8 million to replace LG&E’s portion of the ROVA project’s debt service reserve accounts. The purchase price will be reduced by the amount of any distributions LG&E receives from the ROVA project between August 2004 and closing. Based on distributions LG&E received through August 1, 2005, the cash payment to LG&E would be reduced to $12.0 million. In November 2004, Dominion Virginia Power, the purchaser of the electricity generated by the ROVA Project, asserted that it had a right of first refusal with respect to LG&E’s interest. The Company was negotiating with Dominion Virginia Power to address its claim when, on March 24, 2005, Dominion Virginia Power filed a Petition for Declaratory Judgment in Virginia in the Circuit Court of the City of Richmond seeking an order validating its alleged first right of refusal under the power purchase agreement to acquire LG&E’s partnership interest in the ROVA project. On April 29, 2005, the ROVA project filed a demurrer in the Circuit Court of the City of Richmond requesting the Petition for Declaratory Judgment be denied. A hearing on the demurrer was held on July 19, 2005. A ruling by the court on the demurrer is not expected before the end of August 2005 and could take several months. The Interest Purchase Agreement has not been terminated or amended and remains in effect pending resolution of Dominion Virginia Power’s claim and receipt of the remaining consents necessary to complete the transaction. The Company and LG&E are currently in negotiations with Dominion Virginia Power in an effort to resolve this dispute.
17
9. | RECENT ACCOUNTING PRONOUNCEMENTS |
In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” or SFAS 123R, which replaces SFAS No. 123 and supersedes APB Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005, with early adoption encouraged. In April 2005, the FASB changed the effective date of SFAS 123R to the first interim or annual period after December 15, 2005. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition.
As a result the Company will adopt SFAS 123R on January 1, 2006. The Company has not yet determined the method of adoption or the effect of adopting SFAS 123R, including whether the adoption will result in charges to net income that are similar to the current pro forma disclosures under SFAS No. 123 (see Note 4 to Consolidated Financial Statements). The Company must first determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost, and the transition method to be used at the date of adoption. The effect on net income and earnings per share in the periods following adoption of SFAS No. 123R are expected to be consistent with our pro forma disclosure under SFAS No. 123, except that estimated forfeitures will be considered in the calculation of compensation expense under SFAS No. 123R. The effect on net income and earnings per share going forward will depend upon the number and fair value of options granted in future years.
In November 2004, the FASB issued SFAS No. 151, “Inventory Costs: An Amendment of ARB 43, Chapter 4” (SFAS No. 151). This statement clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). It requires that amounts be recognized as current period charges. In addition, this statement requires that allocation of fixed production overheads to the costs of inventory be based on the normal capacity of the production facilities. The provisions of this statement are effective for fiscal years beginning after June 15, 2005. The Company does not expect this guidance to have a material impact on its consolidated results of operations and financial condition.
In March 2005, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 04-6 “Accounting for Stripping Costs in the Mining Industry” (EITF 04-6). This guidance defines stripping costs as variable production costs that should be considered a component of mineral inventory cost subject to the provisions of ARB 43. According to the provisions of ARB 43, all costs of producing the reserves should be considered costs of the extracted minerals under a full absorption costing system and recognized as a component of cost of sales-coal in the same period as the related revenue. The Company classifies stripping costs as overburden removal costs and is evaluating the impact of adopting EITF 04-6 and has not yet determined the effect adoption will have on its consolidated results of operations and financial position. The provisions of EITF 04-6 are effective for fiscal years beginning after December 15, 2005.
18
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Material Changes in Financial Condition from December 31, 2004 to June 30, 2005
Forward-Looking Disclaimer
Throughout this Form 10-Q, we make statements which are not historical facts or information and that may be deemed “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements include, but are not limited to, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations. For example, words such as “may,” “will,” “should,” “estimates,” “predicts,” “potential,” “continue,” “strategy,” “believes,” “anticipates,” “plans,” “expects,” “intends,” and similar expressions are intended to identify forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties and other factors, which may cause the actual results, levels of activity, performance or achievements, or industry results, to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others, the following: general economic and business conditions; health care cost trends; the cost and capacity of the surety bond market; the Company’s ability to manage growth and significantly expanded operations; the ability of the Company to implement its growth and development strategy; the Company’s ability to pay the preferred stock dividends that are accumulated but unpaid; the Company’s ability to retain key senior management; the Company’s access to financing; the Company’s ability to maintain compliance with debt covenant requirements; the Company’s ability to achieve anticipated cost savings and profitability targets; the Company’s ability to successfully identify new business opportunities; the Company’s ability to negotiate profitable coal contracts, price reopeners and extensions; the Company’s ability to predict or anticipate commodity price changes; the Company’s ability to maintain satisfactory labor relations; changes in the industry; competition; the Company’s ability to utilize its income tax net operating losses; the ability to reinvest cash, including cash that has been deposited in reclamation accounts, at an acceptable rate of return; weather conditions; the availability of transportation; price of alternative fuels; costs of coal produced by other countries; the demand for electricity; the performance of the ROVA Project and the structure of the ROVA Project’s contracts with its lenders and Dominion Virginia Power; our ability to complete the acquisition of the portion of the ROVA project that we do not currently own; the effect of regulatory and legal proceedings; environmental issues, including the cost of compliance with existing and future environmental requirements; the claims between the Company and Montana Power; the risk factors set forth below; and the other factors discussed in Items 1, 2, 3 and Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission. 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.
19
Overview
We are an energy company. We mine coal, which is used to produce electric power, and we own interests in power-generating plants. All of our five mines supply baseloaded power plants. Several of these power plants are located adjacent to our mines and we sell virtually all our coal under long-term contracts. Consequently, our mines enjoy relatively stable demand and pricing compared to competitors who sell more of their production on the spot market.
The Company’s coal market strategy is based on long-term sales agreements with a limited number of customer plants rather than spot market sales. This strategy reduces the Company’s exposure to market volatility, delivering relatively stable prices and sales levels, but also limits the Company’s ability to immediately capture market price increases. However, certain sales agreements are currently scheduled for renewal or renegotiation in the near term. Approximately 5.5 million tons, or 18%, of the Company’s total sales volume, are scheduled to be renewed and/or renegotiated over the next six months, with most of that volume benchmarked to market prices for coal mined in the Southern Powder River Basin.
We currently own a 50% interest in the ROVA I and II coal-fired plants, which have a total generating capacity of 230 MW. We also retain a 4.49% interest in the gas-fired Fort Lupton Project, which has a generating capacity of 290 MW and provides peaking power to the local utility. The ROVA Project is baseloaded and supplies power pursuant to a long-term contract.
Challenges
We believe that our principal challenges today include the following:
• | managing the costs and production of our operations, and reaching a new sales agreement at the Jewett Mine; |
• | inflation in medical costs and potentially longer life expectancies, which can increase our expense for active employees and heritage health benefit costs; |
• | integration of new personnel, especially in the area of finance and accounting; |
• | implementation of a new company-wide computer system to support our mining and corporate segments; |
• | maintaining and collateralizing, where necessary, our Coal Act and reclamation bonds; |
• | new environmental regulations, which have the potential to significantly reduce sales from our mines; and |
• | claims for potential taxes and royalties asserted by various governmental entities. |
We discuss these issues, as well as the other challenges we face, elsewhere in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, and under “Risk Factors.”
Critical Accounting Estimates and Related Matters
Our discussion and analysis of financial condition, results of operations, liquidity and capital resources is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require that we make estimates and judgments. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. Actual results may differ materially from these estimates.
20
We have made significant judgments and estimates in connection with the following accounting matters. Our senior management has discussed the development, selection and disclosure of the accounting estimates in the section below with the Audit Committee of our Board of Directors.
In connection with our discussion of these critical accounting matters, and in order to reduce repetition, we also use this section to present information related to these judgments and estimates.
Postretirement Benefits and Pension Obligations
Our most significant long-term liability is the obligation to provide postretirement medical benefits, pension benefits, workers’ compensation and pneumoconiosis (black lung) benefits. We provide these benefits to our current and former employees and their dependents.
