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, 2005

( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to ___________

Commission File Number
001-11155

WESTMORELAND COAL COMPANY
(Exact name of registrant as specified in its charter)


DELAWARE		23-1128670
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)


2 North Cascade Avenue 14th Floor Colorado Springs, Colorado		80903
(Address of principal executive offices)		(Zip Code)


Registrant's telephone number, including area code		719-442-2600

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___

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

Indicate 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, 2005: Common stock, $2.50 par value: 8,327,994

PART I — FINANCIAL INFORMATION

ITEM 1
FINANCIAL STATEMENTS

Westmoreland Coal Company and Subsidiaries
Consolidated Balance Sheets

		(Unaudited)
		September 30,		December 31,
		2005		2004

		(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	8,308	$	11,125
Receivables:
Trade		29,469		24,891
Other		5,500		4,399

		34,969		29,290
Inventories		17,028		14,952
Deferred overburden removal costs		13,430		12,034
Restricted cash		10,025		9,761
Deferred income taxes		12,747		13,501
Other current assets		7,250		6,239

Total current assets		103,757		96,902


Property, plant and equipment:
Land and mineral rights		21,991		22,234
Capitalized asset retirement cost		118,474		118,474
Plant and equipment		124,667		110,196

		265,132		250,904
Less accumulated depreciation, depletion and amortization		95,429		82,276

Net property, plant and equipment		169,703		168,628

Deferred income taxes		79,781		71,195
Investment in independent power projects		48,586		48,565
Excess of trust assets over pneumoconiosis benefit obligation		3,429		4,463
Restricted cash and bond collateral		23,985		22,921
Advanced coal royalties		3,845		3,521
Deferred overburden removal costs		2,404		3,910
Reclamation deposits		57,682		55,561
Contractual third party reclamation obligations		26,459		24,998
Other assets		12,518		13,325

Total Assets	$	532,149	$	513,989

See accompanying Notes to Consolidated Financial Statements.

(Continued)

Westmoreland Coal Company and Subsidiaries
Consolidated Balance Sheets (Continued)

		(Unaudited)
		September 30,		December 31,
		2005		2004

		(in thousands)
Liabilities and Shareholders' Equity
Current liabilities:
Current installments of long-term debt	$	12,183	$	11,819
Accounts payable and accrued expenses:
Trade		31,541		24,769
Deferred revenue		450		-
Income taxes		1,749		71
Production taxes		21,572		18,316
Workers' compensation		1,066		1,288
FAS 106 postretirement medical costs		16,931		16,437
Asset retirement obligations		10,306		5,284

Total current liabilities		95,798	��	77,984


Long-term debt, less current installments		103,974		105,440
Workers' compensation, less current portion		8,930		9,646
Postretirement medical costs, less current portion		122,256		117,792
Deferred revenue, less current portion		1,217		-
Pension and SERP costs, less current portion		12,011		10,637
Asset retirement obligations, less current portion		135,632		135,509
Other liabilities		7,283		12,819
Minority interest		4,344		4,270

Commitments and contingent liabilities

Shareholders' equity:
Preferred stock of $1.00 par value
Authorized 5,000,000 shares;
Issued and outstanding 205,083 shares at September 30, 2005
and at December 31, 2004		205		205
Common stock of $2.50 par value
Authorized 20,000,000 shares;
Issued and outstanding 8,321,943 shares at September 30, 2005 and
8,168,601 shares at December 31, 2004		20,805		20,421
Other paid-in capital		77,407		75,366
Accumulated other comprehensive loss		(4,862	)	(5,117	)
Accumulated deficit		(52,851	)	(50,983	)

Total shareholders' equity		40,704		39,892

Total Liabilities and Shareholders' Equity	$	532,149	$	513,989

See accompanying Notes to Consolidated Financial Statements.

