WESTMORELAND COAL (WLBAQ) 10-Q 2006 Q3 Quarterly report

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 ended September 30, 2006

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer _____ Accelerated Filer  X  Non-accelerated filer _____

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ___     No   X 

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of November 1, 2006: Common stock, $2.50 par value: 8,975,696 shares

1

PART I — FINANCIAL INFORMATION

ITEM 1
FINANCIAL STATEMENTS

Westmoreland Coal Company and Subsidiaries
Consolidated Balance Sheets
	(Unaudited)
	September 30,		December 31,
	2006		2005
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	20,774	$	11,216
Receivables, net:
Trade		52,889		29,138
Other		9,262		7,330
		62,151		36,468
Inventories		22,160		17,576
Deferred overburden removal costs		-		14,090
Other current assets		7,312		4,816
Total current assets		112,397		84,166
Property, plant and equipment:
Land and mineral rights		78,748		77,591
Capitalized asset retirement cost		121,837		122,561
Plant and equipment		344,868		127,063
		545,453		327,215
Less accumulated depreciation, depletion and amortization		135,442		116,058
Net property, plant and equipment		410,011		211,157
Investment in independent power projects		-		50,869
Excess of trust assets over pneumoconiosis benefit obligation		7,411		7,463
Restricted cash and bond collateral		67,702		34,563
Advanced coal royalties		3,969		3,874
Deferred overburden removal costs		-		2,717
Reclamation deposits		61,520		58,823
Contractual third party reclamation obligations		33,483		31,615
Intangible assets		13,790		-
Other assets		12,303		10,624
Total Assets	$	722,586	$	495,871

See accompanying Notes to Consolidated Financial Statements.

2

Westmoreland Coal Company and Subsidiaries
Consolidated Balance Sheets (Continued)
	(Unaudited)
	September 30,		December 31,
	2006		2005
	(In thousands)
Liabilities and Shareholders' Deficit
Current liabilities:
Current installments of long-term debt	$	75,831	$	12,437
Accounts payable and accrued expenses:
Trade		48,597		33,307
Deferred revenue		867		583
Income taxes		2,351		2,293
Interest		2,187		-
Production taxes		25,157		19,609
Workers' compensation		1,265		949
Postretirement medical costs		14,540		17,160
Asset retirement obligations		11,986		17,890
Total current liabilities		182,781		104,228
Long-term debt, less current installments		220,590		94,306
Revolving lines of credit		7,100		5,500
Workers' compensation, less current portion		7,597		8,394
Postretirement medical costs, less current portion		131,891		124,746
Pension and SERP obligations		18,958		16,171
Deferred revenue, less current portion		8,854		1,251
Asset retirement obligations, less current portion		143,885		140,517
Other liabilities		17,405		6,810
Minority interest		5,091		4,140
Commitments and contingent liabilities
Shareholders' deficit:
Preferred stock of $1.00 par value
Authorized 5,000,000 shares;
Issued and outstanding 160,129 shares at September 30, 2006
and 205,083 shares at December 31, 2005		160		205
Common stock of $2.50 par value
Authorized 20,000,000 shares;
Issued and outstanding 8,959,543 shares at September 30, 2006
and 8,413,312 shares at December 31, 2005		22,398		21,033
Other paid-in capital		78,171		75,344
Accumulated other comprehensive loss		(11,467	)	(11,409	)
Accumulated deficit		(110,828	)	(95,365	)
Total shareholders' deficit		(21,566	)	(10,192	)
Total Liabilities and Shareholders' Deficit	$	722,586	$	495,871

See accompanying Notes to Consolidated Financial Statements.

3

Westmoreland Coal Company and Subsidiaries Consolidated Statements of Operations
	(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
	2006			2005			2006			2005
	(In thousands except per share data)
Revenues:
Coal	$	106,227		$	94,141		$	292,479		$	265,468
Energy		25,437			-			25,437			-
Independent power projects - equity in earnings		84			1,682			7,545			10,310
		131,748			95,823			325,461			275,778
Costs and expenses:
Cost of sales - coal		84,115			78,498			230,331			217,606
Cost of sales - energy		16,066			-			16,066			-
Depreciation, depletion and amortization		8,740			5,525			20,573			16,463
Selling and administrative		11,773			9,195			31,053			24,060
Heritage health benefit expenses		5,862			7,015			19,962			22,597
Loss (gain) on sales of assets		40			(28	)		(4,906	)		151
		126,596			100,205			313,079			280,877
Operating income (loss)		5,152			(4,382	)		12,382			(5,099	)
Other income (expense):
Interest expense		(6,992	)		(2,815	)		(12,456	)		(8,452	)
Interest income		1,886			851			4,099			2,483
Minority interest		(342	)		(295	)		(1,551	)		(854	)
Other		130			585			779			1,225
		(5,318	)		(1,674	)		(9,129	)		(5,598	)
Income (loss) before income taxes and cumulative effect of change in accounting principle		(166	)		(6,056	)		3,253			(10,697	)
Income tax expense		(213	)		(1,368	)		(733	)		(2,996	)
Income (loss) before cumulative effect of change in accounting principle		(379	)		(7,424	)		2,520			(13,693	)
Cumulative effect of change in accounting principle		-			-			-			2,662
Net income (loss)		(379	)		(7,424	)		2,520			(11,031	)
Less preferred stock dividend requirements		340			436			1,164			1,308
Less premium on exchange of preferred stock for common stock		242			-			791			-
Net income (loss) applicable to common shareholders	$	(961)		$	(7,860)		$	565		$	(12,339)
Net income (loss) per share applicable to common shareholders before the cumulative effect of change in accounting principle:
Basic	$	(0.11	)	$	(0.95	)	$	0.07		$	(1.82	)
Diluted	$	(0.11	)	$	(0.95	)	$	0.06		$	(1.82	)
Net income per share applicable to common shareholders from cumulative effect of change in accounting principle:
Basic		-			-			-		$	0.32
Diluted		-			-			-		$	0.32
Net income (loss) per share applicable to common shareholders:
Basic	$	(0.11	)	$	(0.95	)	$	0.07		$	(1.49	)
Diluted	$	(0.11	)	$	(0.95	)	$	0.06		$	(1.49	)
Weighted average number of common shares outstanding:
Basic		8,948			8,302			8,671			8,255
Diluted		9,222			8,302			9,056			8,255

See accompanying Notes to Consolidated Financial Statements.

4

Westmoreland Coal Company and Subsidiaries Consolidated Statement of Shareholders' Deficit and Comprehensive Income Nine Months Ended September 30, 2006 (Unaudited)
	Class A Convertible Exchangeable Preferred Stock		Common Stock		Other Paid-In Capital		Accumulated Other Comprehensive Income (Loss)		Accumulated Deficit (Restated)		Total Shareholders' Equity
		(In thousands except share data)
Balance at December 31, 2004 (205,083 preferred and 8,168,601 common shares outstanding)	$	205	$	20,421	$	73,143	$	(8,529)	$	(88,611)	$	(3,371)
Common stock issued as compensation (72,863 shares)		-		183		1,536		-		-		1,719
Common stock options		-		429		665		-		-		1,094
Dividends declared		-		-		-		-		(820)		(820)
Net loss		-		-		-		-		(5,934)		(5,934)
Minimum pension liability		-		-		-		(3,388)		-		(3,388)
Change in unrealized gain on interest rate swap agreement		-		-		-		508		-		508
Comprehensive loss												(8,814)
Balance at December 31, 2005 (205,083 preferred shares and 8,413,312 common shares outstanding)		205		21,033		75,344		(11,409)		(95,365)		(10,192)
Cumulative effect of change in accounting for deferred overburden removal costs		-		-		-		-		(16,805)		(16,805)
Common stock issued as compensation (55,404 shares)		-		138		1,273		-		-		1,411
Common stock options exercised (154,732 shares)		-		387		552		-		-		939
Adjustment for stock appreciation rights previously classified as a liability upon adoption of FAS 123(R)		-		-		1,006		-		-		1,006
Dividends declared		-		-		-		-		(387)		(387)
Exchange of preferred shares for common stock		(45)		840		(4)		-		(791)		-
Net income		-		-		-		-		2,520		2,520
Change in unrealized gain on interest rate swap		-		-		-		(58)		-		(58)
Comprehensive income												2,462
Balance at September 30, 2006 (160,129 preferred shares and 8,959,543 common shares outstanding)	$	160	$	22,398	$	78,171	$	(11,467)	$	(110,828)	$	(21,566)

See accompanying Notes to Consolidated Financial Statements.

5

Westmoreland Coal Company and Subsidiaries Consolidated Statements of Cash Flows
	(Unaudited)
Nine Months Ended September 30,	2006			2005
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	2,520		$	(11,031	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Equity in earnings from independent power projects		(7,545	)		(10,310	)
Cash distributions from independent power projects		1,170			10,542
Cumulative effect of change in accounting principle		-			(2,662	)
Depreciation, depletion and amortization		20,573			16,463
Deferred power sales revenue		7,881			-
Stock compensation expense		1,411			1,269
Loss (gain) on sales of assets		(4,906	)		151
Minority interest		1,551			854
Net change in operating assets and liabilities, net of effects of ROVA acquisition		(2,988	)		11,766
Net cash provided by operating activities		19,667			17,042
Cash flows from investing activities:
Additions to property, plant and equipment		(14,761	)		(15,454	)
Change in restricted cash and bond collateral and reclamation deposits		(7,610	)		(3,449	)
ROVA acquisition, net of cash resulting from the ROVA consolidation    of $21.9 million		(7,714	)		-
Net proceeds from sales of assets		5,092			641
Net cash used in investing activities		(24,993	)		(18,262	)
Cash flows from financing activities:
Proceeds from long-term debt		873			-
Repayment of long-term debt		(22,156	)		(7,602	)
Net borrowings on lines of credit		36,215			6,500
Exercise of stock options		939			900
Dividends paid to minority interest		(600	)		(780	)
Dividends paid on preferred stock		(387	)		(615	)
Net cash provided by (used in) financing activities		14,884			(1,597	)
Net increase (decrease) in cash and cash equivalents		9,558			(2,817	)
Cash and cash equivalents, beginning of period		11,216			11,125
Cash and cash equivalents, end of period	$	20,774		$	8,308
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest	$	7,542		$	7,235
Income taxes		674			528

See accompanying Notes to Consolidated Financial Statements.

6

WESTMORELAND COAL COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

               These quarterly consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in Amendment No. 1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 (the “2005 Form 10-K/A”). The accounting principles followed by the Company are set forth in the Notes to the Company’s consolidated financial statements in that Annual Report. Most of 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. Certain prior year amounts have been reclassified to conform to the current year presentation.

1. NATURE OF OPERATIONS AND LIQUIDITY

               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. The Company’s activities are conducted through wholly-owned or majority owned subsidiaries which generally have obtained separate financing.

               Credit facilities of certain subsidiaries contain restrictions on the distribution of cash to the parent company as dividends, loans or advances (see note 6). The Company believes that the parent company has sufficient cash resources and committed financing to provide it with adequate liquidity through early 2007. The Company believes that it should be able to address the liquidity needs of the parent company through additional borrowings, the restructuring of current debt obligations, the sale of non-strategic assets, and the issuance of additional equity. The Company has taken specific actions, including discussions with potential lenders, investors and asset purchasers regarding potential transactions that the Company believes can be completed. There can be no assurance that the Company can complete any transaction on terms acceptable to the Company.

2. ROVA ACQUISITION

               On June 29, 2006, the Company acquired a 50 percent partnership interest in the 230 MW Roanoke Valley (“ROVA”) power plant located in Weldon, North Carolina from a subsidiary of E.ON U.S. LLC – formerly LG&E Energy LLC. The acquisition increases the Company’s ownership interest in ROVA to 100 percent. As part of the same transaction, the Company acquired certain additional assets from LG&E Power Services LLC, a subsidiary of E.ON U.S. LLC, consisting primarily of five contracts under which two subsidiaries of the Company will now operate and provide maintenance services to ROVA and four power plants in Virginia owned by Dominion North Carolina Power. These five contracts are referred to as operating agreements.

               The Company paid $27.5 million in cash at closing for the 50% interest in ROVA and other assets acquired. The Company also assumed E.ON U.S.‘s share of non-recourse project debt in the amount of $85.5 million. In conjunction with the acquisition of ROVA, the Company paid a $2.5 million fee to Dominion North Carolina Power in exchange for its agreement to waive the right of first refusal which it claimed to have in connection with the transaction. The total purchase price of $30.3 million also includes $0.3 million in transaction costs. The Company deposited $5.0 million into ROVA’s debt protection account to replace collateral previously provided by E.ON US.

7

               The Company financed the acquisition and debt protection account deposit with a $30 million bridge loan facility from SOF Investments, LP (“SOF”), a $5 million term loan with First Interstate Bank, and with corporate funds (see Note 6).

               As a result of the acquisition, the accounts of ROVA have been included in the consolidated balance sheet beginning on June 30, 2006. For financial reporting purposes, the acquisition is deemed to have occurred on June 30, 2006, and ROVA’s results of operations have been consolidated with the Company’s beginning July 1, 2006. The purchase price has been allocated based upon a preliminary appraised fair value of the identifiable assets acquired. The excess of fair value of net identifiable assets over the purchase price was allocated as a pro rata reduction of the amounts that otherwise would have been assigned to property, plant, and equipment and intangible assets. The $30.3 million purchase price was allocated as follows (in thousands):

Assets:
Cash	$	10,951
Accounts receivable		9,113
Inventory		570
Property, plant, and equipment		91,441
Restricted assets		11,613
Intangible assets		14,266
Other assets		276
Total assets		138,230
Liabilities:
Accounts payable		2,298
Accrued interest		896
Debt		90,660
Other liabilities		14,054
Total liabilities		107,908
Total purchase price	$	30,322

               Restricted assets represent restricted cash deposits required to be maintained under ROVA’s debt agreement. The intangible assets relate to power sales and coal supply agreements acquired and are being amortized over the remaining life of those contracts. Debt consists of term loans and bond borrowings which were used primarily to fund the construction of the facility and qualified expenditures.

8

               The initial accounts of ROVA, including the effects of the purchase price adjustments attributable to the acquisition, that were included in the Company’s consolidated balance sheet of June 30, 2006 as a result of the acquisition and consolidation of ROVA are as follows (in thousands):

Assets:
Cash	$	21,901
Accounts receivable		10,794
Inventory		1,157
Property, plant, and equipment		205,720
Restricted assets		28,226
Intangible assets		14,266
Other assets		3,261
Total assets		285,325
Liabilities:
Accounts payable		5,368
Accrued interest		1,793
Debt		205,986
Other liabilities		14,856
Total liabilities		228,003
Elimination of equity method investment in ROVA	$	57,322

               Intangible assets acquired include the estimated fair value of two power purchase agreements and two coal supply agreements. The Company recorded an asset of $ $0.3 million for one of the power purchase agreements, assets totaling $13.3 million for the coal supply agreements, and a liability of $13.3 million for the other power purchase agreement. The intangible assets and liabilities are being amortized over the terms of the related agreements.