Estimates and Judgments |
We estimate the total amount of these obligations with the help of third party professionals using actuarial assumptions and information. Our estimate is sensitive to judgments made about the discount rate, about the rate of inflation in medical costs, and about mortality rates.
Related Information |
The present value of our actuarially determined liability for postretirement medical costs increased approximately $3.5 million between December 31, 2004 and June 30, 2005. Actuarial valuations project that our retiree health benefit costs may continue to escalate in the next few years and then will decline to zero over the next approximately sixty years as the number of eligible beneficiaries declines. We incurred cash costs of $4.1 million and $9.1 million for postretirement medical costs during the second quarter of 2005 and six months of 2005, respectively. This compares to cash costs of $6.7 million and $14.0 million for postretirement medical costs during the second quarter of 2004 and six months of 2004, respectively. We expect to incur approximately $21 million of these costs in all of 2005 compared to $25.1 million paid in 2004 (including $3.5 million of the Combined Benefit Fund’s retroactive assessment, which was paid in 2004 pending the outcome of that litigation).
Our worker’s compensation liability is recorded on an undiscounted basis on the balance sheet. We incurred cash costs of $0.6 million for workers’ compensation benefits during the first six months of 2005 compared to $0.9 million in 2004. We expect to incur lower cash costs for workers’ compensation benefits in 2005 than we did in 2004 and expect that amount to decline over time. We anticipate that these costs will decline because we are no longer self-insured for workers’ compensation benefits and have had no new claimants since 1995. The Company incurred a $3.2 million non-cash charge for actuarial adjustments to the workers’ compensation liability for the Company’s former Virginia Division in the fourth quarter of 2004. The Company closed the Virginia Division in 1995. The pool of former Virginia Division employees eligible to receive workers’ compensation has been fixed for some time, and the Company’s obligation to pay lost wages has expired; however, the Company incurred this charge because its obligation to pay medical benefits has continued longer and at higher levels than originally forecast by the Company’s actuaries. The Company continues to monitor these costs closely and is reviewing the accounting policy and actuarial methodology for appropriateness and effectiveness.
We do not pay pension or black lung benefits directly. These benefits are paid from trusts that we established and funded. As of June 30, 2005, our pension trusts are underfunded as a result of lower interest rates which increased the present value of the remaining obligations, and we expect to contribute approximately $1.8 million to these trusts in 2005. Of that amount, $1.1 million was contributed in the first six months. As of June 30, 2005, our black lung trust is overfunded by $3.2 million and we do not expect to be required to make additional contributions to this trust in the foreseeable future.
21
One of the estimates we have made relates to the implementation of the Medicare Prescription Drug Improvement and Modernization Act of 2003 (“Medicare Reform Act”). As provided for under that Act, we recognized a benefit to our anticipated future prescription drug costs for retirees and their dependents in 2003 based on a coordinated implementation of the Medicare Reform Act and our existing benefit programs, including the UMWA 1992 Plan. Earlier this year the government issued regulations which make the subsidy approach the only practical alternative given our existing programs. We are currently reviewing the impact of these regulations on our total prescription drug obligation. The subsidy approach will limit our annual benefit to 28% (to a maximum of $1,330/participant) of actual costs. We expect that a revised actuarial analysis could result in a reduction of approximately $5 million in the projected net present value benefit to us from the Medicare Reform Act and a higher resultant future annual expense than we had anticipated with a coordinated benefits approach.
Asset Retirement Obligations, Reclamation Costs and Reserve Estimates
Asset retirement obligations primarily relate to the closure of mines and the reclamation of land upon cessation of mining. We account for reclamation costs, along with other costs related to mine closure, in accordance with Statement of Financial Accounting Standards No. 143 – Asset Retirement Obligations, or SFAS No. 143, which we adopted on January 1, 2003. This statement requires us to recognize the fair value of an asset retirement obligation in the period in which we incur that obligation. We capitalize the present value of our estimated asset retirement costs as part of the carrying amount of our long-lived assets.
The liability “Asset retirement obligations” on our consolidated balance sheet represents our estimate of the present value of the cost of closing our mines and reclaiming land that has been disturbed by mining. This liability increases as land is mined and decreases as reclamation work is performed and cash expended. The asset, “Property, plant and equipment – capitalized asset retirement costs,” remains constant until new liabilities are incurred or old liabilities are re-estimated. We estimate the future costs of reclamation using standards for mine reclamation that have been established by the government agencies that regulate our operations as well as our own experience in performing reclamation activities. These estimates may change. Developments in our mining program also affect this estimate by influencing the timing of reclamation expenditures.
We amortize our acquisition costs, development costs, capitalized asset retirement costs and some plant and equipment using the units-of-production method and estimates of recoverable proven and probable reserves. We review these estimates on a regular basis and adjust them to reflect our current mining plans. The rate at which we record depletion also depends on the estimates of our reserves. If the estimates of recoverable proven and probable reserves decline, the rate at which we record depletion increases. Such a decline in reserves may result from geological conditions, coal quality, effects of governmental, environmental and tax regulations, and assumptions about future prices and future operating costs.
Deferred Income Taxes
Our net income is sensitive to estimates we make about our ability to use our Federal net operating loss carryforwards, or NOLs.
22
As of December 31, 2004 we had approximately $176 million of NOLs. These NOLs expire at various dates through 2023. When we have taxable income, we can use our NOLs to shield that income from regular U.S. Federal income tax. Our ability to use our NOLs thus depends on all the factors that determine taxable income, including operational factors, such as new coal sales, and non-operational factors, such as changes in heritage health benefit costs. Under Federal tax law, our ability to use our NOLs would be limited if we had a “change of ownership” within the meaning of the Federal tax code.
Our NOLs are one of our deferred income tax assets. We have reduced our deferred income tax assets by a valuation allowance. The valuation allowance is primarily an estimate of the deferred tax assets that may not be realized in future periods. On a quarterly and annual basis, we estimate how much of our NOLs we will be able to use to shield future taxable income and make corresponding adjustments in the valuation allowance. The estimate of future taxable income and use of the NOLs may change the valuation allowance in connection with an updated assessment of the status of the Company's business plan.
If we increase our estimated utilization of NOLs, we decrease the valuation allowance, increase our net deferred income tax assets and recognize an income tax benefit in earnings. If we decrease our estimated utilization of NOLs, we increase the valuation allowance, decrease our net deferred income tax assets and increase income tax expense. These changes can materially affect our net income and our assets. In the quarter ended June 30, 2005, for example, we increased the valuation allowance by $0.3 million because of a decrease in this quarter’s estimate of the expected amount of Federal net operating losses to be used in this and future years partially due to an expected reduction in the projected benefit to us from the Medicare Reform Act. We also made other adjustments in our net deferred tax assets. As a result of these estimates and adjustments and changes in temporary differences between book and tax accounting, our net deferred income tax assets increased from $84.7 million at December 31, 2004 to $89.3 million at June 30, 2005, and we recognized an income tax benefit of $1.6 million.
We previously reported that we expect that our alternative minimum income tax net operating loss carryforwards would be fully utilized in 2005, and that AMT payments in 2006 and beyond will increase significantly. The Energy Bill, which was signed into law on August 8, 2005, includes production tax credits available to us beginning January 1, 2006 for tons sold at our Absaloka Mine from coal reserves owned by the Crow Indians. We expect these tax credits will significantly reduce our liability for AMT in 2006 and beyond, but have not yet completed a full assessment of the value that the Company could receive.
Liquidity and Capital Resources
In 2004, Westmoreland Mining LLC borrowed an additional $35 million from its lenders pursuant to what we call the add-on facility. The add-on facility was intended to permit Westmoreland Mining to undertake certain significant capital projects in the near term without adversely affecting cash available to us. We believe that Westmoreland Mining’s add-on facility substantially improves our near term liquidity. In addition, even though the requirements, including debt service requirements, of Westmoreland Mining’s basic term loan agreement, sometimes referred to as our acquisition debt, restrict our access to some of Westmoreland Mining’s cash, Westmoreland Mining itself provides significant liquidity.