Westmoreland Coal Company and Subsidiaries Consolidated Statements of Operations

	(Unaudited)
	Three Months Ended					Nine Months Ended
		September 30,				September 30,
		2005		2004		2005		2004

	(in thousands except per share data)
Revenues:
Coal	$	94,377	$	78,826	$	266,177	$	242,978
Independent power projects — equity in earnings		1,682		5,270		10,310		12,356

		96,059		84,096		276,487		255,334

Costs and expenses:
Cost of sales — coal		78,498		63,624		217,606		189,942
Depreciation, depletion and amortization		4,794		4,018		14,270		11,439
Selling and administrative		9,195		7,743		24,060		22,420
Heritage health benefit costs		6,909		7,247		22,279		22,156
Loss (gain) on sales of assets		(28)		(74)		151		(55)

		99,368		82,558		278,366		245,902

Operating income (loss)		(3,309)		1,538		(1,879)		9,432

Other income (expense):
Interest expense		(2,580)		(2,483)		(7,747)		(7,521)
Interest income		851		674		2,483		2,995
Minority interest		(295)		(288)		(854)		(891)
Other		585		104		1,225		187

		(1,439)		(1,993)		(4,893)		(5,230)

Income (loss) before income taxes		(4,748)		(455)		(6,772)		4,202
Income tax benefit		1,761		1,678		5,519		4,382

Net income (loss)		(2,987)		1,223		(1,253)		8,584
Less preferred stock dividend requirements		(436)		(436)		(1,308)		(1,308)

Net income (loss) applicable to common shareholders	$	(3,423)	$	787	$	(2,561)	$	7,276

Net income (loss) per share applicable to common shareholders :
Basic	$	(.41)	$	.10	$	(.31)	$	.90
Diluted	$	(.41)	$	.09	$	(.31)	$	.84

Weighted average number of common shares outstanding:
Basic		8,302		8,141		8,255		8,078
Diluted		8,302		8,710		8,255		8,611

See accompanying Notes to Consolidated Financial Statements.

Westmoreland Coal Company and Subsidiaries Consolidated Statement of Shareholders' Equity and Comprehensive Income Nine Months Ended September 30, 2005 (Unaudited)

	Class A Convertible Exchangeable Preferred Stock		Common Stock		Other Paid-In Capital		Accumulated Other Comprehensive Loss		Accumulated Deficit		Total Shareholders' Equity

		(in thousands except share data)
Balance at December 31, 2004 (205,083 preferred shares and 8,168,601 common shares outstanding)		$ 205		$20,421		$75,366		$(5,117)		$(50,983)		$ 39,892
Common stock issued as compensation (55,244 shares)		-		139		1,130		-		-		1,269
Common stock options exercised (98,098 shares)		-		245		655		-		-		900
Dividends declared		-		-		-		-		(615)		(615)
Tax benefit of stock option exercises		-		-		256		-		-		256
Net income (loss)		-		-		-		-		(1,253)		(1,253)
Net unrealized change in interest rate swap
agreement, net of tax expense of $170		-		-		-		255		-		255

Comprehensive income												998

Balance at September 30, 2005 (205,083 preferred shares and 8,321,943 common shares outstanding)		$ 205		$20,805		$77,407		$(4,862)		$(52,851)		$ 40,704

See accompanying Notes to Consolidated Financial Statements.

Westmoreland Coal Company and Subsidiaries Consolidated Statements of Cash Flows

		(Unaudited)
Nine Months Ended September 30,	2005		2004
		(in thousands)
Cash flows from operating activities:
Net income (loss)	$	(1,253)	$	8,584
Adjustments to reconcile net income to net cash provided by operating
activities:
Equity in earnings from independent power projects		(10,310)		(12,356)
Cash distributions from independent power projects		10,542		3,133
Deferred income tax benefit		(7,576)		(5,229)
Depreciation, depletion and amortization		14,270		11,439
Stock compensation expense		1,269		1,226
Loss (gain) on sales of assets		151		(55)
Minority interest		854		891
Net change in operating assets and liabilities		9,095		3,043

Net cash provided by operating activities		17,042		10,676

Cash flows from investing activities:
Additions to property, plant and equipment		(15,454)		(11,703)
Change in restricted cash and bond collateral and reclamation deposits		(3,449)		(9,074)
Net proceeds from sales of assets		641		262

Net cash used in investing activities		(18,262)		(20,515)

Cash flows from financing activities:
Proceeds from long-term debt, net of debt issuance costs		-		19,616
Repayment of long-term debt		(7,602)		(8,821)
Net borrowings of revolving lines of credit		6,500		1,500
Exercise of stock options		900		862
Dividends paid to minority interest		(780)		(660)
Dividends on preferred shares		(615)		(533)

Net cash provided by (used in) financing activities		(1,597)		11,964

Net increase (decrease) in cash and cash equivalents		(2,817)		2,125
Cash and cash equivalents, beginning of period		11,125		9,267

Cash and cash equivalents, end of period	$	8,308	$	11,392

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest	$	7,902	$	7,235
Income taxes	$	378	$	528

See accompanying Notes to Consolidated Financial Statements.