               The following table summarizes the consolidated pro forma results of operations for the combined companies for the three months ended September 30, 2005 and the nine months ended September 30, 2006, and 2005 had the ROVA acquisition taken place at the beginning of those periods, and shows the historical results for the three months ended September 30, 2006:

	Historical			Pro forma
(In thousands except per share data)	Three months ended September 30, 2006			Three months ended September 30, 2005			Nine months ended September 30, 2006			Nine months ended September 30, 2005
Revenues	$	131,748		$	112,633		$	359,599		$	325,190
Income (loss) from operations		5,152			(4,919	)		11,387			(4,986	)
Net loss applicable to common shareholders	$	(961	)	$	(12,416	)	$	(7,929	)	$	(24,398	)
Earnings per share
Basic:	$	(0.11	)	$	(1.50	)	$	(0.91	)	$	(2.96	)
Diluted:	$	(0.11	)	$	(1.50	)	$	(0.91	)	$	(2.96	)

               ROVA’s historical accounting policy for revenue recognition has been to record revenue as amounts were invoiced pursuant to the provisions of the power sales agreements. The power sales agreements were entered into prior to the effective date of EITF 91-06 “Revenue Recognition of Long-Term Power Sales Contracts”. Accordingly, the agreements were not subject to the accounting requirements of that consensus. The agreements also were entered into prior to the effective date of the consensus of EITF 01-08 “Determining Whether an Arrangement Contains a Lease”, and accordingly were not subject to the accounting requirement of that consensus.

9

               With the Company’s acquisition of the remaining 50% interest in ROVA, the power sales agreements are considered to be within the scope of EITF 01-08. Under the provisions of EITF 01-08 the power sales arrangements are considered to contain a lease within the scope of SFAS No. 13, “Accounting for Leases”. The lease is classified as an operating lease, and as a result, the Company recognizes amounts invoiced under the power sales agreements as revenue based on the per kilowatt hour weighted average of the capacity payments estimated to be received over the remaining term of the power sales agreements. The capacity payments that ROVA receives are higher in the first 15 years of the power sales agreements (through 2009 for ROVA I and 2010 for ROVA II), but decrease for the remaining 10 years of the agreements. As a result of this change in revenue recognition, adjustments were included in the pro forma statements of operations presented above to reduce revenue in the nine months ended September 30, 2006 and 2005 by $22.0 million and $21.5 million, respectively.

               The pro forma statements of operations also include adjustments for the amortization of intangible assets, fair market value adjustments to property, plant, and equipment and debt, and interest expense on the acquisition debt.

3. CHANGES IN ACCOUNTING PRINCIPLES

RECOGNITION OF REVENUE UNDER POWER SALES AGREEMENTS

               In connection with the acquisition of the remaining 50% interest in ROVA, the Company has applied the provisions of EITF 01-08 “Determining Whether an Arrangement Contains a Lease” (see Note 2) to two power sales agreements.  A portion of the capacity payments under ROVA’s two power sales agreements are considered to be operating leases under EITF 01-08.  Under both agreements, ROVA invoices and collects the capacity payments based on kilowatt hours produced if the units are dispatched or for the kilowatt hours of available capacity if the units are not fully dispatched. Under the power sales agreement for ROVA II, ROVA also collects capacity payments during periods of scheduled outages based on the kilowatt hours of dependable capacity of the unit.   The capacity payments that ROVA invoices and collects are higher in the first 15 years of the power sales agreements (through 2009 for ROVA I and 2010 for ROVA II), but decrease for the remaining 10 years of the agreements due to a reduction in rate per MW hour of capacity.  Effective July 1, 2006, the Company is recognizing  revenue received under the power sales agreements as revenue on a pro rata basis,  based on the weighted average per kilowatt hour capacity payments estimated to be received over the remaining term of the power sales agreements.  Under this method of recognizing revenue, $7.9 million of amounts invoiced during the three and nine months ended September 30, 2006 have been deferred from recognition until 2010 and beyond. 

DEFERRED OVERBURDEN REMOVAL COSTS

               In June 2005, the FASB ratified a modification to the consensus reached by the Emerging Issues Task Force (“EITF”) in EITF 04-06 “Accounting for Stripping Costs Incurred during Production in the Mining Industry.” The EITF clarified that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. The effect of initially applying this consensus is accounted for in a manner similar to a cumulative effect adjustment with the adjustment recognized in the opening balance of retained earnings in the year of adoption. The Company adopted EITF 04-6 effective January 1, 2006. The adjustment to eliminate deferred stripping costs, previously recorded on the balance sheet as deferred overburden removal costs, was recorded as a $16.8 million cumulative effect adjustment to the beginning accumulated deficit as of January 1, 2006. During the nine months ended September 30, 2006, net loss was $0.2 million less than it would have been under the Company’s previous methodology of accounting for deferred stripping costs, an impact of $0.02 per fully diluted share.

10

               Before adopting EITF 04-06, the Company expensed these costs using methods and estimates consistent with those used to account for preproduction stripping costs. All stripping costs incurred during the production phase subsequent to January 1, 2006 are considered production costs of inventory and recognized as a component of cost of sales-coal when the coal is sold.

SHARE-BASED PAYMENTS

               In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” or SFAS 123(R), which replaces SFAS No. 123 and supersedes APB Opinion No. 25. SFAS No. 123(R) requires all share-based payments to employees and directors, including grants of stock options, be recognized in the financial statements based on their fair values.

               The Company adopted SFAS No. 123(R) on January 1, 2006, as prescribed, using the modified prospective method. Accordingly, compensation expense is recognized for all newly granted awards and awards modified, repurchased, or cancelled after January 1, 2006 ratably over the vesting period based on the fair value of the awards at the date of grant. Compensation expense for the unvested portion of stock option awards that were outstanding as of January 1, 2006 is being recognized ratably over the remaining vesting period, based on the fair value of the awards at date of grant as calculated for the pro forma disclosure under SFAS No. 123. See Note 9 “Capital Stock”.

               There was no cumulative effect recorded in the Company’s Statement of Operations for the change in accounting related to SFAS 123(R).

4. RECENT ACCOUNTING PRONOUNCEMENTS

INVENTORY COSTS

               In November 2004, the FASB issued SFAS No. 151, “Inventory Costs: An Amendment of ARB 43, Chapter 4.” 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 Company adopted SFAS No. 151 on January 1, 2006, as prescribed. The adoption of SFAS No. 151 did not have a material impact on the Company’s consolidated results of operations or financial condition.

ACCOUNTING CHANGES

               In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” which primarily changes the requirements for the accounting for and reporting of a change in accounting principle for all voluntary changes or when an accounting pronouncement does not include specific transition provisions. This applies to any future accounting changes beginning in fiscal years beginning after December 31, 2005.

PENSION AND OTHER POSTRETIREMENT PLANS

               In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS 158). This statement requires balance sheet recognition of the overfunded or underfunded status of pension and postretirement benefit plans. Under SFAS 158, actuarial gains and losses, prior service costs or credits, and any remaining transition assets or obligations that have not been recognized under previous accounting standards must be recognized as assets or liabilities with a corresponding adjustment to accumulated other comprehensive income, net of tax effects, until they are amortized as a component of net periodic benefit cost. SFAS 158 is effective for publicly-held companies for fiscal years ending after December 15, 2006. Based on the Company’s unfunded obligations as of December 31, 2005, had the adoption of SFAS 158 been effective on that date, the result would have been to increase the Company’s total liabilities by approximately $144 million and to reduce total shareholders’ equity by approximately $144 million. The adoption of SFAS 158 will not affect the Company’s future pension and postretirement medical benefit expenses, as determined by SFAS 106 and SFAS 87. At December 31, 2006, the date of the required adoption of SFAS 158, changes resulting from returns on the invested pension assets as well as any changes in year end actuarial assumptions could have a significant impact on the actual amounts recorded.

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5. SALE OF LEASES

               In February 2006, a wholly-owned subsidiary of the Company sold its undivided interests in two coal bed methane leases in southern Colorado for net proceeds of $5.1 million and recognized a $5.1 million gain on the sale.

6. LINES OF CREDIT AND LONG-TERM DEBT

               The current portions and total amounts outstanding under the Company’s lines of credit and long-term debt at September 30, 2006 and December 31, 2005 were:

	Current Portion of Debt				Total Debt Outstanding
	September 30, 2006		December 31, 2005		September 30, 2006		December 31, 2005
	(In thousands)
Corporate revolving line of credit	$	-	$	-	$	7,100	$	5,500
WML revolving line of credit		-		-		-		-
WML term debt:
Series B Notes		11,825		11,300		59,425		67,900
Series C Notes		-		-		20,375		20,375
Series D Notes		-		-		14,625		14,625
ROVA acquisition bridge loan		30,000		-		30,000		-
ROVA acquisition term loan		5,000		-		5,000		-
ROVA term debt		27,696		-		163,134		-
Other term debt		1,310		1,137		3,862		3,843
Total debt outstanding	$	75,831	$	12,437	$	303,521	$	112,243

               The maturities of all long-term debt and the revolving credit facilities outstanding at September 30, 2006 are:

	(In thousands)
2006	$	3,426
2007		83,873
2008		78,701
2009		44,322
2010		28,053
Thereafter		65,146
	$	303,521

               The Company obtained waivers from its lenders for its delay in filing financial statements for 2005 and the first and second quarters of 2006 in the required timeframe.

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WESTMORELAND COAL COMPANY

               The Company funded the ROVA acquisition and debt protection account deposit in part with a $30 million bridge loan facility from SOF Investments, LP (“SOF”) and a $5 million term loan with First Interstate Bank. The SOF bridge loan has a one-year term extendable to four years at the option of the Company. The loan has an interest rate of London Interbank Offering Rate (“LIBOR”) plus 4% (currently 9.5% per annum). The Company also paid SOF a 1% closing fee. If the Company elects to extend the loan beyond its initial one-year term, it will be required to issue warrants to purchase 150,000 shares of the Company’s common stock to SOF at a premium of 15% to the then current stock price. These warrants would be exercisable for a three-year period from the date of issuance. The loan is secured by a pledge of the semi-annual cash distributions from ROVA commencing in January 2007 as well as pledges from the Company’s subsidiaries that directly or indirectly acquired the operating agreements.

               The $5 million term loan with First Interstate Bank has a one-year term expiring June 29, 2007. Interest is payable at the Bank’s prime rate (currently 8.25% per annum).

               The Company has a $14 million revolving credit facility with First Interstate Bank. Interest is payable monthly at the Bank’s prime rate (currently 8.25% per annum). The Company is required to maintain certain financial ratios. The revolving credit facility is collateralized by the Company’s stock in Westmoreland Resources Inc. (“WRI”), 100% of the common stock of New Horizon Company and the dragline located at WRI’s Absaloka Mine in Big Horn County, Montana. In June 2006, the expiration date of this facility was extended to June 30, 2008.

               At September 30, 2006, Westmoreland Coal Company had approximately $121.3 million of net assets at its subsidiaries that were not available to be transferred to it in the form of dividends, loans, or advances due to restrictions contained in the credit facilities of these subsidiaries. Approximately $41.1 million of net assets of the subsidiaries are unrestricted.

WESTMORELAND MINING LLC

               Westmoreland Mining LLC (“WML”) has a $20 million revolving credit facility (the “Facility”) with PNC Bank National, Association (“PNC”) which expires on April 27, 2008. The interest rate is either PNC’s Base Rate plus 1%, or a Euro-Rate plus 3%, at WML’s option. As of September 30, 2006, the interest rate under the Facility is 9.25% per year. 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 with $59.4 million in Series B Notes, $20.4 million in Series C Notes and $14.6 million in Series D Notes outstanding as of September 30, 2006. The Series B Notes bear interest at a fixed interest rate of 9.39% per annum, Series C Notes at a fixed rate of 6.85% per annum, and the Series D Notes have a variable rate based upon LIBOR plus 2.90% (currently 8.40% per annum). All of the Notes are secured by assets of WML and the term loan agreement requires the Company to comply with certain covenants and minimum financial ratio requirements.

               Pursuant to the WML term loan agreement, WML is required to maintain debt service reserve and long-term prepayment accounts. As of September 30, 2006, there was a total of $10.2 million in the debt service reserve account and $15.0 million in the prepayment account, which account is to be used to fund a $30.0 million payment due December 31, 2008 for the Series B Notes. The debt service reserve account and the prepayment account have been classified as restricted cash in non-current assets on the consolidated balance sheet.

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ROVA

               On December 18, 1991, ROVA entered into the Credit Agreement (“Tranche A”) with a consortium of banks (the “Banks”) and an institutional lender for the financing and construction of the first ROVA facility. On December 1, 1993, the Credit Agreement was amended and restated (“Tranche B”) to allow for the financing and construction of the second ROVA facility. Under the terms of the Credit Agreement, ROVA was permitted to borrow up to $229.9 million from the Banks (“Bank Borrowings”), $120.0 million from an institutional lender, and $36.8 million in tax-exempt facility revenue bonds (“Bond Borrowings”) under two Indenture Agreements with the Halifax County, North Carolina, Industrial Facilities and Pollution Control Financing Authority (“Financing Authority”). The borrowings are evidenced by promissory notes and are secured by land, the facilities, ROVA’s equipment, inventory, accounts receivable, certain other assets and the assignment of all material contracts. Bank Borrowings amounted to $51.2 million at September 30, 2006 and mature in 2008. The Credit Agreement requires interest on the Bank Borrowings at rates set at varying margins in excess of the Banks’ base rate, LIBOR or certificate of deposit rate, for various terms from one day to one year in length, each selected by ROVA when amounts are borrowed. The weighted average interest rate at September 30, 2006 was 6.9%.

               Under the terms of the Credit Agreement, interest on the Tranche A institutional borrowings is fixed at 10.42% and interest on the Tranche B institutional borrowings is fixed at 8.33%. The Credit Agreement requires repayment of the Tranche A institutional borrowings in 38 semiannual installments ranging from $0.9 million to $4.3 million. Payment of the Tranche A institutional borrowings commenced in 1996 and is currently scheduled to be completed in 2014. The Credit Agreement requires repayment of the Tranche B institutional borrowings in 40 semiannual installments ranging from $0.3 million to $6.5 million. Payment of the Tranche B institutional borrowings commenced in 1996 and is currently scheduled to be completed in 2015.