Cash provided by operating activities was $7.5 million for the six months ended June 30, 2005, compared to the cash used of $2.9 million for the six months ended June 30, 2004. Cash from operations in 2005 compared to 2004 increased primarily because of lower distributions from the ROVA project in 2004 as a result of the project’s lenders withholding cash for the Halifax County tax dispute. Working capital was $19.4 million at June 30, 2005 compared to $18.9 million at December 31, 2004. The increase in working capital resulted primarily from an increase in trade receivables, inventories and deferred overburden removal costs partially offset by an increase in trade payables due to normal timing differences and by an increase in the current portion of asset retirement obligations.
23
We used $14.1 million of cash in investing activities in the six months ended June 30, 2005 and $11.3 million in the six months ended June 30, 2004. Cash used in investing activities in 2005 included $12.3 million of additions to property, plant and equipment for mine equipment and development projects and investment in our a new corporate-wide software system. Cash used in investing activities in 2005 also included an increase of $2.3 million in restricted accounts pursuant to Westmoreland Mining’s term loan agreement and required collateral for surety bonds. In 2004, additions to property and equipment using cash were $5.7 million, and increases in restricted cash accounts were $5.7 million.
Cash of $4.6 million was provided by financing activities in the six months ended June 30, 2005 primarily due to $9.5 million borrowings of revolving lines of credit reduced by $4.7 million used for the repayment of long-term debt. Cash provided from financing activities of $20.1 million in the first six months of 2004 included $18.6 million from new borrowing of long-term debt, net of debt issuance costs. We used cash of $6.0 million for repayment of long-term and revolving debt in 2004.
Consolidated cash and cash equivalents at June 30, 2005 totaled $9.1 million, including $6.5 million at Westmoreland Resources, and $2.9 million at our captive insurance subsidiary. Consolidated cash and cash equivalents at December 31, 2004 totaled $11.1 million, including $4.6 million at Westmoreland Mining, $4.1 million at Westmoreland Resources, and $2.5 million at the captive insurance subsidiary. The cash at Westmoreland Mining is available to us through quarterly distributions, as described below. The cash at Westmoreland Resources is available to us through dividends. In addition, we had restricted cash and bond collateral, which were not classified as cash or cash equivalents, of $33.1 million at June 30, 2005 and $32.7 million at December 31, 2004. The restricted cash at June 30, 2005 included $22.6 million in Westmoreland Mining’s debt service reserve and long-term prepayment accounts. At June 30, 2005, our reclamation, workers’ compensation and postretirement medical cost obligation bonds were collateralized by interest-bearing cash deposits of $11.5 million, which amounts we have classified as non-current assets. In addition, we had accumulated reclamation deposits of $57.0 million at June 30, 2005, which we received from customers of the Rosebud Mine to pay for reclamation. We also had $12.9 million in interest-bearing debt reserve accounts for the ROVA project at June 30, 2005. This cash is restricted as to its use and is classified as part of our investment in independent power projects.
Westmoreland Mining’s term loan agreement restricts Westmoreland Mining’s ability to make distributions to Westmoreland Coal Company from ongoing operations. Until Westmoreland Mining has fully paid the original acquisition debt, which is scheduled for December 31, 2008, Westmoreland Mining may only pay Westmoreland Coal Company a management fee and distribute to Westmoreland Coal Company 75% of Westmoreland Mining’s surplus cash flow. Westmoreland Mining is depositing the remaining 25% into an account that will fund the $30 million balloon payment due December 31, 2008. The add-on facility only restricts distributions to the extent funds are needed to maintain a debt service reserve equal to the next six months principal and interest payments.
Westmoreland Mining has a revolving credit facility which expires in April 2007 of $12 million. As of June 30, 2005, $10.0 million of the facility was available to borrow.
As of June 30, 2005, Westmoreland Coal Company had $6.5 million of its $14.0 million revolving line of credit available to borrow.
On July 28, 2004, we filed a registration statement for a possible rights offering. If the registration statement becomes effective, it would permit holders of our common stock to purchase additional shares of common stock. As stated in the registration statement, the additional equity capital would be used to support our growth and development strategy and for general corporate purposes.
24
Liquidity Outlook
We described certain liquidity comparisons in the Liquidity Outlook section of the Annual Report on Form 10-K for the year ended December 31, 2004. All of the items described in that report continue to be important to us.
Jewett Mine Supply Contract
Texas Westmoreland Coal Co. and Texas Genco are party to a lignite supply agreement that expires in 2015 and that provides annual price redeterminations based on an equivalent cost of Southern Powder River Basin (SPRB) coal at the Limestone Electric Generating Station. In January 2004, the parties agreed to fix a price for the period 2004 through 2007, with pricing thereafter to be determined pursuant to the underlying contract. Subsequent dramatic and unexpected increases in commodity costs, including costs for diesel fuel and steel, among other items, rendered the four-year fixed price agreement uneconomic. At the same time, market prices for SPRB coal and associated rail rates have also increased dramatically. Texas Westmoreland and Texas Genco have been negotiating revisions to the fixed price agreement and potentially the underlying long-term agreement, but the Company cannot predict whether an agreement will be reached that returns the Jewett Mine to a stable and satisfactory level of financial performance. Failure to reach a new agreement with Texas Genco could have a material adverse effect on Texas Westmoreland's financial condition before the end of 2007, when substantial price increases could be expected to take effect under the terms of the current contract.
Growth and Development
We describe in Note 8 to the Consolidated Financial Statements of this Form 10-Q the possible acquisition of the ROVA interest from LG&E and the financial implications of its purchase in our Annual Report on Form 10-K for the year ended December 31, 2004 under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Implications of the ROVA Acquisition.”
Continued growth remains an important part of our strategy. The application for an air permit for our Gascoyne Project in North Dakota was filed in May 2004 and a completeness determination was received in July 2004. The North Dakota Department of Health (Department of Health) issued a draft air permit on March 29, 2005. The Department of Health started a 30 day public comment period on April 2, 2005 that included a public hearing on April 21. The public comment period concluded on May 1, 2005. The Department of Health issued the final air permit in June 2005. The Company also continues to identify and evaluate other potential growth opportunities in the coal and independent power sectors.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements within the meaning of the rules of the Securities and Exchange Commission.
25
Quarter Ended June 30, 2005 Compared to Quarter Ended June 30, 2004.
Coal Operations. Coal sold was 7.3 million tons in the second quarter ended June 30, 2005 compared to 6.7 million tons in the second quarter of 2004. The Rosebud and Jewett Mines increased sales while there was lower production at the Beulah Mine related to reduced sales to the Heskett Station. In the second quarter of 2004, the arbitration award for the price reopener with the owners of Colstrip Units 1&2 resulted in the recognition of additional revenue of $16.3 million for coal shipped from July 30, 2001 to May 31, 2004. Production taxes and royalties on those revenues totaled $5.1 million. Excluding the arbitration award at Colstrip Units 1&2 from the second quarter of 2004, our overall revenue has increased year over year for the second quarter due to an increase in tons sold, and higher contract prices, including the increased price under the Rosebud Mine’s contract with Colstrip Units 1&2, which was redetermined in the second quarter 2004. Revenues also increased because arrangements in place allowed the Company’s mining operations to recover portions of cost increases for commodities. The Company’s coal sales contracts generally protect our operations against cost inflation, either through direct pass-through or through index adjustments, and we are in the process of negotiating provisions to cover commodity price risk under certain contracts where such provisions have been temporary or absent. Cost of sales increased for the second quarter of 2005 compared to the comparable period in 2004 primarily as a result of more tons produced, increased commodity prices and higher stripping ratios.
The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods for actual results as reported and on a pro forma basis (which excludes the impact of the Colstrip arbitration award in second quarter 2004):
Quarter Ended June 30, | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Actual | Pro forma | ||||||||||
2005 | 2004 | Change | 2004 | Change* | |||||||
Revenues - thousands | $ | 85,701 | $ | 87,020 | (2)% | $ | 70,720 | 21 | % | ||
Volumes - millions of equivalent coal tons | 7.252 | 6.677 | 9% | ||||||||
Cost of sales - thousands | $ | 71,350 | $ | 66,115 | 8% | $ | 61,015 | 17 | % |
* Change represents change between 2005 Actual amounts and 2004 Pro forma amounts.