WESTMORELAND COAL COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These quarterly consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004. The accounting principles followed by the Company are set forth in the Notes to the Company’s consolidated financial statements in that Annual Report. These accounting principles and other footnote disclosures previously made have been omitted in this report so long as the interim information presented is not misleading.

The consolidated financial statements of the Company have been prepared in accordance with generally accepted accounting principles and require use of management’s estimates. The financial information contained in this Form 10-Q is unaudited but reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the financial information for the periods shown. Such adjustments are of a normal recurring nature. The results of operations for such interim periods are not necessarily indicative of results to be expected for the full year.

NATURE OF OPERATIONS

The Company’s current principal activities, all conducted within the United States, are: (i) the production and sale of coal from Montana, North Dakota and Texas; and (ii) the development, ownership and management of interests in cogeneration and other non-regulated independent power plants.

LINES OF CREDIT AND LONG-TERM DEBT

The amounts outstanding at September 30, 2005 and December 31, 2004 under the Company’s lines of credit and long-term debt were:

	September 30, 2005		December 31, 2004


		(in thousands)

WML revolving line of credit with PNC Bank		$ 1,000		$ -
WML term debt:
Series B Notes		70,475		78,200
Series C and D Notes		35,000		35,000
Corporate revolving line of credit		5,500		-
Other term debt		4,182		4,059

Total debt outstanding		116,157		117,259
Less current portion		(12,183)		(11,819)

Total long-term debt outstanding		$ 103,974		$ 105,440

The Company has a $14.0 million revolving credit agreement with First Interstate Bank. Interest is payable monthly. Effective July 19, 2005, the interest rate on this line of credit was reduced 1%, to the bank’s prime rate, and the expiration date of this agreement was extended to June 30, 2007. The revolving credit agreement requires the Company to maintain certain financial ratios. The revolving credit agreement is collateralized by the Company’s stock in Westmoreland Resources, Inc. (“WRI”), the stock of Horizon Coal Services, Inc. (“Horizon”), and the dragline located at WRI’s Absaloka Mine in Big Horn County, Montana.

Westmoreland Mining LLC (“WML”) has a $12 million revolving facility (the “Facility”) with PNC Bank National, Association (“PNC”) which expires on April 27, 2007. The interest rate is either PNC’s Base Rate plus 1.50% or Euro-Rate plus 3.00%, at WML’s option. In addition, a commitment fee of ½ of 1% of the average unused portion of the available credit is payable quarterly. The amount available under the Facility is based upon, and any outstanding amounts are secured by, eligible accounts receivable.

WML has a term loan agreement as described in the Company’s 2004 Annual Report on Form 10-K with $70.5 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, 2005. The Series B Notes bear interest at a fixed interest rate of 9.39%, Series C Notes at a fixed rate of 6.85%, and the Series D Notes have a variable rate based upon LIBOR plus 2.90%. The Company incurred the indebtedness represented by the Series B Notes in connection with its acquisition of the Rosebud, Jewett, Beulah and Savage Mines in 2001, and we occasionally refer to this indebtedness as our acquisition debt. The Series C and D Notes were added in 2004 and we refer to them as WML’s “add-on” debt. All of the Notes are secured by assets of WML, and the term loan agreement subjects the Company to certain covenants and financial ratio requirements.

Pursuant to the WML term loan agreement, WML is required to maintain debt service reserve and long-term prepayment accounts. As of September 30, 2005, there was a total of $10.0 million in the debt service reserve account, which could be used for principal and interest payments, and $12.1 million in the long-term prepayment account, which account will be used to fund a $30.0 million payment due December 31, 2008 for the Series B Notes. Those funds have been classified as restricted cash on the consolidated balance sheet.