               In accordance with the Indenture Agreements, the Financing Authority issued $29.5 million of 1991 Variable Rate Demand Exempt Facility Revenue Bonds (“1991 Bond Borrowings”) and $7.2 million of 1993 Variable Rate Demand Exempt Facility Revenue Bonds (“1993 Bond Borrowings”). The 1991 Bond Borrowings and the 1993 Bond Borrowings are secured by irrevocable letters of credit in the amounts of $30.1 million and $7.4 million, respectively, which were issued by the Banks. The interest rate at September 30, 2006 was 3.91%. The 1991 Bond Indenture Agreement requires repayment of the 1991 Bond Borrowings in four semi-annual installments of $1.2 million, $1.2 million, $14.8 million, and $12.4 million. The first installment of the 1991 Bond Borrowings is due in January 2008. The 1993 Indenture Agreement requires repayment of the 1993 Bond Borrowings in three semi-annual installments of $1.6 million, $1.8 million and $3.8 million. The first installment is due in July 2009.

               Irrevocable letters of credit in the amounts of $4.5 million and $1.5 million were issued to ROVA’s customer by the Banks on behalf of ROVA for ROVA I and ROVA II, respectively, to ensure performance under their respective power sales agreements.

               The debt agreements contain various restrictive covenants primarily related to construction of the facilities, maintenance of the property, and required insurance. Additionally, the financial covenants include restrictions on incurring additional indebtedness and property liens, paying cash distributions to the partners, and incurring various commitments without lender approval. At September 30, 2006, ROVA was in compliance with the various covenants.

               Pursuant to the terms of the Credit Agreement, ROVA must maintain a debt protection account (“DPA”). At September 30, 2006, the DPA was funded with $27.8 million which is included in restricted cash. Additional funding of the DPA of $1.1 million per year is required through 2008. The required funding level is reduced by $6.7 million in 2009 and by $3.0 million in 2010. Under the agreement, the Company can select from several investment options for the debt protection account funds and receives the investment returns on these deposits.

14

               The Credit Agreement requires ROVA to fund a repairs and maintenance account and an ash reserve account totaling $3.2 million between January 31, 2004 through January 31, 2010, after which date the funding requirement reduces to $2.8 million. The funds for the repairs and maintenance accounts are required to be deposited every six months based on a formula contained in the agreement. The ash reserve account was fully funded at September 30, 2006. As of September 30, 2006, these accounts had a combined balance of $1.2 million, which is included in restricted cash in the accompanying consolidated balance sheet.

7. DERIVATIVE INSTRUMENTS

               During the first quarter of 2006, the Company entered into two derivative contracts to manage a portion of its exposure to the price volatility of diesel fuel used in its operations. In a typical commodity swap agreement, the Company receives the difference between a fixed price per gallon of diesel fuel and a price based on an agreed upon published, third-party index if the index price is greater than the fixed price. If the index price is lower, the Company pays the difference. By entering into swap agreements, the Company effectively fixes the price it will pay in the future for the quantity of diesel fuel subject to the swap agreement.

               These contracts cover approximately 4 million gallons of diesel fuel which represent an estimated two-thirds of the annual consumption at the Jewett mine, at a weighted average fixed price of $2.01 per gallon. These contracts settle monthly from February to December, 2006. The Company accounts for these derivative instruments on a mark-to-market basis through earnings. The consolidated financial statements as of September 30, 2006 reflect unrealized losses on these contracts of $0.2 million, which is recorded in other receivables and as cost of sales—coal. During the three and nine months ended September 30, 2006, the Company settled a portion of these contracts covering approximately 1.2 million and 2.9 million gallons of fuel, respectively, which resulted in gains of approximately $0.1 million and $0.2 million, respectively.

               In October 2006 the Company entered into an additional derivative contract to manage a portion of its exposure to the price volatility of diesel fuel to be used in its operations in 2007. The contract covers 2.4 million gallons of diesel fuel at a weighted average fixed price of $2.02 per gallon. This contract settles monthly from January to December, 2007.

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8. BENEFIT PROGRAMS

HERITAGE HEALTH BENEFIT EXPENSES

               The caption “Heritage health benefit expenses” used in the Consolidated Statements of Operations refers to costs of benefits the Company provides as required by government regulations and programs, principally the Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”), contractually agreed benefits, past and current, and standard benefits provided voluntarily to attract and retain employees. The components of these expenses are:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006		2005			2006		2005
	(In thousands)
Health care benefits	$	4,469	$	5,819		$	16,430	$	17,319
Combined Benefit Fund		995		1,188			2,985		3,565
Workers’ compensation		177		260			547		730
Black lung benefits (credit)		221		(252	)		-		983
Total	$	5,862	$	7,015		$	19,962	$	22,597

PENSION AND POSTRETIREMENT MEDICAL BENEFITS

               The Company provides pension and postretirement medical benefits to qualified full-time employees and retired employees and their dependents, the majority of which benefits are mandated by the Coal Act. The Company incurred costs of providing these benefits during the three-month and nine-month periods ended September 30, 2006 and 2005 as follows:

	Pension Benefits Three months ended September 30,				Postretirement Medical Benefits Three months ended September 30,
	2006		2005		2006		2005
	(In thousands)
Service cost	$	765	$	672	$	158	$	129
Interest cost		1,053		902		2,454		3,639
Expected return on plan assets		(931	)	(850	)	-		-
Amortization of deferred items		351		248		2,417		2,286
Net periodic cost	$	1,238	$	972	$	5,029	$	6,054

	Pension Benefits Nine months ended September 30,				Postretirement Medical Benefits Nine months ended September 30,
	2006		2005		2006		2005
	(In thousands)
Service cost	$	2,492	$	2,016	$	474	$	387
Interest cost		3,159		2,706		9,854		10,916
Expected return on plan assets		(2,793	)	(2,550	)	-		-
Amortization of deferred items		1,053		743		7,251		6,858
Net periodic cost	$	3,911	$	2,915	$	17,579	$	18,161

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               The Company expects to contribute approximately $1.4 million to its pension plans during 2006. Of that amount, $0.5 million was contributed in the third quarter and $1.0 million has been contributed during the first nine months of 2006. The Company expects to pay approximately $19 to $20 million for postretirement medical benefits during 2006, net of Medicare Part D reimbursements. A total of $3.7 million was paid in the third quarter of 2006 and $15.6 million during the first nine months of 2006.

9. CAPITAL STOCK

               The Company has two classes of capital stock outstanding, common stock, par value $2.50 per share, and Series A Convertible Exchangeable Preferred Stock, par value $1.00 per share (“Series A Preferred Stock”). Each share of Series A Preferred Stock is represented by four Depositary Shares. The full amount of the quarterly dividend on the Series A Preferred Stock is $2.125 per preferred share or $0.53 per Depositary Share. Partial dividends have been declared and paid since October 1, 2002, including a dividend of $0.25 per Depositary Share paid on July 1, 2006. The quarterly dividends which are accumulated but unpaid through and including October 1, 2006 amount to $14.3 million in the aggregate ($89.44 per preferred share or $22.36 per Depositary Share). Common stock dividends may not be declared until the preferred stock dividends that are accumulated but unpaid are made current. Upon completion of the restatement of its prior period financial statements, as described in the 2005 Form 10-K/A, the Company is currently reporting a deficit in shareholders’ equity. As a result, the Company is currently prohibited from paying preferred stock dividends because of the statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which the Company is incorporated. Under Delaware law, the Company is permitted to pay preferred stock dividends only to the extent that shareholders’ equity exceeds the par value of the preferred stock ($160,000 at September 30, 2006).

               During the three and nine months ended September 30, 2006 the Company exchanged a total of 61,036 and 179,816 Depositary Shares, respectively, at an exchange ratio of 1.8691 shares of Common Stock for each Depositary Share, compared to the conversion ratio of 1.708 provided for under the terms of Certificate of Designation governing the preferred stock. As a result of these preferred stock exchanges, $0.2 and $0.8 million of premium on the exchange of preferred stock for common stock was recorded in the three and nine month periods ended September 30, 2006 as a reduction of income (loss) attributable to common shareholders. This premium on the exchange of preferred stock for common stock represents the excess of the fair value of consideration transferred to the preferred stock holders over the value of consideration that would have been issued under the original conversion terms. While the Company can redeem preferred shares at any time for the redemption value of $25 plus accumulated dividends paid in cash, the Company has agreed to the negotiated exchanges as a cash conservation measure and because they reduce the number of outstanding Depositary Shares, thereby eliminating $3.9 million of accumulated dividends and associated future dividend requirements.

INCENTIVE STOCK OPTIONS AND STOCK APPRECIATION RIGHTS

               As of September 30, 2006, the Company had stock options and stock appreciation rights (“SARs”) outstanding from three shareholder-approved Stock Plans for employees and three Stock Incentive Plans for directors.

               The employee plans provide for the grant of incentive stock options (“ISOs”), non-qualified options under certain circumstances, SARs and restricted stock. ISOs and SARs generally vest over two or three years, expire ten years from the date of grant, and may not have an option or base price that is less than the market value of the stock on the date of grant. The maximum number of shares that could be issued or granted under the employee plans is 1,150,000, and as of September 30, 2006, a total of 210,819 shares are available for future issue or grant.

               The non-employee director plans generally provide for the grant of options for 20,000 shares when elected or appointed, and options for 10,000 shares after each annual meeting. Beginning in 2003, rather than the annual grant of 10,000 options, each non-employee director was granted common shares with a market value of $30,000. The shares are restricted for one year from the date of grant. Additionally, each non-employee director is entitled to receive, as an individual grant upon first joining the Board, restricted common stock valued at $60,000. Beginning in 2006, directors were granted SARs as a form of award. The maximum number of shares that could be issued or granted under the director plans is 900,000, and as of September 30, 2006, 19,176 shares were available for future issue or grant.

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               On December 30, 2005 the Company accelerated the vesting of all unvested SARs, resulting in additional compensation expense of $0.5 million. The Company elected to accelerate the vesting of the SARs because doing so reduced the expense that the Company would be required to recognize in the future under SFAS No. 123(R). The Company granted 156,000 and 161,500 SARs under an employee plan during the three and nine months ended September 30, 2006 which vest over a three year period. The Company also granted 16,067 SARs under a non-employee director plan in the first nine months of 2006 which also vest over a three year period. No SARS were granted under the non-employee director plan during the three months ending September 30, 2006. The exercise price of each SAR is equal to the market value of a share of the Company’s common stock on the date of the grant. As of September 30, 2006, there was no intrinsic value for any SARs granted during 2006. Upon vesting, the holders may exercise the SARs and receive an amount equal to the increase in the value of the common stock between the grant date and the exercise date in shares of common stock.

               Compensation cost arising from share-based payment arrangements was $0.2 million in the quarter ended September 30, 2006 and $1.4 million during the first nine months of 2006. The intrinsic value of options and SARs exercised during the third quarter of 2006 and the first nine months of 2006 were less than $0.1 million and $3.0 million, respectively. Based on the market value of the Company’s common stock as of September 30, 2006, the intrinsic value of vested SARs was less than $0.1 million.

               Information for the first nine months of 2006 with respect to both the employee and director SARs is as follows:

	Base Price Range	Stock Appreciation Rights	Weighted Average Base Price
Outstanding at December 31, 2005	$ 15.01-29.48	401,194	$ 20.37
Granted in 2006	23.985-29.48	177,567	24.54
Exercised in 2006	19.365-24.725	(10,334)	20.71
Expired or forfeited in 2006	24.41	(800)	24.41
Outstanding at September 30, 2006	$ 15.01-29.48	567,627	$ 21.66

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Information about SARs outstanding as of September 30, 2006 is as follows:

Range of Base Price	Number Outstanding	Weighted Average Remaining Contractual Life (Years)	Weighted Average Base Price	SARs Vested	Weighted Average Base Price
$  18.04-29.48	567,627	9.3	$   21.66	390,860	$   20.37

               The weighted-average fair value of each SAR granted in 2006 and 2005 was $14.18 and $10.13 respectively. There will be no future compensation expense arising from the SARs granted prior to 2006 because of the accelerated vesting discussed above. The unamortized compensation expense for SARs outstanding at September 30, 2006 was $2.3 million.

               The fair value of SARs granted is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions for the nine months ended September 30, 2006 and 2005:

SARS Granted	Number of SARs Granted	Dividend Yield	Volatility	Risk-Free Rate	Expected Life
2006	177,567	None	52%	5.20%	6.5 years
2005	246,100	None	48%	3.85%	5.2 years

               No stock options were granted during 2005 or 2006. Information for the first nine months of 2006 with respect to both the employee and director stock options is as follows:

		Exercise Price Range	Stock Option Shares		Weighted Average Exercise Price
Outstanding at December 31, 2005	$	2.81-22.86	717,950	$	10.20
Granted in 2006		-	-		-
Exercised in 2006		2.81-18.19	(154,732)		6.06
Expired or forfeited in 2006		-	(1,068)		17.94
Outstanding at September 30, 2006	$	2.81-22.86	562,150	$	11.32

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               Information about stock options outstanding as of September 30, 2006 is as follows:

	Range of Exercise Price	Number Outstanding	Weighted Average Remaining Contractual Life (Years)		Weighted Average Exercise Price	Options Vested		Weighted Average Exercise Price
$	2.81-5.00	208,150	2.9	$	2.93	208,150	$	2.93
	5.01-10.00	-	-		-	-		-
	10.01-15.00	95,835	5.5		12.38	93,935		11.62
	15.01-22.86	258,165	6.2		17.70	228,379		17.54
$	2.81-22.86	562,150	4.9	$	11.32	530,464	$	10.91

               Prior to January 1, 2006, the Company applied the intrinsic-value-based method of accounting prescribed by Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees”, and related interpretations, to account for its fixed-plan stock options. Under this method, compensation expense was recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”), established accounting and disclosure requirements using a fair-value-based method of accounting for stock-based employee compensation plans. As allowed under SFAS No. 123, the Company had elected to continue to apply the intrinsic-value-based method of accounting described above, and adopted only the disclosure requirements of SFAS No. 123, prior to the adoption of SFAS 123(R) effective January 1, 2006. The following table illustrates the pro forma effect on net loss and net loss per share in 2005 as if the compensation cost for the Company’s fixed-plan stock options had been determined based on fair value at their grant dates consistent with SFAS No. 123:

		Three Months Ended 9/30/05		Nine Months Ended 9/30/05
		(In thousands)
Net loss applicable to common shareholders, as reported		$	(7,860)	$	(12,339)
Less:	Total stock-based employee compensation expense determined under fair value based method for all awards		62		231
Net loss applicable to common shareholders		$	(7,922)	$	(12,570)
Net loss per share applicable to common shareholders:
Basic – as reported		$	(0.95)	$	(1.49)
Basic – pro forma		$	(0.95)	$	(1.52)
Diluted – as reported		$	(0.95)	$	(1.49)
Diluted – pro forma		$	(0.95)	$	(1.52)

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10. 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		Nine Months Ended
	September 30,		September 30,
	2006	2005	2006	2005
	(In thousands of shares)
Number of shares of common stock:
Basic	8,948	8,302	8,671	8,255
Effect of dilutive SARs and stock options	274	-	385	-
Diluted	9,222	8,302	9,056	8,255
Number of shares not included in diluted EPS that would have been antidilutive because exercise price of SARs and options was greater than the average market price of the common shares	200	585	18	614

11. INCOME TAXES

               Income tax expense attributable to income before income taxes consists of:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
	(In thousands)				(In thousands)
Current:
Federal	$	-	$	(168)	$	25	$	-
State		213		1,536		708		2,996
		213		1,368		733		2,996
Deferred:
Federal		-		-		-		-
State		-		-		-		-
		-		-		-		-
Income tax expense	$	213	$	1,368	$	733	$	2,996

               During the three months ended September 30, 2005, the Company accrued $2.1 million for a North Carolina state income tax assessment.