The Company’s business is subject to weather and some seasonality. The power-generating plants that we supply typically schedule their regular maintenance for the spring and fall seasons.
Depreciation, depletion and amortization increased to $4.7 million in the second quarter of 2005 compared to $3.6 million in 2004’s second quarter. The increase is primarily related to increased capital expenditures at the mines for both continued mine development and the replacement of mining equipment and increased amortization of capitalized asset retirement costs.
26
Independent Power. Our equity in earnings from independent power operations increased to $3.5 million in the second quarter 2005 from $1.7 million in the quarter ended June 30, 2004. The second quarter of 2004 included a $2.0 million charge recorded for retroactive personal property taxes contingently due to Halifax County, North Carolina, partially offset in 2005 by decreased generation and higher operating and maintenance expenses. For the quarters ended June 30, 2005 and 2004, the ROVA project produced 369,000 and 397,000 megawatt hours, respectively, and achieved average capacity factors of 81% and 87%, respectively. Both periods had scheduled maintenance outages, resulting in lower capacity factors for both periods. In addition, the second quarter of 2005 included almost 7 days of forced outages due to tube leaks in the plant which reduced the capacity factor and related revenues. We recognized $14,000 in equity earnings in second quarter 2005, compared to $23,000 in the quarter ended June 30, 2004 from our 4.49% interest in the Ft. Lupton project.
Costs and Expenses.Selling and administrative expenses increased to $8.5 million in the quarter ended June 30, 2005 compared to $7.0 million in the quarter ended June 30, 2004. The increase is primarily a result of settlement of the Entech litigation at a cost of $1.2 million plus legal fees partially offset by lower long-term incentive plan costs. Long-term incentive compensation decreased $1.1 million in second quarter 2005 compared to the three months ended June 30, 2004 because the price of the Company’s stock decreased in the second quarter of 2005 compared to our peer companies. In general, this expense increases or decreases as the market price of the Company’s common stock increases or decreases.
Heritage health benefit costs were $7.7 million in both the second quarter of 2005 and the second quarter of 2004 with both periods experiencing a decrease in the amount by which the black lung trust is overfunded as a result of increased interest rates that decreased the market value of the trust’s assets.
Interest expense was $2.6 million for both the three months ended June 30, 2005 and 2004. Interest associated with the larger amount of outstanding debt as a result of Westmoreland Mining’s add-on facility in the fourth quarter of 2004 was mostly offset by the lower interest payments due to the pay-down of the acquisition financing obtained during 2001 in connection with the purchase of the Montana Power (Entech) and Knife River coal operations and the increased use of the Company’s revolving credit lines. Interest income decreased in 2005 due to lower short-term investments earning interest although there were larger restricted cash and surety bond collateral balances that are invested.
As a result of the acquisitions we completed in the spring of 2001, the Company recognized a $55.6 million deferred income tax asset in April 2001, which assumed that a portion of previously unrecognized net operating loss carryforwards would be utilized because of the projected generation of future taxable income. That amount has grown over the years as it is estimated more net operating losses will be used. The deferred tax asset increased to $89.3 million as of June 30, 2005 from $84.7 million at December 31, 2004 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. The current income tax expense for the second quarter of 2005 represents income tax obligations for State income taxes and for Federal alternative minimum tax, partially reduced by 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 deferred tax benefit of $1.6 million recognized in the second quarter of 2005 is net of a $1.0 million expense caused by an increase in the valuation allowance. This expense reflects the full estimated increase for the year 2005 resulting from a decrease in the amount of Federal net operating loss carryforwards we expect to utilize based on this quarter’s (1) financial results, (2) projections of 2005 taxable income and (3) assumptions relating to estimates of future taxable income.
Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004
Coal Operations. Coal revenues increased to $171.8 million for the six months ended June 30, 2005 from $164.2 million for the six months ended June 30, 2004 primarily as a result of an increase in tons sold from 14.1 million to 14.7 million and higher prices even including the Colstrip Units 1 & 2 arbitration award in 2004 discussed above. The increase in tons sold in 2005 came from new or extended sales contracts at the Rosebud mine. Cost of sales increased for the six months of 2005 compared to 2004 primarily as a result of increased tons produced, commodity prices and higher stripping ratios. In 2005, very difficult mining conditions at the Beulah Mine and unusually heavy rainfall there increased costs. Costs in 2004 included unplanned repairs to a primary dragline, a customer outage that extended beyond its planned duration and weather related production interruptions at the Jewett Mine.
27
The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods for actual results as reported and on a pro forma basis (which excludes the impact of the Colstrip arbitration award in the first six months of 2004):
Six Months Ended June 30, | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Actual | Pro forma | ||||||||||
2005 | 2004 | Change | 2004 | Change* | |||||||
Revenues - thousands | $ | 171,800 | $ | 164,152 | 5% | $ | 147,852 | 16 | % | ||
Volumes - millions of equivalent coal tons | 14.699 | 14.123 | 4% | ||||||||
Cost of sales - thousands | $ | 139,108 | $ | 126,318 | 10% | $ | 121,218 | 15 | % |
* Change represents change between 2005 Actual amounts and 2004 Pro forma amounts.
Depreciation, depletion and amortization increased to $9.5 million in the first six months of 2005 compared to $7.4 million in the first six months of 2004. The increase is primarily related to increased capital expenditures at the mines for both continued mine development and the replacement of mining equipment and increased amortization of capitalized asset retirement costs.
Independent Power.Our equity in earnings from the independent power projects increased to $8.6 million in the first six months of 2005 from $7.1 million for the six months ended June 30, 2004. For the six months ended June 30, 2005 and 2004, the ROVA projects produced 811,000 and 853,000 megawatt hours, respectively, and achieved capacity factors of 89% in 2005 and 93% in 2004. The lower capacity factor in 2005 was discussed above in the quarterly results. In 2004, equity in earnings was reduced by the $2.0 million charge for contested retroactive Halifax County personal property tax assessments. In 2005, the ROVA I and II plants had shorter than scheduled outages for planned repairs that improved the capacity factor, but they experienced unscheduled outages for unplanned repairs. We recognized $225,000 in equity earnings in the first six months of 2005, compared to $188,000 in the first six months of 2004 from our 4.49% interest in the Ft. Lupton project.
Costs and Expenses. Selling and administrative expenses were $14.9 million for the six months ended June 30, 2005 compared to $14.7 million for the six months ended June 30, 2004. The 2005 period included the costs of the Entech settlement and litigation previously discussed. However, as a result of a decrease in price of the Company’s common stock in the first six months of 2005, our long-term incentive performance unit plan resulted in a benefit of $2.2 million compared to an expense of $0.2 million in 2004. Legal fees associated with the Company’s legal contingencies, including the arbitration with the owners of Colstrip Units 1 & 2, were higher in 2004.
Heritage health benefit costs were higher in the first six months of 2005 than in the comparable six months in 2004 due to an increase in actuarially determined costs for postretirement medical plans and a greater decrease in the market value of the black lung trust assets as a result of increased interest rates.
28
Interest expense was $5.2 million and $5.0 million for the six month periods ended June 30, 2005 and 2004, respectively. Interest associated with the increased debt outstanding from the Westmoreland Mining add-on facility and borrowing using the Company’s revolving credit facilities was partially offset by the lower interest payments on the acquisition financing obtained during 2001. Interest income decreased in 2005 in spite of larger balances in our restricted cash and surety bond collateral accounts because 2004 included $700,000 in interest relating to the Colstrip Units 1 & 2 arbitration decision.
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 2005 and 2004 relate to obligations for State income taxes and Federal alternative minimum tax. During the first six months of 2005, the deferred tax benefit of $4.4 million includes a $1.5 million benefit caused by a reduction in the valuation allowance resulting from an increase in the amount of Federal net operating loss carryforwards we expect to utilize before their expiration.