The maturities of all long-term debt and the revolving credit facilities outstanding at September 30, 2005 are:


		In thousands

2005		$ 3,017
2006		12,462
2007		19,592
2008		45,447
2009		12,272
Thereafter		23,367

		$ 116,157

PENSION AND POSTRETIREMENT MEDICAL BENEFITS

The Company provides pension and postretirement medical and life insurance benefits to qualifying full-time employees and retired employees and their dependents. A very large majority of these benefits are mandated by the Federal Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”) and provided to former miners at the Company’s previously owned operations and their dependents. The Company incurred costs of providing these benefits during the nine-month periods ended September 30, 2005 and 2004 as follows:

	Pension Benefits		Postretirement Medical and Life Insurance Benefits
	2005	2004	2005	2004

	(in thousands)
Service cost	$ 2,016	$ 1,848	$ 387	$ 397
Interest cost	2,706	2,478	10,916	11,642
Expected return on plan assets	(2,550)	(2,079)	-	-
Amortization of deferred items	743	675	6,858	6,563

Net periodic cost	$ 2,915	$ 2,922	$18,161	$18,602

The Company will contribute approximately $1.6 million to its pension plans during 2005. Of that amount, $1.5 million was contributed in the nine months ended September 30, 2005.

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 January 1, 2005, April 1, 2005, July 1, 2005, and October 1, 2005. A dividend of $0.25 per depositary share was declared on November 4, 2005, payable January 1, 2006. The quarterly dividends which are accumulated but unpaid through and including October 1, 2005 amount to $17.0 million in the aggregate ($82.90 per preferred share or $20.73 per depositary share). Common stock dividends may not be declared until the preferred stock dividends that are accumulated but unpaid are made current.

Incentive Stock Options

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

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2005		2004		2005		2004

		(in thousands, except per share data)
Net income (loss) applicable to common
shareholders, as reported	$	(3,423)	$	787	$	(2,561)	$	7,276
Less: Total stock-based employee compensation
expense determined under fair value based
method for all awards, net of related tax
effects		62		153		231		576

Net income (loss) applicable to common shareholders, pro forma	$	(3,485)	$	634	$	(2,792)	$	6,700

Net income (loss) per share applicable to
common shareholders:
Basic - as reported	$	(.41)	$	.10	$	(.31)	$	.90
Basic - pro forma	$	(.42)	$	.08	$	(.34)	$	.83

Diluted - as reported	$	(.41)	$	.09	$	(.31)	$	.84
Diluted - pro forma	$	(.42)	$	.07	$	(.34)	$	.78

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,
	2005	2004	2005	2004

	(in thousands)
Number of shares of common stock:
Basic	8,302	8,141	8,255	8,078
Effect of dilutive option shares	-	569	-	533

Diluted	8,302	8,710	8,255	8,611

Number of shares not included in diluted EPS that
would have been antidilutive because exercise price
of options was greater than the average market
price of the common shares	-	-	-	-

Number of shares not included in diluted EPS
that would have been dilutive had the Company
reported net income	585	-	614	-

INCOME TAXES

Income tax (expense) benefit attributable to income before income taxes consists of:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2005		2004		2005		2004

		(in thousands)
Current:
Federal	$	168	$	(110)	$	-	$	(444)
State		(1,578)		(82)		(2,057)		(403)

		(1,410)		(192)		(2,057)		(847)


Deferred:
Federal		2,695		1,725		6,665		4,895
State		476		145		911		334

		3,171		1,870		7,576		5,229

Income tax benefit	$	1,761	$	1,678	$	5,519	$	4,382

The deferred income tax benefit recorded for the nine months ended September 30, 2005 included a benefit of $1.5 million, due to reduction in the deferred income tax asset valuation allowance as a result of changes in the amount of Federal net operating loss carryforwards expected to be used by the Company prior to their expiration through 2024. For the three months ended September 30, 2005 there was no change in the Federal deferred income tax asset valuation allowance. The deferred income tax benefit recorded for the three months and nine months ended September 30, 2004 included a benefit of $0.9 million and $3.0 million, respectively, due to a reduction in the deferred income tax asset valuation allowance. The income tax benefit also includes a benefit from tax depletion in excess of book depletion. For the nine months ended September 30, 2005 this tax benefit was approximately $2.1 million.