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12. 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, including business development activities. The “Corporate” classification noted in the tables represents all costs not otherwise classified, including corporate office charges and heritage health benefit expenses. Summarized financial information by segment for the three and nine month periods ended September 30, 2006 and 2005 is as follows:

Quarter ended September 30, 2006
(Unaudited)

		Coal		Independent Power		Corporate		Total
		(In thousands)
Revenues:
Coal	$	106,227	$	-	$	-	$	106,227
Energy		-		25,437		-		25,437
Equity in earnings		-		84		-		84
		106,227		25,521		-		131,748
Costs and expenses:
Cost of sales		84,115		16,066		-		100,181
Depreciation, depletion and amortization		6,372		2,322		46		8,740
Selling and administrative		6,257		2,838		2,678		11,773
Heritage health benefit expenses		-		-		5,862		5,862
Loss (gain) on sales of assets		40		-		-		40
Operating income (loss)	$	9,443	$	4,295	$	(8,586)	$	5,152
Capital expenditures	$	5,930	$	327	$	147	$	6,404
Total assets	$	302,455	$	284,274	$	135,857	$	722,586

Quarter ended September 30, 2005
(Unaudited)

		Coal		Independent Power		Corporate		Total
		(In thousands)
Revenues:
Coal	$	94,141	$	-	$	-	$	94,141
Energy		-		-		-		-
Equity in earnings		-		1,682		-		1,682
		94,141		1,682		-		95,823
Costs and expenses:
Cost of sales		78,498		-		-		78,498
Depreciation, depletion and amortization		5,424		6		95		5,525
Selling and administrative		5,738		435		3,022		9,195
Heritage health benefit expenses		-		-		7,015		7,015
Loss (gain) on sales of assets		-		-		(28)		(28)
Operating income (loss)	$	4,481	$	1,241	$	(10,104)	$	(4,382)
Capital expenditures	$	3,831	$	26	$	(718)	$	3,139
Total assets	$	299,744	$	50,467	$	120,961	$	471,172

Nine Months ended September 30, 2006
(Unaudited)

		Coal		Independent Power		Corporate		Total
		(In thousands)
Revenues:
Coal	$	292,479	$	-	$	-	$	292,479
Energy		-		25,437		-		25,437
Equity in earnings		-		7,545		-		7,545
		292,479		32,982		-		325,461
Costs and expenses:
Cost of sales		230,331		16,066		-		246,397
Depreciation, depletion and amortization		17,977		2,387		209		20,573
Selling and administrative		17,091		4,868		9,094		31,053
Heritage health benefit expenses		-		-		19,962		19,962
Loss (gain) on sales of assets		154		-		(5,060)		(4,906)
Operating income (loss)	$	26,926	$	9,661	$	(24,205)	$	12,382
Capital expenditures	$	13,768	$	341	$	652	$	14,761
Total assets	$	302,455	$	284,274	$	135,857	$	722,586

Nine Months ended September 30, 2005
(Unaudited)

		Coal		Independent Power		Corporate		Total
		(In thousands)
Revenues:
Coal	$	265,468	$	-	$	-	$	265,468
Energy		-		-		-		-
Equity in earnings		-		10,310		-		10,310
		265,468		10,310		-		275,778
Costs and expenses:
Cost of sales		217,606		-		-		217,606
Depreciation, depletion and amortization		16,266		16		181		16,463
Selling and administrative		17,423		1,471		5,166		24,060
Heritage health benefit expenses		-		-		22,597		22,597
Loss (gain) on sales of assets		261		-		(110)		151
Operating income (loss)	$	13,912	$	8,823	$	(27,834)	$	(5,099)
Capital expenditures	$	15,003	$	44	$	407	$	15,454
Total assets	$	299,744	$	50,467	$	120,961	$	471,172

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13. COMMITMENTS AND CONTINGENCIES

Asset Retirement Obligation, Reclamation, Reclamation Deposits and Contractual Third Party Reclamation Obligations

               As of September 30, 2006 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 estimated at December 31, 2005 that the cost of final reclamation for its mines when they are closed at some point in the future will total approximately $396.1 million (on an undiscounted basis), or $158.4 million expressed on a present value basis. The Company’s customers and the contract operator of the Absaloka Mine are responsible for $200.9 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 $61.5 million as of September 30, 2006. 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 which has a balance of approximately $6.1 million as of September 30, 2006. 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 $195.2 million (on an undiscounted basis) at September 30, 2006.

               ROVA’s asset retirement obligation at September 30, 2006 was $0.4 million.

               Changes in the Company’s asset retirement obligations from January 1, 2006 to September 30, 2006 (in thousands) were:

Asset retirement obligations — beginning of year	$ 158,407
Accretion	8,105
ROVA asset retirement obligation assumed	414
Settlements (final reclamation performed)	(11,055)
Asset retirement obligations — September 30, 2006	$ 155,871

Royalty Claims

               The Company acquired Western Energy Company (“WECO”) from Montana Power Company in 2001. WECO produces coal from the Rosebud Mine, which includes federal leases, a state lease and some privately owned leases near Colstrip, Montana. The Rosebud Mine supplies coal to the four units of the adjacent Colstrip Power Plant. In the late 1970‘s, a consortium of six utilities, including Montana Power, entered into negotiations with WECO for the long-term supply of coal to Units 3 and 4 of the Colstrip Plant, which would not be operational until 1984 and 1985, respectively. The parties could not reach agreement on all the relevant terms of the coal price and arbitration was commenced. The arbitration panel issued its opinion in 1980. As a result of the arbitration order, WECO and the Colstrip owners entered into a Coal Supply Agreement and a separate Coal Transportation Agreement. Under the Coal Supply Agreement, the Colstrip Units 3&4 owners pay a price for the coal F.O.B. mine. Under the Coal Transportation Agreement, the Colstrip Units 3&4 owners pay a separate fee for the transportation of the coal from the mine to Colstrip Units 3&4 on a conveyor belt that was designed and constructed by WECO and has been continuously operated and maintained by WECO.

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               In 2002 and 2006, the State of Montana, as agent for the Minerals Management Service (“MMS”) of the U.S. Department of the Interior, conducted audits of the royalty payments made by WECO on the production of coal from the federal leases. The audits covered three periods: October 1991 through December 1995, January 1996 through December 2001, and January 2002 through 2004. Based on these audits, the Office of Minerals Revenue Management (“MRM”) of the Department of the Interior issued orders directing WECO to pay royalties in the amount of $8.6 million on the proceeds received from the Colstrip owners under the Coal Transportation Agreement during the three audit periods. Both held that the payments for transportation were payments for the production of coal. The Company believes that only the costs paid for coal production are subject to the federal royalty, not payments for transportation.

               WECO appealed the orders of the MRM to the Directors of MMS. On March 28, 2005, the MMS issued a decision stating that payments to WECO for transportation across the conveyor belt were part of the purchase price of the coal and therefore subject to the royalty charged by the federal government under the federal leases. However, the MMS dismissed the royalty claims for periods more than seven years before the date of the order on the basis that the statute of limitations had expired.

               On June 17, 2005, WECO appealed the decision of the MMS on the transportation charges to the United States Department of the Interior, Office of Hearings and Appeals, Interior Board of Land Appeals (“IBLA”). On September 6, 2005, the MMS filed its answer to WECO’s appeal. This matter is still pending before the IBLA.

               The total amount of the MMS royalty claims including interest through the end of 2003 was approximately $5.0 million. This amount, if payable, is subject to interest through the date of payment, and as discussed above, the audit only covered the period through 2001.

               In 2003, the State of Montana Department of Revenue (“DOR”) assessed state taxes for years 1997 and 1998 on the transportation charges collected by WECO from the Colstrip Units 3&4 owners. The taxes are payable only if the transportation charges are considered payments for the production of coal. The DOR is relying upon the same arguments used by the MMS in its royalty claims. WECO has disputed the state tax claims. It is anticipated that the state tax claims will be resolved following the outcome of WECO’s appeal of the MMS royalty claims or subsequent proceedings in federal court. The total of the state tax claims through the end of 1998, including interest through the end of 2003, was approximately $3.6 million. If this amount is payable it is subject to interest from the time the tax payment was due until it is paid.

               The MMS has asserted two other royalty claims against WECO. In 2002, the MMS held that “take or pay” payments received by WECO during the period from October 1, 1991 to December 31, 1995 from two Colstrip Units 3&4 owners were subject to the federal royalty. The MMS is claiming that these “take or pay” payments are payments for the production of coal, notwithstanding that no coal was produced. WECO filed a notice of appeal with MMS on October 22, 2002, disputing this royalty demand. No ruling has yet been issued by MMS. The total amount of the royalty demand, including interest through August 2003, is approximately $2.7 million.

               In 2004, the MMS issued a demand for a royalty payment in connection with a settlement agreement dated February 21, 1997 between WECO and one of the Colstrip owners, Puget Sound Energy. This settlement agreement reduced the coal price payable by Puget Sound as a result of certain “inequities” caused by the fact that the mine owner at the time, Montana Power, was also one of the Colstrip customers. The MMS has claimed that the coal price reduction is subject to the federal royalty. WECO has appealed this demand to the MMS, which has not yet ruled on the appeal. The amount of the royalty demand, with interest through mid-2003, is approximately $1.3 million.

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               Finally, in May 2005 the State of Montana asserted a demand for unpaid royalties on the state lease for the period from January 1, 1996 through December 31, 2001. This demand, which was for $0.6 million, is based on the same arguments as those used by the MMS in its claim for payment of royalties on transportation charges and the 1997 retroactive “inequities” adjustment of the coal price payable by Puget Sound.

               Neither the MMS nor the DOR has made royalty or tax demands for all periods during which WECO has received payments for transportation of coal. Presumably, the royalty and tax demands for periods after the years in dispute—generally, 1997 to 2001—and future years will be determined by the outcome of the pending proceedings. However, if the MMS and DOR were to make demands for all periods through the present, including interest, the total amount claimed against WECO, including the pending claims and interest thereon through September 30, 2006, could exceed $40 million.

               The Company believes that WECO has meritorious defenses against the royalty and tax demands made by the MMS and the DOR. The Company expects a favorable ruling from the IBLA, although it could be a year or more before the IBLA issues its decision. If the outcome is not favorable to WECO, the Company plans to seek relief in Federal district court.

               Moreover, in the event of a final adverse outcome with DOR and MMS, the Company believes that certain of the Company’s customers are contractually obligated to reimburse the Company for any royalties and taxes imposed on the Company for the production of coal sold to the Colstrip owners, plus the Company’s legal expenses. Consequently, the Company has not recorded any provisions for these matters. Legal expenses associated with these matters are expensed as incurred. WECO may be able to recover these expenses from the Colstrip owners upon the final determination of these claims.

Rensselaer Tax Assessment

               Niagara Mohawk Power Corporation (“NIMO”) was party to power purchase agreements with independent power producers, including the Rensselaer project, in which the Company owned an interest. In 1997, the New York Public Service Commission approved NIMO’s plan to terminate or restructure 29 power purchase contracts. The Rensselaer project agreed to terminate its Power Purchase and Supply Agreement after NIMO threatened to seize the project under its power of eminent domain. NIMO and the Rensselaer project executed a settlement agreement in 1998 with a payment to the project. On February 11, 2003, the North Carolina Department of Revenue notified the Company that it had disallowed the exclusion of gain as non-business income from the settlement agreement between NIMO and the Rensselaer project. The State of North Carolina assessed a current tax of $3.5 million, interest of $1.3 million (through 2004), and a penalty of $0.9 million. The Company consequently filed a protest. The North Carolina Department of Revenue held a hearing on May 28, 2003. In November 2003, the Company submitted further documentation to the State to support its position. On January 14, 2005, the North Carolina Department of Revenue concluded that the additional assessment is statutorily correct. On July 27, 2005, the Company responded to the North Carolina Department of Revenue providing additional information. 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 has accrued a reserve of $2.2 million at September 30, 2006, which is the amount at which the Company believes a settlement of this tax claim is likely.

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1992 UMWA Benefit Plan Surety Bond

               On May 11, 2005, XL Specialty Insurance Company and XL Reinsurance America, Inc. (together, “XL”), filed in the U.S. District Court, Southern District of New York, a Complaint for Declaratory Judgment against Westmoreland Coal Company and named Westmoreland Mining LLC as a co-defendant. The Complaint asks the court to confirm XL’s right to cancel a $21.3 million bond that secures Westmoreland’s obligation to pay premiums to the UMWA 1992 Plan, and also asks the court to direct Westmoreland to pay $21.3 million to XL to reimburse XL for the $21.3 million that would be drawn under the bond by the 1992 Plan Trustees upon cancellation of the bond.

               At a hearing held on January 31, 2006, the judge changed the venue to the United States District Court for New Jersey.

               The Company believes that it has no obligation to reimburse XL for draws under the bond unless the draw is the result of a default by the Company under its obligations to the UMWA 1992 Plan. No default has occurred. If XL prevails on its claim, the Company will be required to provide cash collateral of $21.3 million for its obligations to the 1992 Plan or, alternatively, provide a letter of credit.

Combined Benefit Fund

               Under the Coal Act, the Company is required to provide postretirement medical benefits for certain UMWA miners and their dependents by making payments into certain benefit plans, one of which is the Combined Benefit Fund (“CBF”).

               The Coal Act merged the UMWA 1950 and 1974 Benefit Plans into the CBF, and beneficiaries of the CBF were assigned to coal companies across the country. Congress authorized the Department of Health & Human Services (“HHS”) to calculate the amount of the premium to be paid by each coal company to whom beneficiaries were assigned. Under the statute, the premium was to be based on the aggregate amount of health care payments made by the 1950 and 1974 Plans in the plan year beginning July 1, 1991, less reimbursements, divided by the number of individuals covered. That amount is increased each year by a cost of living factor.

               Prior to the creation of the CBF, the UMWA 1950 and 1974 Plans had an arrangement with HHS pursuant to which they would pay the health care costs of retirees entitled to Medicare, and would then seek reimbursement for the Medicare-covered portion of the costs from HHS. The parties had numerous disputes over the years concerning the amount to be reimbursed, which led them to enter into a capitation agreement in which they agreed that HHS would pay the Plans a specified per-capita reimbursement amount for each beneficiary each year, rather than trying to ascertain each year the actual amount to be reimbursed. The capitation agreement was in effect for the plan year beginning July 1, 1991, the year specified by the Coal Act as the baseline for the calculation of Coal Act premiums.