Other Comprehensive Income.The other comprehensive income of $194,000, net of income taxes of $129,000, recognized during the six months ended June 30, 2005 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 the other comprehensive income of $303,000, net of income taxes of $202,000, for the six months ended June 30, 2004.
RISK FACTORS
In addition to the trends and uncertainties described in Items 1 and 3 of our Annual Report on Form 10-K for the year ended December 31, 2004 and elsewhere in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, we are subject to the risks set forth below.
Our coal mining operations are inherently subject to conditions that could affect levels of production and production costs at particular mines for varying lengths of time and could reduce our profitability.
Our coal mining operations are all surface mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production and increase the cost of mining at particular mines for varying lengths of time and negatively affect our profitability. These conditions or events include:
• | unplanned equipment failures, which could interrupt production and require us to expend significant sums to repair our capital equipment, including our draglines, the large machines we use to remove the soil that overlies coal deposits; |
• | geological conditions, such as variations in the quality of the coal produced from a particular seam, variations in the thickness of coal seams and variations in the amounts of rock and other natural materials that overlie the coal that we are mining; and |
• | weather conditions. |
Examples of recent conditions or events of these types include the following:
• | In the first quarter of 2004, electrical components on the dragline at our Savage Mine failed. This reduced overburden removal and increased costs at that mine for a period of 10 1/2 days while the dragline was being repaired. |
• | In the second quarter of 2005, our Beulah Mine experienced unusually heavy rainfall and in fact had record rainfall in June that adversely impacted overburden stability and resulted in highwall and spoil sloughage, a condition in which the side of the pit partially collapses and must be stabilized before mining can continue. Unstable conditions in the pits impacted dragline operations at that mine for a period of 5 days. This resulted in a reduction in coal production during the quarter. |
29
• | A dragline at Jewett experienced a mechanical failure this July that will take the machine out of service for approximately two weeks. |
• | In the second quarter of 2004, our Jewett Mine received approximately 93% more rain than normal, impeding production. |
Our revenues and profitability could suffer if our customers reduce or suspend their coal purchases.
In 2004, we sold approximately 98% of our coal under long-term contracts and about three-fourths of our coal under contracts that obligate our customers to purchase all or almost all of their coal requirements from us, or which give us the right to supply all of the plant’s coal, lignite or fuel requirements. Three of our contracts, with the owners of the Limestone Electric Generating Station, Colstrip Units 3&4 and with Colstrip Units 1&2, accounted for 26%, 22% and 16%, respectively, of our coal revenues in 2004. (The contract with the owners of Colstrip Units 1&2 accounted for this percentage of our 2004 revenues because we received, in 2004, an arbitration award that covered coal delivered to Colstrip Units 1&2 from July 2001.) Interruption in the purchases by or operations of our principal customers could significantly affect our revenues and profitability. Unscheduled maintenance outages at our customers’ power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. Four of our five mines are dedicated to supplying customers located adjacent to or near the mines, and these mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.
Disputes relating to our coal supply agreements could harm our financial results.
From time to time, we may have disputes with customers under our coal supply agreements. These disputes could be associated with claims by our customers that may affect our revenue and profitability. Any dispute that resulted in litigation could cause us to pay significant legal fees, which could also affect our profitability.
We may not be able to complete the ROVA acquisition.
In August 2004, we agreed to acquire from LG&E the 50% interest in the ROVA Project that we do not currently own. In November 2004, Dominion Virginia Power asserted that it had a right of first refusal with respect to LG&E’s interest in this project, and in March 2005, Dominion Virginia Power filed a Petition for Declaratory Judgment in the Circuit Court of the City of Richmond, Virginia, seeking an order validating its alleged first right of refusal. In view of Dominion Virginia Power’s claim, there can be no assurance that we will be able to acquire LG&E’s interest in the ROVA Project.
Even if we are able to resolve the claim of Dominion Virginia Power, the completion of the ROVA transaction is subject to the following conditions specified in our Interest Purchase Agreement with LG&E:
• | Both we and LG&E must have performed and complied with, in all material respects, the obligations and covenants that we and LG&E are required to perform and comply with prior to the closing. |
• | Our representations and warranties, and the representations and warranties of LG&E, must be true and correct in all material respects on the closing date. |
30
• | Since August 25, 2004, there must not have been a material adverse effect on the assets, business, condition, or results of operations of the partnership that owns the ROVA Project; the condition, use, or operation of the ROVA Project itself; the payments owed to the ROVA Project by Dominion Virginia Power under the power purchase agreement; or LG&E’s 50% interest in the ROVA Project. |
• | We and LG&E must have received all necessary consents to the transaction from all regulatory authorities and third parties, including the consents of the lenders to the ROVA Project. |
• | We must have obtained replacement insurance that satisfies the insurance requirements of the ROVA Project’s credit agreement with its lenders. |
• | LG&E and its affiliates must have been released from their obligations under the ROVA Project’s existing letters of credit, and the beneficiaries of those letters of credit must not have drawn under them. |
The closing of the ROVA acquisition is also subject to other customary conditions.
Dominion Virginia Power’s alleged right of first refusal is pending in a court proceeding, and there can be no assurance that we will prevail on this issue. In addition, many of the conditions to the closing of the ROVA acquisition are beyond our control, and there can be no assurance that those conditions will be satisfied.
We are a party to numerous legal proceedings, some of which, if determined unfavorably to us, could result in significant monetary damages.
We are a party to several legal proceedings, which are described more fully in our Annual Report on Form 10-K for the year ended December 31, 2004 under Item 3 – “Legal Proceedings”, and in Note 7 (“Contingencies”) to our Consolidated Financial Statements in this Quarterly Report on Form 10-Q. Adverse outcomes in some or all of the pending cases could result in substantial damages against us or harm our business.
We currently own a 50% interest in the ROVA Project, which is located in Halifax County, North Carolina, and we have agreed to purchase the 50% interest that we do not currently own. Halifax County asserts that the ROVA Project owes $8.6 million in back taxes, penalties and interest. If we complete the ROVA acquisition, LG&E has agreed to indemnify the ROVA Project for one-half of this amount.
We may not be able to manage our expanding operations effectively, which could impair our profitability.
At the end of 2000, we owned one mine and employed 31 people. In the spring of 2001, we acquired the Rosebud, Jewett, Beulah and Savage Mines from Entech and Knife River Corporation, and at the end of 2004, we employed 943 people. This growth has placed significant demands on our management as well as our resources and systems. One of the principal challenges associated with our growth has been, and we believe will continue to be, our need to attract and retain highly skilled employees and managers. In the second quarter of 2005, we hired a new Chief Financial Officer, General Counsel, Controller, and Assistant Controller. Eight of the eleven professional positions in our corporate-level finance and accounting department and both of the positions in our legal department are or will be filled by individuals who have joined the Company since the beginning of 2005. To manage our financial, accounting and legal matters effectively, these individuals must absorb considerable, necessary background information on the Company and we must successfully integrate them into our ongoing activities. In the second quarter of 2005, we began to implement a new Company-wide computer system. The start-up of this new system has imposed increased demands on employees, particularly our finance and accounting staff. If we are unable to attract and retain the personnel we need to manage our increasingly large and complex operations, if we are unable to integrate successfully our new officers and employees, and if we are unable to complete successfully the implementation of our new computer system, our ability to manage our operations effectively and to pursue our business strategy could be compromised.
31
The implementation of a new enterprise resource planning system could disrupt our internal operations.
We are in the process of implementing a new company-wide computer system to replace the various systems that have been in place at our corporate offices, at the operations we owned in 2001, and at the operations we acquired in 2001. Once implemented, we expect this system to help establish standard, uniform, best practices and reporting in a number of areas, increase productivity and efficiency, and enhance management of our business. Certain aspects of our information technology infrastructure and operational activities have and may continue to experience difficulties in connection with this transition and implementation. Such difficulties can cause delay, be time consuming and more resource intensive than planned, and cost more than we have anticipated. There can be no assurance that we will achieve the cost savings and return on investment intended from this project.
Our growth and development strategy could require significant resources and may not be successful.