BUSINESS SEGMENT INFORMATION

The Company’s operations have been classified into two segments: coal and independent power. The coal segment includes the production and sale of coal from Montana, North Dakota and Texas. The independent power operations include the ownership of interests in cogeneration and other non-regulated independent power plants. The “Corporate” classification noted in the tables represents all costs not otherwise classified, including corporate office charges, heritage health benefit costs and business development expenses. Summarized financial information by segment for the quarters ended September 30, 2005 and 2004 is as follows:

Quarter ended September 30, 2005

		Coal		Independent Power		Corporate		Total

		(in thousands)
Revenues:
Coal	$	94,377	$	-	$	-	$	94,377

Equity in earnings		-		1,682		-		1,682

		94,377		1,682		-		96,059

Costs and expenses:
Cost of sales – coal		78,498		-		-		78,498

Depreciation, depletion and amortization		4,693		6		95		4,794
Selling and administrative		5,738		435		3,022		9,195

Heritage health benefit costs		-		-		6,909		6,909
Gain on sales of assets		-		-		(28)		(28)

Operating income (loss)	$	5,448	$	1,241	$	(9,998)	$	(3,309)


Capital expenditures	$	3,831	$	26	$	(718)	$	3,139


Property, plant and equipment, net	$	168,647	$	103	$	953	$	169,703

Quarter ended September 30, 2004

		Coal		Independent Power		Corporate		Total

		(in thousands)

Revenues:
Coal	$	78,826	$	-	$	-	$	78,826

Equity in earnings		-		5,270		-		5,270

		78,826		5,270		-		84,096

Costs and expenses:
Cost of sales – coal		63,624		-		-		63,624

Depreciation, depletion and amortization		3,980		4		34		4,018
Selling and administrative		4,868		184		2,691		7,743

Heritage health benefit costs		-		-		7,247		7,247
Gain on sales of assets		(74)		-		-		(74)

Operating income (loss)	$	6,428	$	5,082	$	(9,972)	$	1,538


Capital expenditures	$	5,831	$	19	$	128	$	5,978


Property, plant and equipment, net	$	151,005	$	68	$	772	$	151,845

Nine months ended September 30, 2005

		Coal		Independent Power		Corporate		Total

		(in thousands)

Revenues:
Coal	$	266,177	$	-	$	-	$	266,177

Equity in earnings		-		10,310		-		10,310

		266,177		10,310		-		276,487

Costs and expenses:
Cost of sales – coal		217,606		-		-		217,606

Depreciation, depletion and amortization		14,073		16		181		14,270
Selling and administrative		17,423		1,471		5,166		24,060

Heritage health benefit costs		-		-		22,279		22,279
Loss (gain) on sales of assets		261		-		(110)		151

Operating income (loss)	$	16,814	$	8,823	$	(27,516)	$	(1,879)


Capital expenditures	$	15,003	$	44	$	407	$	15,454


Property, plant and equipment, net	$	168,647	$	103	$	953	$	169,703

Nine months ended September 30, 2004

		Coal		Independent Power		Corporate		Total

		(in thousands)

Revenues:
Coal	$	242,978	$	-	$	-	$	242,978

Equity in earnings		-		12,356		-		12,356

		242,978		12,356		-		255,334

Costs and expenses:
Cost of sales – coal		189,942		-		-		189,942

Depreciation, depletion and amortization		11,312		14		113		11,439
Selling and administrative		14,869		798		6,753		22,420

Heritage health benefit costs		-		-		22,156		22,156
Gain on sales of assets		(55)		-		-		(55)