               On August 12, 2005, the United States District Court for the District of Maryland issued a decision in a case filed by a large group of coal operators (including the Company) against the Commissioner of the Social Security Administration (“Social Security”), successor to HHS in this matter, and the Trustees of the UMWA Combined Benefit Fund (the “Trustees”). The case concerns the calculation of premiums payable to the CBF pursuant to the Coal Act. The dispute involves the proper definition of the term “reimbursements” as used in the statutory provision describing how premiums are to be calculated. The position of the coal operators is that “reimbursements” means actual reimbursements received by the CBF pursuant to the capitation agreement, whereas the Trustees have assessed the premiums based on the HHS calculation using the amounts of Medicare-covered expenses, i.e., the amounts that would be reimbursed to the CBF if the published reimbursement schedule for Medicare-covered expenses were being applied. The method of assessing “reimbursements” used by Social Security and the Trustees resulted in higher premiums for coal operators than would have been the case if the actual reimbursements received by the CBF had been used in the calculation of premiums.

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               This issue has been in litigation for over ten years and in two different United States Circuit Courts of Appeals. In 1995, the Court of Appeals for the Eleventh Circuit ruled, in a victory for coal companies, that the meaning of the statute was clear, i.e., that “reimbursements” meant the actual amount by which the CBF was reimbursed, regardless of the amount of the CBF’s Medicare-covered expenditures. In 2002, the Court of Appeals for the District of Columbia Circuit ruled that the statute was ambiguous, and remanded the case to the Commissioner of Social Security for an explanation of its interpretation so that the court could evaluate whether the interpretation was reasonable. In the August 2005 decision, the United States District Court for the District of Maryland agreed with the Eleventh Circuit that the term “reimbursements” unambiguously means the actual amount by which the CBF was reimbursed, and the Court granted summary judgment to the coal operators.

               The difference in premium payments for Westmoreland is substantial. Pursuant to the holdings of the Eleventh Circuit and the Federal District Court of Maryland, Westmoreland has overpaid and expensed premiums by more than $6 million for the period from 1993 through 2005.

               On August 25, 2005, the Trustees filed a motion with the Maryland District Court asking the court to clarify its order or grant a stay to prevent the coal operators from claiming a refund or applying the overpayment against current premiums pending appeal of the court’s order. No decision has been issued on this motion, and the Company expects it to be denied. Subsequently, the Commissioner of Social Security and the Trustees appealed the decision of the Maryland District Court to the United States Court of Appeals for the Fourth Circuit. The Company believes that the decision of the District Court will not be overturned on appeal.

               On December 2, 2005, the Maryland federal district court judge who granted summary judgment in favor of the coal companies on the premium calculation issue, held a hearing on the motion the CBF filed in August seeking an order barring the coal companies from offsetting their plan year 2006 premiums by the amount of the premium overpayments at issue in the case while the case is on appeal. The judge ruled that until the case is final, the CBF can retain the premium overpayments. However, the judge applied the new premium calculation prospectively.

               Oral arguments before the Fourth Circuit Court of Appeals were held on September 21, 2006.

               The Company paid premiums to the CBF of approximately $332,000 for each of the first nine months of 2006, compared to $396,000 per month prior to the Maryland District Court decision. The premiums will reduce to approximately $306,000 per month beginning in October, 2006.

Landowner Claim

               In 1998, Basin Resources Inc., a subsidiary of the Company, paid a landowner $48,000 to settle a claim that Basin’s operations had caused subsidence that damaged his home. On March 22, 2001, the landowner filed a second claim in Las Animas County Court, Colorado, again alleging that Basin’s operations had caused subsidence that damaged his home. Basin contested this claim. In December 2002, a judge of that court determined that subsidence had occurred and awarded the landowner damages of $622,000 plus attorney’s fees. Based on the court decision, the Company recorded a reserve for the amount of the award. The Company believes that this award was excessive, in part because the landowner’s own expert placed the cost of repair at less than $100,000. The Company also believes the settlement in the first case bars the second claim. The Company appealed to the Colorado Intermediate Court of Appeals, which affirmed the lower court’s decision on November 17, 2005. The Company’ motion for reconsideration, filed on December 1, 2005, was denied. The Company filed a Petition for Writ of Certiorari with the Colorado Supreme Court on March 27, 2006, which was also denied. Basin has no assets with which to pay the judgment. The Company believes it has no obligation to pay the obligations of Basin.

27

Derivative Action Brought by Washington Group International, Inc., in Connection With Sales Agency Agreement

               On February 17, 2006, the Company was served with a complaint filed by Washington Group International, Inc. (“WGI”) in Colorado District Court, City and County of Denver. The defendants in this legal action were Westmoreland Coal Company, Westmoreland Coal Sales Company (“WCSC”), Westmoreland Resources, Inc. (“WRI”), and certain directors and officers of WRI. WGI owns a 20% interest in WRI and the Company owns the remaining 80%. This litigation related to a coal sales agency agreement between WRI and WCSC, a wholly owned subsidiary of the Company, which was entered into in January of 2002. Under this coal sales agency agreement, WCSC agreed to act as agent for WRI in marketing and selling WRI’s produced coal in exchange for an agency fee per ton sold. WGI objected to this fee and claimed in its complaint that the directors of WRI and its President breached their fiduciary duty by granting an over-market agency fee to an affiliated company. WGI’s share of the amount in dispute, if the fee was to be rescinded retroactively to 2002 and the fee then in effect applied, is approximately $0.6 million. The Company believes that the sales agency fee reflects a fair rate for marketing and selling coal since 2002 and further believes that WCSC provides service to WRI for which it should be compensated at a fair rate. The Company has not reserved any amount in the financial statements for this claim.

               On April 3, 2006, WGI and the Company agreed to submit the determination of the coal sales agency fee to binding arbitration if the dispute cannot be resolved through negotiations and mediation. Pursuant to this agreement, the litigation described above was dismissed with prejudice. The Company and WGI are continuing negotiations in this matter.

West Virginia Flood Litigation

               From late 2001 to early 2003, the Company was named as a defendant in two civil actions filed in Boone County, West Virginia, in which the plaintiffs claimed to represent a class of people adversely affected by a large flood that occurred in southern West Virginia in early July 2001. Under a local court rule for “mass litigation,” those civil actions were referred to the West Virginia Circuit Court for Raleigh County, West Virginia, where the Company was joined in a consolidated proceeding with approximately 200 defendants named by more than 2,000 plaintiffs in thirty-five civil actions filed originally in eight counties in southern West Virginia. The Complaints were similar in that they alleged that the defendants were engaged in activities that altered the landscape causing excess amounts of surface water to flow upon plaintiffs’ lands, thereby causing damage to their property. The causes of action pleaded included strict liability, negligence, nuisance, trespass, and gross negligence or recklessness. All of the Complaints sought punitive damages. The Company responded to the complaints by denying liability. The Company was able to negotiate from plaintiffs’ counsel an informal dismissal of the Company without prejudice. However, when new Plaintiffs asserted claims in an Amended Complaint that was filed in the consolidated cases on September 30, 2005 in the West Virginia Circuit Court for Raleigh County, the Company was again included as a defendant, perhaps because the Company’s name appeared on pleadings filed early in this litigation. With the filing and service of amended complaints, the number of Plaintiffs now exceeds 4,000.

               On December 2, 2005, the Company responded to the Amended Complaint with a motion to dismiss the Company based on the expiration of the statute of limitations and other procedural grounds. The trial is scheduled to occur in stages, with each stage focusing on one or more particular watershed areas in southern West Virginia because each watershed has unique facts that are relevant to the issues of liability and damages. The first series of trials (organized by watershed then further by subwatershed) is underway in Raleigh County. That trial does not involve the Company, except to the extent that precedent-setting trial procedures and legal rulings are being set and made. In what could be called a “test case,” plaintiffs are proceeding generally only against the landowners that allowed mining and timbering on their properties, arguing that the combined effects of the extraction they allowed exacerbated flooding and that they should have foreseen that result.

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               At the appropriate time, the Company will attempt to obtain from plaintiffs’ counsel a voluntary dismissal based on the fact that it was not, at the time the flooding occurred, operating any mines in West Virginia, all active operations having ceased around 1995. If the Company is not dismissed as a defendant, it will vigorously contest liability because it believes strongly that the mining operations prior to 1995 had no impact on the flood damage that occurred in 2001. The Company has not reserved any amount in the financial statements for this claim.

Global Warming Class Action

               On April 26, 2006, the Company learned of a class action complaint filed in the United States District Court in the Southern District of Mississippi in which it was named as a defendant. The case, entitled Comer, et al. v Nationwide Insurance Company, et al. case No. 1: 05-cv-00436-RHW, has 14 named individuals as plaintiffs who filed the complaint on behalf of themselves and all others similarly situated. The defendants are: 7 large oil companies; the American Petroleum Institute; 1 to 100 unnamed oil and refining companies; 21 power generation companies; and 10 coal mining and/or coal leasing companies, including the Company. With respect to the coal companies, the complaint alleges that the defendants produced hydrocarbons that, when used in the production of electricity, caused the emission of “greenhouse gases”, which allegedly caused global warming, which allegedly caused, or added to, the destructiveness of Hurricane Katrina, which allegedly caused damage to the plaintiffs. The plaintiffs are seeking compensatory and punitive damages as well as expenses and legal costs.

               The Company believes there is no more than a remote possibility that it has any liability in this matter. The Company has not reserved any amount in the financial statements for this claim.

Coal Supply Agreements

               Westmoreland Partners, which owns ROVA, has two coal supply agreements with TECO Coal Corporation (“TECO”). If Westmoreland Partners continues to purchase coal under these contracts at the current volume and pricing and does not extend these coal supply agreements, then Westmoreland Partners would be obligated to pay TECO $6.6 million in the last three months of 2006, $25.6 million in each of 2007, 2008, 2009, and 2010, and an aggregate of $107.6 million after 2010.

29ITEM 2
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

Material Changes in Financial Condition from December 31, 2005 to September 30, 2006

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; the material weaknesses in the Company’s internal controls over financial reporting identified in Amendment No. 1 to the Annual Report on Form 10-K for the year ended December 31, 2005 (“Amendment No. 1 to our 2005 Form 10-K”), the associated ineffectiveness of the Company’s disclosure controls; 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 or obtain waivers from its lenders in cases of non-compliance; 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 deferred income tax assets; 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 ROVA and the structure of ROVA’s contracts with its lenders and Dominion Virginia Power; the effect of regulatory and legal proceedings; environmental issues, including the cost of compliance with existing and future environmental requirements; the contingencies of the Company discussed in Note 13 to the Consolidated Financial Statements; the risk factors set forth below; and the other factors discussed in Items 1, 2, 3 and 7 of Amendment No. 1 to our 2005 Form 10-K 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.

               References in this document to www.westmoreland.com, any variations of the foregoing, or any other uniform resource locator, or URL, are inactive textual references only. The information on our Web site or any other Web site is not incorporated by reference into this document and should not be considered to be a part of this document.

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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.

               On June 29, 2006, we purchased the remaining 50% ownership interest in the ROVA coal-fired plants, and we now own 100% of these plants, which have a total generating capacity of 230 MW. ROVA is baseloaded and supplies power pursuant to long-term contracts. We also own 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 in Colorado.

Challenges

               We believe that our principal challenges today include the following:

• integrating the newly acquired ROVA business;

• continuing to fund high heritage health benefit expenses which continue to be adversely affected by inflation in medical costs, potentially longer life expectancies for retirees and active employees and the failure of the UMWA retirement fund trustees to manage medical costs;

• maintaining and collateralizing, where necessary, our Coal Act obligations and reclamation bonds;

• funding required contributions to pension plans that are underfunded;

• obtaining adequate capital for on-going operations and our growth initiatives;

• complying with new environmental regulations, which have the potential to significantly reduce sales from our mines; and

• defending against claims for potential taxes and royalties asserted by various governmental entities, subject to reimbursement by customers in certain cases

               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.

               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.

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               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 obligations are the obligations to provide postretirement medical benefits, pension benefits, workers’ compensation and pneumoconiosis (black lung) benefits. We provide these benefits to our current and former employees and their dependents. See Notes 6, 7, 8, 9 and 10 to the Consolidated Financial Statements in Amendment No. 1 to our 2005 Form 10-K for more information about these assumptions, estimates, and obligations.

               We estimate the total amount of these obligations with the help of third party professionals using actuarial assumptions and information. Our estimates are sensitive to judgments we make about the discount rate, about the rate of inflation in medical costs, about mortality rates, and about the effect of the Medicare Prescription Drug Improvement and Modernization Act of 2003 or Medicare Reform Act on the benefits payable. We review these estimates and obligations at least annually.

               Actuarial valuations project that our retiree health benefit costs for current employees and retirees will continue at the current level for the remainder of 2006 and then decline to zero over the next approximately sixty years as the number of eligible beneficiaries declines. Beginning in 2006, we began receiving Medicare Part D prescription drug reimbursements. We expect that these reimbursements will reduce our cash costs by approximately $1.5 million in 2006.

               We expect to incur lower cash payments for workers’ compensation benefits in 2006 than in 2005 and expect that amount to decline over time. We anticipate that these payments will decline because we are no longer self-insured for workers’ compensation benefits and have had no new claimants since 1995.

               We do not pay pension or black lung benefits directly. These benefits are paid from trusts that we established and funded. As of September 30, 2006, our pension trusts were underfunded, and we expect to contribute approximately $1.4 million to these trusts in 2006. As of September 30, 2006, our Black Lung trust was overfunded by $7.4 million, and we do not expect to be required to make additional contributions to this trust.

               Asset Retirement Obligations, Reclamation Costs and Reserve Estimates

               Asset retirement obligations primarily relate to the closure of mines and the reclamation of land upon cessation of mining. We account for reclamation costs, along with other costs related to mine closure, in accordance with SFAS No. 143 – Asset Retirement Obligations or SFAS No. 143, which we adopted on January 1, 2003. This statement requires the Company to recognize the fair value of an asset retirement obligation in the period in which we incur that obligation. We capitalize the present value of our estimated asset retirement costs as part of the carrying amount of our long-lived assets.

               Certain of the Company’s customers have either agreed to reimburse the Company for reclamation expenditures as they are incurred or have pre-funded a portion of the expected reclamation costs. These funds will serve as sources for use in final reclamation activities.

               The liability “Asset retirement obligations” on our consolidated balance sheets 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 can and do change. Developments in our mining program also affect this estimate by influencing the timing of reclamation expenditures.

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               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.

Liquidity and Capital Resources

               Cash provided by operating activities was $19.7 million for the nine months ended September 30, 2006, compared with $17.0 million for the nine months ended September 30, 2005. Cash provided by operating activities increased due to the improvement in net income of $13.6 million, partially offset by an increase in net non-cash charges to income of $10.4 million and an increase in undistributed earnings from independent power projects of $6.6 million. Cash provided by operating activities includes $7.9 million invoiced under our power sales agreements, which has been recorded as deferred power sales revenue. Changes in working capital decreased cash provided by operating activities in 2006 by $3.0 million and increased cash provided by operating activities by $11.8 million in the 2005 period.