We regularly seek opportunities to make additional strategic acquisitions, to expand existing businesses, to develop new operations and to enter related businesses. We may not be able to identify suitable acquisition candidates or development opportunities, or complete any acquisition or project, on terms that are favorable to us. Acquisitions, investments and other growth projects involve risks that could harm our operating results, including difficulties in integrating acquired and new operations, diversions of management resources, debt incurred in financing such activities and unanticipated problems and liabilities. We anticipate that we would finance acquisitions and development activities by using our existing capital resources, borrowing under existing bank credit facilities, issuing equity securities or incurring additional indebtedness. We may not have sufficient available capital resources or access to additional capital to execute potential acquisitions or take advantage of development opportunities.
Our expenditures for postretirement medical and life insurance benefits could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.
We provide various postretirement medical and life insurance benefits to current and former employees and their dependents. We estimate the amounts of these obligations based on assumptions described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Estimates and Related Matters” herein. We accrue amounts for these obligations, which are unfunded, and we pay as costs are incurred. If our assumptions change, the amount of our obligations could increase, and if our assumptions are inaccurate, we could be required to expend greater amounts than we anticipate. We estimate that our gross obligation for postretirement medical and life insurance benefits was $259.8 million at December 31, 2004. We had an accrued liability for postretirement medical and life insurance benefits of $137.7 and $134.2 million at June 30, 2005 and December 31, 2004, respectively, and we expect to accrue an additional $122.1 million over the next ten years, as permitted by Statement of Financial Accounting Standards No. 106. We regularly revise our estimates, and the amount of our accrued obligations is subject to change.
32
We have a significant amount of debt, which imposes restrictions on us and may limit our flexibility, and a decline in our operating performance may materially affect our ability to meet our future financial commitments and liquidity needs.
As of June 30, 2005, our total indebtedness was approximately $122 million, which included Westmoreland Mining’s obligations under its term loan agreement, including the add-on facility described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” We will assume significant non-recourse debt upon completion of the ROVA acquisition, we may incur additional indebtedness to finance the ROVA acquisition and we may incur additional indebtedness in the future, including indebtedness under our two existing revolving credit facilities.
Westmoreland Mining’s term loan agreement restricts its ability to distribute cash to Westmoreland Coal Company through 2011 and limits the types of transactions that Westmoreland Mining and its subsidiaries can engage in with Westmoreland Coal Company and our other subsidiaries. Westmoreland Mining executed the term loan agreement in 2001 and used the proceeds to finance its acquisition of the Rosebud, Jewett, Beulah and Savage Mines. The final payment on this indebtedness, which we call Westmoreland Mining’s acquisition debt, is in the amount of $30 million and is due on December 31, 2008. After payment of principal and interest, 25% of Westmoreland Mining’s surplus cash flow is dedicated to an account that is expected to fund this final payment. The $35 million add-on facility is scheduled to be paid-down from 2009 through 2011. Westmoreland Mining has pledged or mortgaged substantially all of its assets and the assets of the Rosebud, Jewett, Beulah and Savage Mines, and we have pledged all of our member interests in Westmoreland Mining, as security for Westmoreland Mining’s indebtedness. In addition, Westmoreland Mining must comply with financial ratios and other covenants specified in the agreements with its lenders. Failure to comply with these ratios and covenants or to make regular payments of principal and interest could result in an event of default.
A substantial portion of our cash flow must be used to pay principal of and interest on our indebtedness and is not available to fund working capital, capital expenditures or other general corporate uses. In addition, the degree to which we are leveraged could have other important consequences, including:
• | increasing our vulnerability to general adverse economic and industry conditions; |
• | limiting our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements; and |
• | limiting our flexibility in planning for, or reacting to, changes in our business and in the industry. |
If our or Westmoreland Mining’s operating performance declines, or if we or Westmoreland Mining do not have sufficient cash flows and capital resources to meet our debt service obligations, we or Westmoreland Mining may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. If Westmoreland Mining were to default on its debt service obligations, a note holder may be able to foreclose on assets that are important to our business.
At June 30, 2005, the ROVA Project had total debt of approximately $194 million. The ROVA Project’s credit agreement restricts its ability to distribute cash, contains financial ratios and other covenants, and is secured by a pledge of the project and substantially all of the project’s assets. If the ROVA Project fails to comply with these ratios and covenants or fails to make regular payments of principal and interest, an event of default could occur. A substantial portion of the ROVA Project’s cash flow must be used to pay principal of and interest on its indebtedness and is not available to us. If the ROVA Project were to default on its debt service obligations, a creditor may be able to foreclose on assets that are important to our business.
33
If the cost of obtaining new reclamation bonds and renewing existing reclamation bonds continues to increase, our profitability could be reduced.
Federal and state laws require that we provide bonds to secure our obligations to reclaim lands used for mining. We must post a bond before we obtain a permit to mine any new area. These bonds are typically renewable on a yearly basis and have become increasingly expensive. Bonding companies are requiring that applicants collateralize a portion of their obligations to the bonding company. In 2004, we paid approximately $2.5 million in premiums for reclamation bonds and posted approximately $3.2 million in collateral, in addition to the collateral that we had previously posted, for those bonds. Any capital that we provide to collateralize our obligations to our bonding companies is not available to support our other business activities. If the cost of our reclamation bonds continues to increase, our profitability could be reduced.
Our financial position could be adversely affected if we fail to maintain our Coal Act bonds.
The Coal Act established the 1992 UMWA Benefit Plan, or 1992 Plan. We are required to secure three years of our obligations to that plan by posting a surety bond or a letter of credit or collateralizing our obligations with cash. We presently secure these obligations with two bonds, one in an amount of approximately $21.3 million and one in an amount of approximately $5.0 million. In December 2003, the issuer of our $21.3 million bond indicated a desire to exit the business of bonding Coal Act obligations. In February 2004, this company renewed our Coal Act bond. Although we believe that the issuer of this bond must continue to renew the bond so long as we do not default on our obligations to the 1992 Plan, the issuer of this bond filed a Complaint for Declaratory Judgment on May 11, 2005 to force our payment of $21.3 million and to cancel the bond. If either of the companies that issue our Coal Act bonds were to cancel or fail to renew our bonds, we may be required to post another bond or secure our obligations with a letter of credit or cash. At this time, we are not aware of any other company that would provide a surety bond to secure obligations under the Coal Act. We do not believe that we could now obtain a letter of credit without collateralizing that letter of credit in full with cash. The Company does not currently have $21.3 million in cash available.
We face competition for sales to new and existing customers, and the loss of sales or a reduction in the prices we receive under new or renewed contracts would lower our revenues and could reduce our profitability.
Approximately one-third of the coal tonnage that we will produce in 2005 will be sold under long-term contracts to power plants that take delivery of our coal from common carrier railroads. All of the Absaloka Mine’s sales are delivered by rail and about 20% of the Rosebud Mine’s and Beulah Mine’s sales are delivered by rail. Contracts covering 90% of those rail tons are scheduled to expire between December 2006 and December 2008. As a general matter, plants that take coal by rail can buy their coal from many different suppliers. We will face significant competition, primarily from mines in the Southern Powder River Basin of Wyoming, to renew our long-term contracts with our rail-served customers, and for contracts with new rail-served customers. Many of our competitors are larger and better capitalized than we are and have coal with a lower sulfur and ash content than our coal. As a result, our competitors may be able to adopt more aggressive pricing policies for their coal supply contracts than we can. If our existing customers fail to renew their existing contracts with us on terms that are at least equivalent to those in effect today, or if we are unable to replace our existing contracts with contracts of equal size and profitability from new customers, our revenues and profitability would be reduced.
34
Approximately two-thirds of the coal tonnage that we will sell in 2005 will be delivered under long-term contracts to power plants located adjacent to our mines. We will face somewhat less competition to renew these contracts upon their expiration, both because of the transportation advantage we enjoy by being located adjacent to these customers and because most of these customers would be required to invest additional capital to obtain rail access to alternative sources of coal. Our Jewett Mine is an exception because our customer has already built rail unloading and associated facilities that are being used to take coal from the Southern Powder River Basin as permitted under our contract with that customer.