Operating income (loss)	$	26,910	$	11,544	$	(29,022)	$	9,432


Capital expenditures	$	11,255	$	35	$	413	$	11,703


Property, plant and equipment, net	$	151,005	$	68	$	772	$	151,845

CONTINGENCIES

Protection of the Environment

As of September 30, 2005 the Company has reclamation bonds in place for its active mines in Montana, North Dakota and Texas. The Company also has reclamation bonds in place for inactive mining sites in Virginia and Colorado, which are now awaiting final bond release. These government-required bonds assure that coal mining operations comply with applicable Federal and State regulations relating to the performance and completion of final reclamation activities. The Company currently estimates that the cost of final reclamation for its mines when they are closed at some point in the future will total approximately $314.1 million (on an undiscounted basis), or $145.9 million expressed on a present value basis. The Company’s customers and the contract operator of the Absaloka Mine are responsible for $189.5 million of these reclamation costs (on an undiscounted basis) and have secured a portion of these obligations by providing a $50 million corporate guarantee to assure performance of such final reclamation and by funding reclamation escrow accounts in the amount of approximately $57.7 million as of September 30, 2005. The reclamation escrow accounts are restricted funds and have been classified as Reclamation Deposits on the Consolidated Balance Sheets. In addition, the Absaloka contract mine operator is funding a separate reclamation escrow account that is approximately $4.4 million as of September 30, 2005. The present value of obligations of certain other customers and the Absaloka contract mine operator has been classified as contractual third party reclamation obligations on the Consolidated Balance Sheets. The Company’s estimated obligation for final reclamation that is not the contractual responsibility of others is $124.6 million (on an undiscounted basis) at September 30, 2005.

Changes in the Company’s asset retirement obligations from January 1, 2005 to September 30, 2005 (in thousands) were:

Asset retirement obligation — beginning of year		$ 140,793
Accretion		7,233
Settlements (final reclamation performed)		(2,591)
Loss on settlements		503

Asset retirement obligation — September 30, 2005		$ 145,938

Royalty Claims and Taxes (Rosebud Mine)

Western Energy Company, a subsidiary of the Company that was acquired from Montana Power Company in 2001, produces coal from four federal leases and a state lease near Colstrip, Montana. This leased property, part of the Company’s Rosebud Mine, supplies coal to four units of the adjacent Colstrip Power Plant. In the late 1970‘s, the owners of the Colstrip Power Plant, including Montana Power, entered into negotiations with Western Energy 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, Western Energy and the Colstrip owners entered into a Coal Supply Agreement and a separate Coal Transportation Agreement. Under the Coal Supply Agreement, the Colstrip Owners pay a per-ton price for the delivered coal. Under the Coal Transportation Agreement, the Colstrip Owners pay a separate fee for the transportation of the coal from the mine to the Colstrip Plant on a conveyor belt that was designed and constructed by Western Energy and has been continuously operated and maintained by Western Energy.

In 2002, the State of Montana, as agent for the Minerals Management Service (“MMS”) of the U.S. Department of the Interior, conducted an audit of the royalty payments made by Western Energy on the production of coal from the federal leases. The audit covered two periods: October 1991 through December 1995, and January 1996 through 2001. Based on these audits, the Office of Minerals Revenue Management (“MRM”) of the Department of the Interior issued orders directing Western Energy to pay royalties in the amount of approximately $7.0 million on the proceeds received from the Colstrip owners under the Coal Transportation Agreement during the two audit periods. Both orders claimed that the payments for transportation were deemed to be payments for the production of coal. Only payments for coal production are subject to the federal royalty, not payments for transportation.

Western Energy appealed the orders of the MRM to the Directors of the MMS. On March 28, 2005, the MMS issued a decision stating that payments to Western Energy 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, Western Energy appealed the decision of the MMS on the transportation charges to the Department of Interior’s Office of Hearings and Appeals, Interior Board of Land Appeals (“IBLA”). On September 6, 2005, the MMS filed its answer to Western Energy’s appeal. Western Energy believes that it has a strong case and expects a favorable ruling from the IBLA. The appeal before the IBLA could take as much as two years. If the ruling is not favorable to Western Energy, the Company intends to seek relief in federal court.

The total amount of the MMS royalty claims through the end of 2003, adjusted for the partial favorable ruling on March 28, 2005 from the MMS directors discussed above, was approximately $5.0 million, including interest through the end of 2003. This amount, if payable, is subject to interest through the date of payment at the rate of 1% per year.

In 2003, the State of Montana Department of Revenue (“DOR”) assessed state taxes for years 1997 and 1998 on the transportation charges collected by Western Energy from the Colstrip 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. Western Energy has disputed the state tax claims. It is anticipated that the state tax claims will be resolved following the outcome of Western Energy’s appeal of the MMS royalty claims or subsequent proceedings in federal court. The total of the state tax claims through the end of 2003 was approximately $3.6 million. If this amount is payable it is subject to interest at an annual rate of 12%.