               Our working capital deficit was $70.4 million at September 30, 2006 compared to $20.1 million at December 31, 2005. The decrease in working capital resulted primarily from the short-term ROVA bridge financing, the consolidation of ROVA, which had negative working capital, and the elimination of deferred overburden removal costs as the result of a change in accounting principle discussed in Note 3 to our consolidated financial statements. This accounting adjustment had no effect on cash flows.

               We used $25.0 million of cash in investing activities in the nine months ended September 30, 2006 compared to $18.3 million in the nine months ended September 30, 2005. The increase was primarily driven by our $7.7 million investment for our ROVA acquisition (net of cash acquired). Cash provided by investing activities in 2006 included $5.1 million received from the sale of mineral interests. Cash used in investing activities in 2006 included $14.8 million of additions to property, plant and equipment for mine equipment and investment in a company-wide software system. Cash flows from investing activities in 2006 also included a $7.6 million increase in our restricted cash accounts, pursuant to Westmoreland Mining’s term loan agreement and as collateral for our surety bonds. Additions to property, mine equipment, development projects and investment in a new company-wide software system in the first nine months of 2005 totaled $15.5 million. Increases in restricted cash accounts, bond collateral, and reclamation deposits were $3.4 million in the first nine months of 2005.

               We received $14.9 million of cash from our financing activities in the nine months ended September 30, 2006. This increase was primarily driven by our $35 million of borrowings to finance the ROVA acquisition and was offset by the repayment of $22.2 million of long-term debt. Cash used in financing activities of $1.6 million in the first nine months of 2005 was primarily the result of $6.5 million in borrowings under revolving lines of credit offset by $7.6 million used for the repayment of long-term debt.

               Consolidated cash and cash equivalents at September 30, 2006 totaled $20.8 million, including $9.3 million at ROVA, $0.6 million at Westmoreland Power Inc., $0.4 million at Westmoreland Mining, $6.4 million at Westmoreland Resources and $4.1 million at our captive insurance subsidiary. Consolidated cash and cash equivalents at December 31, 2005 totaled $11.2 million, including $3.0 million at Westmoreland Mining, $4.2 million at Westmoreland Resources, and $3.4 million at the captive insurance subsidiary. The cash at Westmoreland Mining is available to the Company through quarterly distributions, as described below. The cash at our captive insurance subsidiary and Westmoreland Resources is available to the Company through dividends. The cash at ROVA is available to the Company through distributions after debt and debt reserve account requirements are met.

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               We had restricted cash and bond collateral, which were not classified as cash or cash equivalents, of $67.7 million at September 30, 2006 and $34.6 million at December 31, 2005. The restricted cash at September 30, 2006 included $29.0 million at ROVA in interest bearing debt service accounts and prepayment accounts and $26.3 million in Westmoreland Mining’s debt service reserve, long-term prepayment, and reclamation escrow accounts. At September 30, 2006, our reclamation, workers’ compensation and postretirement medical cost obligation bonds were collateralized by interest-bearing cash deposits of $12.7 million, which amounts we have classified as non-current assets. In addition, we had accumulated reclamation deposits of $61.5 million at September 30, 2006, which we received from customers of the Rosebud Mine to pay for reclamation.

               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 to be used to fund the $30 million balloon payment due December 31, 2008. The agreement restricts distributions to the extent funds are needed to maintain a debt service reserve equal to the next nine months principal and interest payments. At September 30, 2006, Westmoreland Mining had $10.2 million in the debt service reserve account.

               Westmoreland Mining has a $20 million revolving credit facility which expires in April 2008. As of September 30, 2006, a letter of credit for $1.9 million was supported by the facility with the remainder of the facility available to borrow. As of September 30, 2006, Westmoreland Coal Company had $6.9 million of its $14.0 million revolving line of credit available to borrow.

               During the first nine months of 2006, the Company exchanged a total of 179,816 Depositary Shares at an exchange ratio of 1.8691 shares of Common Stock for each Depositary Share, compared to the conversion ratio of 1.708 provided for under the terms of Certificate of Designation governing the preferred stock. As a result of these preferred stock exchanges, $0.2 million and $0.8 million of premium on the exchange of preferred stock for common stock was recorded in the three and nine months ended September 30, 2006, respectively, as a reduction of income (loss) attributable to common shareholders. This premium on the exchange of preferred stock for common stock represents the excess of the fair value of consideration transferred to the preferred stock holders over the value of consideration that would have been issued under the original conversion terms. While the Company can redeem preferred shares for cash at any time for the redemption value of $25 plus accumulated dividends, the Company has agreed to the negotiated exchanges as a cash conservation measure and because they reduce the number of outstanding Depositary Shares, thereby eliminating $3.9 million of accumulated dividends and associated future dividend requirements.

               The changes in the Company’s current installments of long-term debt, trade accounts payable, interest payable, long-term debt, and revolving lines of credit are primarily attributable to the assets acquired and the liabilities incurred and assumed as part of the ROVA acquisition.

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Financial Implications of the ROVA Acquisition

               In June 2006, we acquired the 50% interest in the ROVA project that we did not previously own. As part of that transaction, we also acquired five contracts from LG&E Power Services. Pursuant to these contracts two new subsidiaries of the Company, Westmoreland Power Operations and Westmoreland Utility Operations, will now operate the ROVA project and four other power plants.

               ROVA sells electric power under two power sales agreements, one that expires in 2019 and one that expires in 2020. Capacity charges are calculated based on a rate for each MW-hour of electricity produced. The ROVA I per kilowatt hour capacity charge is fixed from 2006 through 2008 and then steps down to a new lower rate in May 2009 through the end of the power sales agreement in 2019. The ROVA II per kilowatt hour capacity charge is fixed from 2006 through 2009 and then steps down to a new lower rate in June 2010 through the end of the power sales agreement in 2020. ROVA’s indebtedness was structured so that ROVA’s principal and interest payments are relatively higher through 2009 and relatively lower thereafter. ROVA’s power sales agreements are structured to provide ROVA sufficient cash to repay its lenders and thus the capacity charges are relatively higher through 2009 and relatively lower thereafter.

               ROVA’s historical accounting policy for revenue recognition of these capacity charges has been to record them as revenue as amounts were invoiced pursuant to the provisions of the power sales agreements. Revenue recognition rules now require the Company to record these capacity charges ratably over the remaining term of the power sales agreements, irrespective of when the amounts are billed and collected. This change, while having no effect on cash flow or total revenue recognized over the remaining term of the power sales agreements, will have a significant impact on the timing of the recognition of revenue and income at ROVA.

               These two power sales agreements were entered into prior to the effective date of EITF 91-06, “Revenue Recognition of Long-Term Power Sales Contracts” and EITF 01-08, “Determining Whether an Arrangement Contains a Lease”. Accordingly, ROVA’s power sales agreements were not subject to the accounting requirements of these pronouncements. The completion of the ROVA acquisition triggered the two power sales agreements to be within the scope of EITF 01-08. Under EITF 01-08, each of the power sales agreements is considered to contain a lease within the scope of SFAS No. 13, “Accounting for Leases”. Each such lease is classified as an operating lease. As a result, the Company must recognize revenue for future capacity charges ratably over the remaining term of the power sales agreements.

               In our historical financial statements, earnings from our original 50% interest in ROVA appeared as “equity in earnings—independent power” because ROVA was an equity method affiliate. Because we now own 100% of ROVA, it is now fully consolidated in our financial statements. The pro forma impact of our ownership of 100% of ROVA is shown in our Form 8-K/A filed with the Securities and Exchange Commission on November 6, 2006. On a pro forma basis, if the ROVA transaction had occurred on January 1, 2005, the net loss attributable to common stockholders for the year ended December 31, 2005 would have increased to approximately $26.7 million compared to the amount reported in the historical financial statements of $7.7 million. If the ROVA transaction had occurred on January 1, 2006, the net loss applicable to common shareholders for the nine months ended September 30, 2006 would have been $7.9 million. For the first nine months of 2005 had the transaction occurred on January 1, 2005 the pro forma net loss applicable to common shareholders would have been $24.4 million. The pro forma financial statements include pro forma adjustments to reflect capacity charges under the power sales agreements ratably over the term of the agreements, adjustments to reflect interest expense on debt incurred to finance the acquisition, and adjustments to reflect depreciation and amortization on the adjusted basis in the asset and liabilities acquired. For more information, please see our Form 8-K/A.

               Substantial debt was incurred to finance ROVA’s development. Westmoreland Partners, which owns ROVA, is required to make principal payments on its indebtedness of $27.7 million in 2007, $32.3 million in 2008, $31.2 million in 2009, $15.3 million in 2010, and $51.5 million from 2011 through 2015, when ROVA’s project debt is completely repaid.

35

               We incurred $35 million of indebtedness to fund the ROVA acquisition. For more information about this indebtedness, see Notes 2 and 6 to our consolidated financial statements.

Liquidity Outlook

               The major factors impacting the Company’s liquidity outlook are its significant heritage health benefit costs, its acquisition debt and add-on debt repayment obligations for WML, its recent acquisition debt and existing project debt obligations for ROVA, and its ongoing business and future growth requirements. The Company’s principal sources of cash flow are dividends from WRI, distributions from ROVA and from WML subject to the provisions in their respective debt agreements, dividends from the subsidiaries that operate power plants and periodic dividends from WRM.

               The Company’s heritage health benefit costs consist primarily of payments for post-retirement medical and workers’ compensation benefits. The Company also is obligated for employee pension and pneumoconiosis benefits. It is important to note that retiree health benefit costs are directly affected by increases in medical service and prescription drug costs. The most recent actuarial valuations of the Company’s post-retirement medical obligations indicated that the Company’s 2006 retiree health benefit expenses would be comparable in amount to the 2005 expenses and then decline to zero over the next approximately sixty years as the number of eligible beneficiaries declines. The Company incurred cash costs of $20 million for heritage health benefit costs in 2005 and expects to incur $19 to $20 million (net of the receipt of approximately $1.5 million in Medicare D subsidies) for these costs in 2006.

               The Company’s WML acquisitions in 2001 greatly increased revenues and operating cash flow. The financing obtained to make those acquisitions requires quarterly interest and principal payments of approximately $4 million. This debt financing also requires that 25% of excess cash flow, as defined, be set aside to fund the $30 million debt payment due in December 2008. Therefore, only 75% of WML’s excess cash flow is available to the Company until this debt is paid off in 2008. WML also entered into the add-on debt facility in 2004 which requires the use of approximately $1 million of cash each quarter for debt service.

               In addition to the WML acquisitions, in June 2006, the Company acquired the 50% interest in ROVA that it did not previously own, which is expected to increase revenues and operating cash flow. This acquisition was funded with $35 million in debt as described in Note 2 to the financial statements. ROVA also has project-level debt which funded the original development of the power plants. The project-level debt requires semi-annual principal payments as described in Note 6 to the financial statements as well as ongoing interest payments. The acquisition debt requires approximately $0.8 million each quarter for interest in addition to semi-annual principal payments of approximately $4.3 million. During the term of this acquisition debt, the Company expects that substantially all of the cash distributions generated by ROVA will be used to make these interest and principal payments.

               The Company’s ongoing and future business needs may also affect liquidity. The Company does not anticipate that either its coal or its power production revenues will diminish materially as a result of any future downturn in economic conditions because the independent power projects in which the Company owns interests and the power plants that purchase coal mined by the Company produce relatively low-cost, baseload power. In addition, most of the Company’s coal and power production is sold under long-term contracts, which help insulate the Company from unfavorable market developments. However, contract price reopeners, contract expirations or terminations, and market competition could affect future coal revenues.

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               The Company currently has sufficient cash resources and committed financing arrangements to provide adequate liquidity through early 2007. The Company believes it should be able to address its future liquidity needs through additional financing activities and/or by selling assets. Sources of additional liquidity may include additional borrowings, the restructuring of current debt obligations, the sale of non-strategic assets, and the issuance of additional equity. The Company has taken specific actions, including discussions with potential lenders, investors and asset purchasers regarding potential transactions that the Company believes can be completed. There can be no assurance that the Company can complete any transaction on terms acceptable to the Company.

Growth and Development

               We describe in Note 2 of the Consolidated Financial Statements of this Form 10-Q our June 29, 2006 acquisition of the ROVA interest from E.ON US LLC and we discussed the financial implications of this transaction above. We discuss other growth and development opportunities in Amendment No. 1 to our 2005 Form 10-K. Please review these disclosures for more information.

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.

Contractual Commitments

               As a result of the ROVA acquisition, our contractual obligations and commitments increased. We describe our additional contractual obligations to purchase coal under long-term contracts for ROVA in Note 13 of the consolidated financial statements of this Form 10-Q, under “Coal Supply Agreements”. We describe our additional debt obligations in Notes 2 and 6 to our unaudited consolidated financial statements.

37RESULTS OF OPERATIONS

Quarter Ended September 30, 2006 Compared to Quarter Ended September 30, 2005.

Coal Operations. Coal tons sold were approximately 2% lower in the quarter ended September 30, 2006 compared to the same quarter in 2005, with decreases at Jewett, Rosebud and Absaloka partially offset by increases at Beulah and Savage. The decreases at Jewett, Rosebud, and Absaloka were primarily the result of customer outages, customer requests to accelerate shipments to the first two quarters of 2006, and decreased operational performance by the Absaloka contract mine operator. The Company has filed suit in Montana federal district court for what it believes are material breaches by the contract mining company of their obligations under the contract mining agreement. Our overall revenue has increased due to higher prices at all mines. Most of the Company’s coal sales contracts provide partial or substantial, and in some cases complete, protection of our operations against cost inflation, including increasing costs for commodities, either through direct pass-through or through index adjustments. During the third quarter of 2006, coal revenues increased at the Absaloka Mine compared to 2005 as a result of increased prices to its core customers despite a decrease in tons sold. At Jewett, increased revenue in the third quarter of 2006 reflected the interim supply agreement negotiated in 2005 despite a decrease in tons sold. Cost of sales increased for the third quarter of 2006 compared to the comparable period in 2005 primarily as a result of increased operating costs, including commodity prices (fuel, electricity, and explosives) at all mines, and higher stripping ratios at Rosebud and Beulah.

               The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods:

	Quarter Ended September 30,
		2006		2005	Change
Revenues – thousands	$	106,227	$	94,141	13%
Volumes – millions of equivalent coal tons		7.869		8.010	-2%
Cost of sales – thousands	$	84,115	$	78,498	7%

               The Company’s business is subject to the effects of weather and some seasonality. The power-generating plants that we supply typically schedule their regular maintenance for the spring and fall seasons.