Stricter environmental regulations, including regulations recently adopted by the EPA, could reduce the demand for coal as a fuel source and cause the volume of our sales to decline.
Coal contains impurities, including sulfur, mercury, nitrogen and other elements or compounds, many of which are released into the air when coal is burned. Stricter environmental regulation of emissions from coal-fired electric generating plants could increase the costs of using coal, thereby reducing demand for coal as a fuel source generally, and could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future. The U.S. Environmental Protection Agency, or EPA, has recently adopted regulations that could increase the costs of operating coal-fired power plants, including the ROVA Project. Congress has considered legislation that would have this same effect. At this time, we are unable to predict the impact of these new regulations on our business. However, we expect that the new regulations may alter the relative competitiveness among coal suppliers and coal types. The new regulations could also disadvantage some or all of our mines, and notwithstanding our coal supply contracts we could lose all or a portion of our sales volumes and face increased pressure to reduce the price for our coal, thereby reducing our revenues, our profitability and the value of our coal reserves.
In March 2005, the EPA issued the Clean Air Interstate Rule (“CAIR”) and Clean Air Mercury Rule (“CAMR”). The CAIR will reduce emissions of sulfur dioxide and nitrogen oxide in 28 eastern States and the District of Columbia. Texas and Minnesota, in which customers of the Jewett and Absaloka mines are located, and North Carolina, where the ROVA Project is located, are subject to the CAIR. The CAIR requires these States to achieve required reductions in emissions from electric generating units, or EGUs, in one of two ways: (1) through participation in an EPA-administered, interstate “cap and trade” system that caps emissions in two stages, or (2) through measures of the State’s choice. Under the cap and trade system, the EPA will allocate emission “allowances” for nitrogen oxide to each State. The 28 States will distribute those allowances to EGUs, which can trade them. To control sulfur dioxide, the EPA will reduce the existing allowance allocations for sulfur dioxide that are currently provided under the acid rain program established pursuant to Title IV of the Clean Air Act Amendments.EGUs may choose among compliance alternatives, including installing pollution control equipment, switching fuels, or buying excess allowances from other EGUs that have reduced their emissions. Aggregate sulfur dioxide emissions are to be reduced from 2003 levels in two stages, a 45% reduction by 2010 and a 57% reduction by 2015. Aggregate nitrogen oxide emissions are also to be reduced from 2003 levels in two stages, a 53% reduction by 2009 and a 61% reduction by 2015.
The CAMR applies to all States. The CAMR establishes a two-stage, nationwide cap on mercury emissions from coal-fired EGUs. Aggregate mercury emissions are to be reduced from 1999 levels in two stages, a 20% reduction by 2010 and a 70% reduction by 2018. The EPA expects that, in the first stage, emissions of mercury will be reduced in conjunction with the reductions of sulfur dioxide and nitrogen oxide under the CAIR. The EPA has assigned each State an emissions “budget” for mercury, and each state must submit a State Plan detailing how it will meet its budget for reducing mercury from coal-fired EGUs. Again, States may participate in an interstate “cap and trade” system or achieve reductions through measures of the State’s choice. The CAMR also establishes mercury emissions limits for new coal-fired EGUs (new EGUs are power plants for which construction, modification, or reconstruction commenced after January 30, 2004).
These new rules are likely to affect the market for coal for at least three reasons:
35
• | Different types of coal vary in their chemical composition and combustion characteristics. For example, the lignite from our Jewett and Beulah mines is inherently higher in mercury than bituminous and sub-bituminous coal, and sub-bituminous coal from different seams can differ significantly. |
• | Different EGUs have different levels of emissions control technology. For example, the ROVA Project has “state of the art” emissions control technology that reduces its emissions of sulfur dioxide, nitrogen oxide and, collaterally, mercury. |
• | The CAIR is likely to affect the existing national market for sulfur dioxide emissions allowances, thereby indirectly affecting coal producers and consumers that are not directly subject to the CAIR. |
For all the foregoing reasons, and because it is unclear how States will allocate their emissions budgets, we are unable to predict at this time how these new rules will affect the Company.
The Company’s contracts protect our sales positions, including volumes and prices, to varying degrees. However, we could face disadvantages under the new regulations that could result in our inability to renew some or all of our contracts as they expire or reach scheduled price reopeners or that could result in relatively lower prices upon renewal, thereby reducing our relative revenue, profitability, and/or the value of our coal reserves.
New legislation or regulations in the United States aimed at limiting emissions of greenhouse gases could increase the cost of using coal or restrict the use of coal, which could reduce demand for our coal, cause our profitability to suffer and reduce the value of our assets.
A variety of international and domestic environmental initiatives are currently aimed at reducing emissions of greenhouse gases, such as carbon dioxide, which is emitted when coal is burned. If these initiatives were to be successful, the cost to our customers of using coal could increase, or the use of coal could be restricted. This could cause the demand for our coal to decrease or the price we receive for our coal to fall, and the demand for coal generally might diminish. Restrictions on the use of coal or increases in the cost of burning coal could cause us to lose sales and revenues, cause our profitability to decline or reduce the value of our coal reserves.
Demand for our coal could also be reduced by environmental regulations at the state level.
Environmental regulations by the states in which our mines are located, or in which the generating plants they supply operate, may negatively affect demand for coal in general or for our coal in particular. For example, Texas passed regulations requiring all fossil fuel-fired generating facilities in the state to reduce nitrogen oxide emissions beginning in May 2003. In January 2004, we entered into a supplemental settlement agreement with Texas Genco II pursuant to which the Limestone Station must purchase a specified volume of lignite from the Jewett Mine. In order to burn this lignite without violating the Texas nitrogen oxide regulations, the Limestone Station is blending our lignite with coal, produced by others in the Southern Powder River Basin, and using emissions credits. Considerations involving the Texas nitrogen oxide regulations might affect the demand for lignite from the Jewett Mine in the period after 2007, which is the last year covered by the four- year fixed price agreement. Texas Genco II might claim that it is less expensive for the Limestone Station to comply with the Texas nitrogen oxide regulations by switching to a blend that contains relatively more coal from the Southern Powder River Basin and relatively less of our lignite. Other states are evaluating various legislative and regulatory strategies for improving air quality and reducing emissions from electric generating units. Passage of other state-specific environmental laws could reduce the demand for our coal.
36
We have significant reclamation and mine closure obligations. If the assumptions underlying our accruals are materially inaccurate, or if we are required to honor reclamation obligations that have been assumed by our customers or contractors, we could be required to expend greater amounts than we currently anticipate, which could affect our profitability in future periods.
We are responsible under federal and state regulations for the ultimate reclamation of the mines we operate. In some cases, our customers and contractors have assumed these liabilities by contract and have posted bonds or have funded escrows to secure their obligations. We estimate our future liabilities for reclamation and other mine-closing costs from time to time based on a variety of assumptions. If our assumptions are incorrect, we could be required in future periods to spend more on reclamation and mine-closing activities than we currently estimate, which could harm our profitability. Likewise, if our customers or contractors default on the unfunded portion of their contractual obligations to pay for reclamation, we could be forced to make these expenditures ourselves and the cost of reclamation could exceed any amount we might recover in litigation, which would also increase our costs and reduce our profitability.
We estimate that our gross reclamation and mine-closing liabilities, which are based upon permit requirements and our experience, were $315.5 million (with a present value of $144.4 million) at June 30, 2005. Of these liabilities, our customers have assumed a gross aggregate of $187.3 million and have secured a portion of these obligations by posting bonds in the amount of $50 million and funding reclamation escrow accounts that currently hold approximately $57.0 million, in each case at June 30, 2005. We estimate that our gross obligation for final reclamation that is not the contractual responsibility of others was $128.1 million at June 30, 2005, and that the present value of our net obligation for final reclamation that is not the contractual responsibility of others was $55.6 million at June 30, 2005.
Our profitability could be affected by unscheduled outages at the power plants we supply or own or if the scheduled maintenance outages at the power plants we supply or own last longer than anticipated.
Scheduled and unscheduled outages at the power plants that we supply could reduce our coal sales and revenues, because any such plant would not use coal while it was undergoing maintenance. We cannot anticipate if or when unscheduled outages may occur.
Our profitability could be affected by unscheduled outages at the ROVA Project or if scheduled outages at the ROVA Project last longer than we anticipate. For example, the ROVA I unit is scheduled to be out of service for 20 days in September and early October 2005. Also, the ROVA II unit is scheduled to be out of service for 28 days in October and November 2005. The ROVA Project’s contract with Dominion Virginia Power is structured so that our annual revenues will not be adversely affected by this outage. However, if maintenance uncovers matters beyond those anticipated, the outage could be prolonged beyond the scheduled period, which could reduce the ROVA Project’s profitability and our revenues. In addition, if the maintenance uncovers a matter that must be remedied or repaired, the cost of those repairs may also adversely affect the ROVA Project’s profitability.
Increases in the cost of the fuel, electricity and materials we use to operate our mines could affect our profitability.
Under several of our existing coal supply agreements, our mines bear the cost of the diesel fuel, lubricants and other petroleum products, electricity, and other materials and supplies necessary to operate their draglines and other mobile equipment. The prices of many of these commodities have increased significantly in the last year, and continued escalation of these costs would hurt our profitability or threaten the financial condition of certain operations in the absence of corresponding increases in revenue.
37
If we experience unanticipated increases in the capital expenditures we expect to make over the next several years, our profitability could suffer.
Over the next several years, we anticipate making significant capital expenditures, principally at the Rosebud and Jewett Mines, in order to add to and refurbish our machinery and equipment and prepare new areas for mining. We also began implementing a new company-wide computer system in 2005. The costs of any of these expenditures could exceed our expectations, which could reduce our profitability and divert our capital resources from other uses.
Our ability to operate effectively and achieve our strategic goals could be impaired if we lose key personnel.
Our future success is substantially dependent upon the continued service of our key senior management personnel, particularly Christopher K. Seglem, our Chairman of the Board, President and Chief Executive Officer. We do not have key-person life insurance policies on Mr. Seglem or any other employees. The loss of the services of any of our executive officers or other key employees could make it more difficult for us to pursue our business goals.
Provisions of our certificate of incorporation, bylaws and Delaware law, and our stockholder rights plan, may have anti-takeover effects that could prevent a change of control of our company that you may consider favorable, and the market price of our common stock may be lower as a result.
Provisions in our certificate of incorporation and bylaws and Delaware law could make it more difficult for a third party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our bylaws impose various procedural and other requirements that could make it more difficult for stockholders to effect some types of corporate actions. In addition, a change of control of our Company may be delayed or deterred as a result of our stockholder rights plan, which was initially adopted by our Board of Directors in early 1993 and amended and restated in February 2003. Our ability to issue preferred stock in the future may influence the willingness of an investor to seek to acquire our company. These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control of Westmoreland.
38
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
The Company, 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 are sold through long-term contracts with customers. These long-term contracts serve to reduce the Company’s exposure to changes in commodity prices although some of the Company’s contracts are adjusted periodically based upon market prices and some contracts provide for fixed pricing. 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, 2005.
Interest Rate Risk
The Company and its subsidiaries are subject to interest rate risk on its debt obligations. Long-term debt obligations have 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 balances outstanding on these instruments as of June 30, 2005, a one percent change in the prime interest rate or LIBOR would increase or decrease interest expense by $95,000 on an annual basis. Westmoreland Mining’s Series D Notes under its term debt agreement have a variable interest rate based on LIBOR. A one percent change in the LIBOR would increase or decrease interest expense by $146,000 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.
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 of June 30, 2005. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, means controls and other procedures of a company that are designed to ensure 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. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Based on the evaluation of the Company’s disclosure controls and procedures as of June 30, 2005, the Company’s chief executive officer and chief financial officer concluded that, as of such date, the Company’s disclosure controls and procedures were effective at the reasonable assurance level.
39
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, 2005 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
40
PART II — OTHER INFORMATION
LEGAL PROCEEDINGS
As described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, “Item 3 — Legal Proceedings,” the Company has litigation which is still pending. For developments in these proceedings, see Notes 7 and 8 to our Consolidated Financial Statements, which are incorporated by reference herein.
Purchase Price Adjustment
On June 24, 2005, Westmoreland Coal Company reached a settlement with Entech LLC of all disputes relating to Westmoreland’s acquisition of Entech’s coal business in 2001. Entech is currently in bankruptcy. Under the terms of the settlement, Westmoreland will pay $1,150,000 to Entech for a full and final settlement of claims either party may have against the other. This amount was accrued as an expense in the quarter ended June 30, 2005. The settlement is subject to the approval of the bankruptcy court having jurisdiction over Entech’s bankruptcy proceeding. This approval is expected.
As background, the final purchase price for Westmoreland’s 2001 acquisition of the coal business of Entech was subject to certain adjustments to reflect changes in net assets and net revenues of the acquired operations between January 1, 2001 and the closing date. In June 2001, Entech submitted proposed adjustments that would have increased the purchase price by approximately $9.0 million. In July 2001, Westmoreland objected to Entech’s proposed adjustments and submitted its own adjustments which would have resulted in a substantial decrease in the original purchase price. The Stock Purchase Agreement required that the parties’ disagreements be submitted to an independent accountant for resolution. Westmoreland also submitted a claim for indemnification by Entech.
In November 2004, the independent accountant issued findings that showed a net amount due to Westmoreland of $587,000. However, the independent accountant’s findings did not include a $5 million adjustment that represented an initial purchase price reduction at the time of closing. Entech requested that the independent accountant revise his findings to include this $5 million adjustment. Prior to the settlement, the independent accountant had not revised his findings. Westmoreland’s claims against Entech for indemnification were set for trial in December 2005 in the U.S. District Court for the District of Delaware, but all legal proceedings have been brought to an end because of the settlement.
The dispute with Entech involved two separate proceedings, one relating to purchase price adjustments and one to indemnification of the Company by Entech related to the representations and warranties by Entech in the purchase and sale agreement. As a result of Entech having filed for bankruptcy after these proceedings commenced, a significant risk emerged that any judgment in favor of the Company in the indemnification proceeding would be subordinated to the claims of unsecured creditors in the Entech bankruptcy proceeding, and thus not only uncollectable, but unavailable to offset any potential purchase price adjustment in favor of Entech. In light of these circumstances and the cost of continuing litigation it was concluded that a negotiated settlement was the best way to resolve this four-year-old dispute. The Company believes the settlement is fair and in the best interests of shareholders.
41
DEFAULTS UPON SENIOR SECURITIES
See Note 4 “Capital Stock” to our Consolidated Financial Statements, which is incorporated by reference herein.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
An Annual Meeting of Shareholders was held on May 19, 2005. 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 | 7,169,276 | 166,186 | |||
Thomas W. Ostrander | 7,184,114 | 151,348 | |||
Christopher K. Seglem | 7,213,886 | 121,576 | |||
Thomas J. Coffey | 7,177,893 | 157,569 | |||
Robert E. Killen | 7,219,551 | 115,911 | |||
James W. Sight | 7,220,551 | 114,911 | |||
Donald A. Tortorice | 7,219,151 | 116,311 | |||
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 | 668,163 | 5,903 | |||
William M. Stern | 668,163 | 5,903 | |||
Messrs. Armstrong and Stern were elected.
There were no abstentions or broker non-votes.
42
EXHIBITS
Exhibit Number | Description | ||
---|---|---|---|
31 | Rule 13a-14(a)/15d-14(a) Certifications. | ||
32 | Certifications pursuant to 18 U.S.C. Section 1350. |
43
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 9, 2005 | /s/ David J. Blair |
David J. Blair | |
Chief Financial Officer | |
(A Duly Authorized Officer) | |
/s/ Diane M. Nalty | |
Diane M. Nalty | |
Controller | |
(Principal Accounting Officer) | |
44
Exhibit Number | Description | ||
---|---|---|---|
31 | Rule 13a-14(a)/15d-14(a) Certifications. | ||
32 | Certifications pursuant to 18 U.S.C. Section 1350. |
45