Independent Power. Power segment operating income was $4.3 million in the quarter ended September 30, 2006 compared to $1.2 million in the third quarter 2005. Our energy revenues and costs and expenses were $25.4 million and $16.1 million during the third quarter of 2006, compared to equity in earnings from independent power operations of $1.7 million in the quarter ended September 30, 2005. This change in presentation was due to our second quarter 2006 acquisition and consolidation of our ROVA results of operations beginning in the third quarter. Also in connection with the acquisition, the Company changed its method of recognizing revenue under its long-term power sales agreements (see Financial Implications of the ROVA Acquisition). For the three months ended September 30, 2006, revenue received under these agreements totaling $7.9 million was deferred. For the quarters ended September 30, 2006 and 2005, ROVA produced 457,000 and 381,000 megawatt hours, respectively, and achieved average capacity factors of99% and 82%, respectively. The reduction in the third quarter of 2005 includes the effect of scheduled and forced outages at ROVA I and forced outages at ROVA II compared to only minimal forced outages at ROVA II during the third quarter of 2006. Maintenance outages are scheduled for both units during the fourth quarter of 2006. We also recognized $84,000 in equity earnings in the third quarter of 2006, compared to $70,000 in the quarter ended September 30, 2005, from our 4.49% interest in the Ft. Lupton project.

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               Costs and Expenses.Depreciation, depletion and amortization increased to $8.7 million in the third quarter of 2006 compared to $5.5 million in 2005‘s third quarter. The increase is primarily related to the consolidation of ROVA which increased depreciation by $2.2 million, increased capital expenditures at the mines for continued mine development and the replacement of mining equipment, and increased amortization of capitalized asset retirement costs.

               Selling and administrative expenses increased to $11.8 million in the quarter ended September 30, 2006 compared to $9.2 million in the quarter ended September 30, 2005. The significant contributors to the quarter-over-quarter increase were consulting and audit fees related to the restatement of our 2005 financial statements, additional accounting staff, personnel and related costs incurred as part of our investment in development activities, and selling and administrative expenses resulting from our consolidation of ROVA of $1.2 million. These expenses were partially offset by reversals of a portion of our long-term incentive compensation accruals totaling $0.4 million as the price of the Company’s stock decreased in the three months ended September 30, 2006.

               Heritage health benefit costs decreased to $5.9 million in the third quarter of 2006 from $7.0 million in the third quarter of 2005 due primarily to a reduction of $1.0 million in the accruals for our postretirement medical benefits reflected in updated actuarial projections. Also contributing to our lower heritage health benefit costs were lower Combined Benefit Fund premiums which were partially offset by an increase in our Black Lung benefit expense as a result of a decline in the value of the Black Lung Trust assets.

               Interest expense was $7.0 million for the three months ended September 30, 2006, compared to $2.8 million of interest expense for the quarter ended September 30, 2005, primarily as a result of our consolidation of ROVA including the ROVA project debt which increased interest expense by $4.5 million. Interest income increased in 2006 due to higher short-term investments earning interest and because there were larger restricted cash and surety bond collateral balances that are invested, after our ROVA acquisition.

               Current income tax expense was $0.2 million and $1.4 million for the three months ended September 30, 2006 and 2005, respectively. Deferred tax expense accrued on income before tax was offset by a change in the valuation allowance. Current income tax expense includes state income taxes payable in certain states and alternative minimum tax. The current income tax expense for the third quarter of 2005 included a $2.1 million accrual for the North Carolina state income tax assessment.

Nine months Ended September 30, 2006 Compared to Nine months Ended September 30, 2005.

Coal Operations. Coal tons sold were approximately 4% lower in the first nine months ended September 30, 2006 compared to the first nine months in 2005, with decreases at Absaloka, Beulah and Rosebud partially offset by increases at Jewett and Savage. The decreases at Beulah and Rosebud were primarily the result of customer outages. The decrease at Absaloka relates to decreased operational performance by our contract mine operator. Our overall revenue increased due to higher prices at all mines. Most of the Company’s coal sales contracts provide partial or substantial, and in some cases complete, protection of our operations against cost inflation, including increasing costs for commodities, either through direct pass-through or through index adjustments. During the first nine months of 2006, coal revenues decreased at the Absaloka Mine compared to 2005 as a result of lower sales related to contract mine operator performance. At Jewett, increased revenue in the first nine months of 2006 reflected the interim supply agreement negotiated in 2005, including a small amount of above-contract tonnage sold at above-contract rates, whereas revenue in the first nine months of 2005 included a one-time $2.4 million “catch-up” payment to recover portions of prior year cost increases for commodities. Cost of sales increased for the first nine months of 2006 compared to the comparable period in 2005 primarily as a result of increased operating costs including commodity prices at all mines (fuel, electricity, and explosives), higher stripping ratios at Rosebud and Beulah, and increased costs related to the operational performance at our Absolaka mine. During the first nine months of 2006, the Rosebud mine signed new 3-year labor agreements with the union which represents the mine’s operating personnel.

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               The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods:

	Nine Months Ended September 30,
		2006		2005	Change
Revenues – thousands	$	292,479	$	265,468	10%
Volumes – millions of equivalent coal tons		21.836		22.709	-4%
Cost of sales – thousands	$	230,331	$	217,606	6%

               The Company’s business is subject to the effects of weather and some seasonality. The power-generating plants that we supply typically schedule their regular maintenance for the spring and fall seasons.

Independent Power. Power segment operating income was $9.7 million in the first nine months of 2006 compared to $8.8 million in the first nine months of 2005. Our equity in earnings from independent power operations was $7.5 million in the first nine months of 2006. In addition, we had $25.4 million and $16.1 million of energy revenues and costs, respectively, from the consolidation of the ROVA results of operations for the third quarter of 2006. Also in connection with the acquisition, the Company changed its method of recognizing revenue under its long-term power sales agreements (see Financial Implications of the ROVA Acquisition). For the nine months ended September 30, 2006, revenue totaling $7.9 million received under the agreements was deferred. For the nine months ended September 30, 2006 and 2005, ROVA produced 1,263,000 and 1,191,000 megawatt hours, respectively, and achieved average capacity factors of90% and 87%, respectively. We also recognized $327,000 in equity earnings in the first nine months of 2006, compared to $296,000 in the first nine months of 2005, from our 4.49% interest in the Ft. Lupton project.

Costs and Expenses.Depreciation, depletion and amortization increased to $20.6 million in the first nine months of 2006 compared to $16.5 million in 2005‘s first nine months. The increase is primarily related to our consolidation of ROVA, which increased depreciation by $2.2 million, 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.

               Selling and administrative expenses increased to $31.1 million in the nine months ended September 30, 2006 compared to $24.1 million in the nine months ended September 30, 2005. Approximately $1.3 million of the increase is a result of an expense of less than $0.1 million for our long-term performance unit plan during the first nine months of 2006, compared to a decrease in expense of $1.2 million in the first nine months of 2005 when the Company’s stock price decreased relative to certain stock indices. Prior to the adoption of FAS 123(R), the Company’s stock appreciation rights were accounted for under variable plan accounting. In general, this expense increases or decreases as the market price of the Company’s common stock increases or decreases. The other significant contributors to the first nine months-over-first nine months increase were approximately $1.6 million of costs for consulting and audit fees related to the restatement of our 2005 financial statements, additional accounting staff, personnel and related costs incurred as part of our investment in development activities, and selling and administrative expenses resulting from our consolidation of ROVA of $1.2 million.

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               Heritage health benefit costs decreased to $20.0 million in the first nine months of 2006 from $22.6 million in the first nine months of 2005 due primarily to a reduction of $1.0 million in the accruals for our postretirement medical benefits reflected in updated actuarial projections. Also contributing to our lower heritage health benefit costs were lower Combined Benefit Fund premiums and an increase in the amount by which the Black Lung trust is over-funded as a result of increased discount rates that decreased the black lung liabilities.

               Interest expense was $12.5 million and $8.5 million for the nine months ended September 30, 2006 and 2005, respectively. The increase was due primarily to interest on the ROVA acquisition debt and the consolidation of ROVA including the project debt which increased interest expense by $4.5 million. Interest income increased in 2006 due to higher short-term investments earning interest and because there were larger restricted cash and surety bond collateral balances that are invested, after our ROVA acquisition.

               Current income tax expense was $0.7 million and $3.0 million for the nine months ended September 30, 2006 and 2005, respectively. Deferred tax expense (benefit) accrued on income (loss) before tax in 2006 and 2005 was offset by a change in the valuation allowance. Current income tax expense includes state income taxes payable in certain states and alternative minimum tax. The 2005 current income tax expense included a $2.1 million accrual for the North Carolina state income tax assessment.

41ITEM 3
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

               The Company is exposed to market risk, including the effects of changes in commodity prices and interest rates as discussed below.

Commodity Price Risk

               The Company produces and sells commodities – principally coal and electric power – and also purchases commodities – principally diesel fuel, steel and electricity.

               The Company produces and sells coal through its subsidiaries, Westmoreland Resources, Inc., Westmoreland Mining LLC, and Westmoreland Coal Sales Co., and the Company produces and sells electricity and steam through its subsidiary Westmoreland Energy LLC. Nearly all of the Company’s coal production and all of its electricity and steam production are sold through long-term contracts with customers. These long-term contracts reduce the Company’s exposure to changes in commodity prices. These contracts typically contain price escalation and adjustment provisions, pursuant to which the price for our coal may be periodically revised. The price may be adjusted in accordance with changes in broad economic indicators, such as the consumer price index; commodity-specific indices, such as the PPI-light fuel oils index; and/or changes in our actual costs. Contracts may also contain periodic price reopeners or renewal provisions, which give us the opportunity to adjust the price of our coal to reflect developments in the marketplace.

               The Company also purchases commodities. The Company manages some of the risk associated with the costs of these commodities by entering into contracts for the sale of its products with the adjustment features discussed above. In addition, during the first quarter of 2006, Westmoreland Mining LLC entered into derivative contracts to establish a fixed price for approximately 65% of the estimated diesel fuel needs at the Jewett Mine for 2006. These contracts settle monthly through the end of 2006 and cover approximately 4.0 million gallons of diesel fuel at an average price of $2.01 per gallon. The Company accounts for these derivative instruments on a mark-to-market basis through earnings. The consolidated financial statements as of September 30, 2006 reflect unrealized losses on these contracts of $0.2 million, which is recorded in other receivables with a corresponding adjustment to cost of sales.

               In October 2006, the Company entered into an additional derivative contract to manage a portion of its exposure to the price volatility of diesel fuel to be used in its operations in 2007. The contract covers 2.4 million gallons of diesel fuel at a weighted average fixed price of $2.02 per gallon. This contract settles monthly from January through December, 2007.

Interest Rate Risk

               The Company and its subsidiaries are subject to interest rate risk on its debt obligations. The Company’s revolving lines of credit have a variable rate of interest indexed to either the prime rate or LIBOR. Based on balances outstanding on the lines of credit as of September 30, 2006, a one percent change in the prime interest rate or LIBOR would increase or decrease interest expenses by $71,000 on an annual basis. Westmoreland Mining’s Series D Notes under its term loan agreement have a variable interest rate based on LIBOR. A one percent change in the LIBOR would increase or decrease interest expense on the Series D Notes by $146,000 on an annual basis. A portion of ROVA’s project debt under its Credit Agreement also has a variable interest rate based on LIBOR. A one percent change in the LIBOR would increase or decrease interest expense on ROVA’s debt by $0.9 million on an annual basis. The Company’s ROVA acquisition debt also has variable interest rates based on LIBOR. A one percent change in the LIBOR would increase or decrease interest expense on the acquisition term loan by approximately $0.4 million on an annual basis.

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               The Company’s heritage health benefit expenses are also impacted by interest rate changes because its workers compensation, pension, pneumoconiosis, and post-retirement medical benefit obligations are recorded on a discounted basis.

               The carrying value and estimated fair value of the Company’s long-term debt with fixed interest rates at September 30, 2006 were $155.0 million and $164.2 million, respectively.

43ITEM 4
CONTROLS AND PROCEDURES

               The Company’s management, with the participation of the Company’s chief executive officer and chief financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of September 30, 2006. 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.

               As disclosed in Amendment No. 1 to our Form 10-K, the Company has restated its previously issued consolidated financial statements as of December 31, 2005 and 2004 and for the years ended December 31, 2005, 2004 and 2003, and selected financial information for the years 2001 to 2005. The consolidated balance sheets and statements of operations have been restated to correct errors in the Company’s accounting for income taxes, its accounting for asset retirement obligations, and the classification of restricted cash. The restatement adjustments had no effect on the cash flows of the Company for any of the periods presented.

               As a result of the need to restate its previously issued financial statements, the Company’s chief executive officer and chief financial officer concluded that, as of September 30, 2006, the Company’s disclosure controls and procedures were not effective. 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 September 30, 2006 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1
LEGAL PROCEEDINGS

               The Company is party to litigation described in this Form 10-Q in Note 13 to our Consolidated Financial Statements.

Litigation against Washington Group International, Inc.

               On October 16, 2006, Westmoreland Resources, Inc. (“WRI”) brought a lawsuit against Washington Group International, Inc. (“WGI”) in the United States District Court for the District of Montana. The Company owns 80% of WRI and WGI owns the remaining 20%. WGI also conducts all mining at the WRI Absaloka Mine under a long-term contract with WRI. The complaint filed by WRI alleges that WGI failed to meet its obligations under the mining contract and asks the court to affirm the right of WRI to terminate the mining contract with WGI. The complaint also seeks unspecified damages from WGI, which includes the incremental cost to WRI of purchasing approximately 300,000 tons of coal from Western Energy Company, a subsidiary of the Company, to meet delivery requirements of WRI customers.

ITEM 1A
RISK FACTORS

               In addition to the trends and uncertainties described elsewhere in Management’s Discussion and Analysis of Financial Condition and Results of Operations, we are subject to the risks set forth below.

Our coal mining operations are inherently subject to conditions that could affect levels of production and production costs at particular mines for varying lengths of time and could reduce our profitability.

               Our coal mining operations are all surface mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production and increase the cost of mining at particular mines for varying lengths of time and negatively affect our profitability. These conditions or events include:

• 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:

• During the first quarter of 2006, the dragline at the Absaloka Mine was unable to operate for almost one-half of the quarter due to repairs to a broken walking shoe and to its electrical systems.

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• In the second quarter of 2005, our Beulah Mine experienced unusually heavy rainfall including record rainfall in June that adversely impacted overburden stability and resulted in highwall and spoil sloughage, a condition in which the side of the pit partially collapses and must be stabilized before mining can continue. Unstable conditions in the pits impacted dragline operations at that mine for a period of time. This resulted in a reduction in coal production during the quarter which negatively affected third and fourth quarter results in 2005.

Our revenues and profitability could suffer if our customers reduce or suspend their coal purchases.

               In 2005, we sold approximately 99% 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 Generating Station, Colstrip Units 3&4 and Colstrip Units 1&2, accounted for 31%, 21% and 11%, respectively, of our coal revenues for 2005. Interruption in the purchases by or operations of our principal customers could significantly affect our revenues and profitability. Unscheduled maintenance outages at our customers’ power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. Four of our five mines are dedicated to supplying customers located adjacent to or near the mines, and these mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.

Disputes relating to our coal supply agreements could harm our financial results.

               From time to time, we may have disputes with customers under our coal supply agreements. These disputes could be associated with claims by our customers that may affect our revenue and profitability. Any dispute that resulted in litigation could cause us to pay significant legal fees, which could also affect our profitability.

We are a party to numerous legal proceedings, some of which, if determined unfavorably to us, could result in significant monetary damages.

               We are a party to several legal proceedings which are described more fully in Note 13 (“Commitments and Contingencies”) to our Consolidated Financial Statements. Adverse outcomes in some or all of the pending cases could result in substantial damages against us or harm our business.

We may not be able to manage our expanding operations effectively, which could impair our profitability.

               At the end of 2000, we owned one mine and employed 31 people.  In the spring of 2001, we acquired the Rosebud, Jewett, Beulah and Savage Mines from Entech and Knife River Corporation, and at the end of 2005, we employed 1,052 people, including employees at subsidiaries.  In June 2006, we acquired ROVA and the operating agreements, and as of September 30, we employed 1,335 people, including employees at subsidiaries. This growth has placed significant demands on our management as well as our resources and systems. One of the principal challenges associated with our growth has been, and we believe will continue to be, our need to attract and retain highly skilled employees and managers. In the second quarter of 2005, we hired a new Chief Financial Officer and new General Counsel. Ten of the thirteen professional positions in our corporate-level finance and accounting department and three of the positions in our legal department are 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.  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.

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The implementation of a new company-wide computer system could disrupt our internal operations.

               We are in the process of implementing a new company-wide computer system to replace the various systems that have been in place at our corporate offices, at the operations we owned in 2001, and at the operations we acquired in 2001 and in 2006. Once implementation is fully complete, we expect this system to help establish standard, uniform, best practices and reporting in a number of areas, increase productivity and efficiency, and enhance management of our business.  Certain aspects of our information technology infrastructure and operational activities have and may continue to experience difficulties in connection with this transition and implementation.  Such difficulties can cause delay, be time consuming and more resource intensive than planned, and cost more than we anticipated.   There can be no assurance that we will achieve the 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. See Note 8 to the Consolidated Financial Statements for more detail. We accrue amounts for these obligations, which are unfunded, and we pay as costs are incurred. If our assumptions change, the amount of our obligations could increase, and if our assumptions are inaccurate, we could be required to expend greater amounts than we anticipate. We regularly revise our estimates, and the amount of our accrued obligations is subject to change.

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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 September 30, 2006, our total gross indebtedness was approximately $303.5 million. 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 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 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.

               ROVA’s credit agreement restricts its ability to distribute cash, contains financial ratios and other covenants, and is secured by a pledge of the project and substantially all of the project’s assets. If ROVA fails to comply with these ratios and covenants or fails to make regular payments of principal and interest, an event of default could occur. A substantial portion of ROVA’s cash flow must be used to pay principal and interest on its indebtedness and is not available to us. If ROVA were to default on its debt service obligations, a creditor may be able to foreclose on assets that are important to our business.

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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 2005, we paid approximately $2.3 million in premiums for reclamation bonds. As we permit additional areas for our mines in 2006 and 2007, the bonding requirements are expected to increase significantly and the collateral posted is expected to increase as well. Any capital that we provide to collateralize our obligations to our bonding companies is not available to support our other business activities. If the cost of our reclamation bonds continues to increase, our profitability could be reduced.

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 with XL Specialty Insurance Company (“XL”) and an affiliate and one in an amount of approximately $5.0 million. In December 2003, XL indicated a desire to exit the business of bonding Coal Act obligations. In February 2004, XL renewed our Coal Act bond. Although we believe that XL must continue to renew the bond so long as we do not default on our obligations to the 1992 Plan, XL filed a Complaint for Declaratory Judgment on May 11, 2005 to force our payment of $21.3 million 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 2006 will be sold under long-term contracts to power plants that take delivery of our coal from common carrier railroads. Most of the Absaloka Mine’s sales are delivered by rail (with 6% by truck starting in 2006) and about 20% of the Rosebud Mine’s and Beulah Mine’s sales are delivered by rail. Contracts covering 60-70% 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.

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               Approximately two-thirds of the coal tonnage that we will sell in 2006 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, adopted regulations in March 2005, that could increase the costs of operating coal-fired power plants, including ROVA. Congress has considered legislation that would have this same effect. At this time, we are unable to predict the impact of these new regulations on our business. However, we expect that the new regulations may alter the relative competitiveness among coal suppliers and coal types. The new regulations could also disadvantage some or all of our mines, and notwithstanding our coal supply contracts we could lose all or a portion of our sales volumes and face increased pressure to reduce the price for our coal, thereby reducing our revenues, our profitability and the value of our coal reserves.

               In March 2005, the EPA issued the Clean Air Interstate Rule (“CAIR”) and Clean Air Mercury Rule (“CAMR”). The CAIR will reduce emissions of sulfur dioxide and nitrogen oxide in 28 eastern States and the District of Columbia. Texas and Minnesota, in which customers of the Jewett and Absaloka mines are located, and North Carolina, where ROVA is located, are subject to the CAIR. The CAIR requires these States to achieve required reductions in emissions from electric generating units, or EGUs, in one of two ways: (1) through participation in an EPA-administered, interstate “cap and trade” system that caps emissions in two stages, or (2) through measures of the State’s choice. Under the cap and trade system, the EPA will allocate emission “allowances” for nitrogen oxide to each State. The 28 States will distribute those allowances to EGUs, which can trade them. To control sulfur dioxide, the EPA will reduce the existing allowance allocations for sulfur dioxide that are currently provided under the acid rain program established pursuant to Title IV of the Clean Air Act Amendments.EGUs may choose among compliance alternatives, including installing pollution control equipment, switching fuels, or buying excess allowances from other EGUs that have reduced their emissions. Aggregate sulfur dioxide emissions are to be reduced from 2003 levels in two stages, a 45% reduction by 2010 and a 57% reduction by 2015. Aggregate nitrogen oxide emissions are also to be reduced from 2003 levels in two stages, a 53% reduction by 2009 and a 61% reduction by 2015.

               The CAMR applies to all States. The CAMR establishes a two-stage, nationwide cap on mercury emissions from coal-fired EGUs. Aggregate mercury emissions are to be reduced from 1999 levels in two stages, a 20% reduction by 2010 and a 70% reduction by 2018. The EPA expects that, in the first stage, emissions of mercury will be reduced in conjunction with the reductions of sulfur dioxide and nitrogen oxide under the CAIR. The EPA has assigned each State an emissions “budget” for mercury, and each state must submit a State Plan detailing how it will meet its budget for reducing mercury from coal-fired EGUs. Again, States may participate in an interstate “cap and trade” system or achieve reductions through measures of the States’ choice. The CAMR also establishes mercury emissions limits for new coal-fired EGUs (new EGUs are power plants for which construction, modification, or reconstruction commenced after January 30, 2004).

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               These new rules are likely to affect the market for coal for at least three reasons:

• 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, ROVA 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 NRGT pursuant to which the Limestone Station must purchase a specified volume of lignite from the Jewett Mine. In order to burn this lignite without violating the Texas nitrogen oxide regulations, the Limestone Station is blending our lignite with coal produced by others in the Southern Powder River Basin, and using emissions credits. Considerations involving the Texas nitrogen oxide regulations might affect the demand for lignite from the Jewett Mine in the period after 2007, which is the last year covered by the four- year fixed price agreement. Not- withstanding our contractual right to deliver approximately 6.5 million tons per year, NRGT might claim that it is less expensive for the Limestone Station to comply with the Texas nitrogen oxide regulations by switching to a blend that contains relatively more coal from the Southern Powder River Basin and relatively less of our lignite. Other states are evaluating various legislative and regulatory strategies for improving air quality and reducing emissions from electric generating units. Passage of other state-specific environmental laws could reduce the demand for our coal.

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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 $396.1 million (with a present value of $158.4. million) at December 31, 2005. Of these liabilities, our customers have assumed a gross aggregate of $200.9 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 $58.8 million, in each case at December 31, 2005. We estimate that our gross obligation for final reclamation that is not the contractual responsibility of others was $195.2 million at December 31, 2005. ROVA’s asset retirement obligation at the date of acquisition was $0.4 million.

Our profitability could be affected by unscheduled outages at the power plants we supply or own or if the scheduled maintenance outages at the power plants we supply or own last longer than anticipated.

               Scheduled and unscheduled outages at the power plants that we supply could reduce our coal sales and revenues, because any such plant would not use coal while it was undergoing maintenance. We cannot anticipate if or when unscheduled outages may occur.

               Our profitability could be affected by unscheduled outages at ROVA or if scheduled outages at ROVA last longer than we anticipate.

Increases in the cost of the fuel, electricity and materials and the availability of tires we use in the operation of our mines could affect our profitability.

               Under several of our existing coal supply agreements, our mines bear the cost of the diesel fuel, lubricants and other petroleum products, electricity, and other materials and supplies necessary to operate their draglines and other mobile equipment. In particular, the cost of tires for our heavy equipment at the mines increased drastically in 2005 as the supply tightened due to world-wide demand, which impacts productivity and could even reduce production if replacement tires are not available. The prices of many 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.

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If we experience unanticipated increases in the capital expenditures we expect to make over the next several years, our liquidity and/or profitability could suffer.

               Certain of our contracts provide for our customers to reimburse us for our capital expenditures on a depreciation and amortization basis, plus in some instances, a stated return-on-investment. Certain contracts provide reimbursement of capital expenditures in full as such expenditures are incurred. Other contracts feature set prices that adjust only for changes in a general inflation index. When we spend capital at our operations, it affects our near term liquidity in most instances and if capital is spent where the customer is not specifically obligated to reimburse us, that capital could be at risk if market conditions and contract duration do not match up to the investment.

Our ability to operate effectively and achieve our strategic goals could be impaired if we lose key personnel.

               Our future success is substantially dependent upon the continued service of our key senior management personnel, particularly Christopher K. Seglem, our Chairman of the Board, President and Chief Executive Officer. We do not have key-person life insurance policies on Mr. Seglem or any other employees. The loss of the services of any of our executive officers or other key employees could make it more difficult for us to pursue our business goals.

Provisions of our certificate of incorporation, bylaws and Delaware law, and our stockholder rights plan, may have anti-takeover effects that could prevent a change of control of our company that 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 bring about some types of corporate actions. In addition, a change of control of our Company may be delayed or deterred as a result of our stockholder rights plan, which was initially adopted by our Board of Directors in early 1993 and amended and restated in February 2003. Our ability to issue preferred stock in the future may influence the willingness of an investor to seek to acquire our company. These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control of Westmoreland.

Our ability to operate effectively and achieve our strategic goals depends on maintaining satisfactory labor relations.

               A significant portion of the workforce at each of the Company-operated mines, except Jewett, is represented by labor unions. While we believe that our relationships with our employees at the mines are satisfactory, the nature of collective bargaining is such that there is a risk of a disruption in operations when any collective bargaining agreement reaches its expiration dates unless a renewal or extension has been accepted by the employees who are covered by the agreement. While labor strikes are generally a force majeure event in long-term coal supply agreements, thereby exempting the mine from its delivery obligations, the loss of revenue for even a short period of time could have a material adverse effect on the Company’s financial results.

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We have had material weaknesses in internal control over financial reporting in the past and cannot assure that additional material weaknesses will not be identified in the future. Our failure to maintain effective internal control over financial reporting could result in material misstatements in our financial statements which could require us to restate financial statements, cause investors to lose confidence in our reported financial information and have a negative effect on our stock price.

               During the past year, the Company identified five material weaknesses in internal controls over financial reporting as defined in the Public Company Accounting Oversight Board’s Auditing Standard No. 2. The material weaknesses in our internal control over financial reporting are described in Amendment No. 1 to our 2005 Form 10-K under “Item 9A – Controls and Procedures”.

               We cannot assure that additional significant deficiencies or material weaknesses in our internal control over financial reporting will not be identified in the future. Any failure to maintain or implement new or improved controls, or any difficulties we encounter in their implementation, could result in additional significant deficiencies or material weaknesses, and cause us to fail to meet our periodic reporting obligations or result in material misstatements in our financial statements. Any such failure could also adversely affect the results of periodic management evaluations and annual auditor attestation reports regarding the effectiveness of our internal control over financial reporting required under Section 404 of the Sarbanes-Oxley Act of 2002 and the rules promulgated under Section 404. The existence of a material weakness could result in errors in our financial statements that could result in a restatement of financial statements, cause us to fail to meet our reporting obligations and cause investors to lose confidence in our reported financial information, leading to a decline in our stock price.

We may face risks related to an SEC investigation and securities litigation in connection with the restatement of our financial statements.

               We are not aware that the Securities and Exchange Commission (“SEC”) has begun any formal or informal investigation in connection with accounting errors requiring restatement of 2005 and prior years’ financial statements including 2004 and 2005 quarterly financial statements, or that any laws have been violated. However, if the SEC makes a determination that the Company has violated Federal securities laws, the Company may face sanctions, including, but not limited to, monetary penalties and injunctive relief, which could adversely affect our business. In addition, the Company or its officers and directors could be named defendants in civil proceedings arising from the restatement. We are unable to estimate what our liability in either event might be.

54ITEM 3
DEFAULTS UPON SENIOR SECURITIES

               See Note 9 "Capital Stock" to our Consolidated Financial Statements, which is incorporated by reference herein.

ITEM 5
OTHER INFORMATION

               The Company has accumulated but unpaid quarterly preferred dividends through and including October 1, 2006 amount to $14.3 million in the aggregate ($89.44 per preferred share or $22.36 per Depositary Share). The Company is prohibited from paying preferred stock dividends because there are statutory restrictions limiting the payment of preferred stock dividends under Delaware law, the state in which the Company is incorporated. Under Delaware law, the Company is permitted to pay preferred stock dividends only to the extent that shareholders’ equity exceeds the par value of the preferred stock (which par value was $160,000 at September 30, 2006).

ITEM 6
EXHIBITS

a) Exhibits

(31) Rule 13a-14(a)/15d-14(a) Certifications.

(32) Certifications pursuant to 18 U.S.C. Section 1350.

55SIGNATURES

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:    November 14, 2006	/s/ David J. Blair
	David J. Blair
	Chief Financial Officer
	(A Duly Authorized Officer)
Date:    November 14, 2006	/s/ Kevin A. Paprzycki
	Kevin A. Paprzycki
	Controller and
	Principal Accounting Officer
	(A Duly Authorized Officer)

56Exhibit Index

Exhibit
Number Description

(31) Rule 13a-14(a)/15d-14(a) Certifications.

(32) Certifications pursuant to 18 U.S.C. Section 1350.

57