The MMS has asserted two other royalty claims against Western Energy. In 2002, the MMS held that “take or pay” payments received by Western Energy during the period from October 1, 1991 to December 31, 1995 from two Colstrip owners were subject to the federal royalty. A “take or pay” provision is a term in coal supply agreements pursuant to which the purchaser must pay a specified amount in the event that it chooses not to take delivery of coal that it agreed to purchase. The MMS is claiming that these “take or pay” payments are payments for the production of coal, notwithstanding that no coal was produced. Western Energy 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 Western Energy and one of the Colstrip owners. This settlement agreement reduced the coal price payable by the owner 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 owners. The MMS has claimed that the coal price reduction is subject to the federal royalty. Western Energy has appealed this demand of 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.

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 approximately $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 one of the Colstrip owners.

Neither the MMS nor the DOR has made royalty or tax demands for all periods during which Western Energy 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 Western Energy, including the pending claims and interest thereon through the present, could exceed $40 million.

The Company believes that Western Energy has meritorious defenses against the royalty and tax demands made by the MMS and the DOR. Moreover, in the event of a final adverse outcome with DOR and MMS, certain of the Company’s customers are contractually obligated to reimburse the Company for any royalties and taxes imposed on the Company for the production of coal sold to the Colstrip owners, plus legal expenses. The Company has not accrued any amount for the royalty and tax claims.

Tax Assessments

Halifax County

The ROVA project is located in Halifax County, North Carolina and is the County’s largest taxpayer. In 2002, the County hired an independent consultant to review and audit the property tax returns for the previous five years. In May 2002, the County advised the ROVA project that its returns were being scrutinized for potential underpayment due to undervaluation of property subject to tax. ROVA responded to the County that its valuation was consistent with a preconstruction agreement reached with the County in 1996. In late 2002, the ROVA project received notice of an assessment of $3.2 million for the years 1997 to 2001. Since that date the County has increased the amount of its claim to $5.4 million, which adds tax years 1996, 2002, 2003 and 2004. With penalty and interest, the total amount claimed due by the County is $8.6 million, which amount has been withheld from distributions by the project lender. The ROVA project filed a protest of the assessment for 1996 to 2001 with the Property Tax Commission. On May 26, 2004, the Tax Commission denied the ROVA project’s protest and issued an order sustaining the County’s assessment. The ROVA project appealed the Tax Commission’s decision to the North Carolina Intermediate Court of Appeals on June 24, 2004. On April 20, 2005, the case was heard. A decision from the Court is expected within the next few weeks. The ROVA project also filed a protest of the assessment for 2002 to 2004 with the County Board of Equalization and Review, including a claim for a refund on its 2005 real estate taxes. The Board of Equalization and Review denied the ROVA project’s protest. On July 20, 2005, the ROVA project appealed that decision to the North Carolina Tax Commission.

The term “LG&E” refers to LG&E Energy LLC and its subsidiaries. LG&E has agreed that, if we complete the ROVA acquisition, LG&E will indemnify the ROVA Project for one-half of the taxes, penalties, and interest assessed by Halifax County for the period through December 31, 2003 and for one-half of our reasonable attorneys’ fees and expenses incurred in settling or otherwise resolving Halifax County’s claims for this period. The ROVA project accrued a liability of $4 million for the claims in 2004 and the Company recorded its 50% share of $2 million. The Company has accrued an additional $900,000 during third quarter 2005 for its share of the tax liability in excess of $4 million.

Rensselaer

Niagara Mohawk Power Corporation (“NIMO”) was party to power purchase agreements with independent power producers, including the Rensselaer project, in which we owned an interest. In 1997, the New York Public Service Commission approved NIMO’s plan to terminate or restructure 29 power purchase contracts. The Rensselaer project agreed to terminate its Power Purchase and Supply Agreement after NIMO threatened to seize the project under its power of eminent domain. NIMO and the Rensselaer project executed a settlement agreement in 1998 with a payment to the project. On February 11, 2003, the North Carolina Department of Revenue notified us that it had disallowed the exclusion of gain as non-business income from the settlement agreement between NIMO and the Rensselaer project. The State of North Carolina has assessed a current tax of $3.5 million, interest of $1.3 million (through 2004), and a penalty of $0.9 million. We have filed a protest. The North Carolina Department of Revenue held a hearing on May 28, 2003. In November 2003, we submitted further documentation to the State to support our position. On January 14, 2005, the North Carolina Department of Revenue concluded that the additional assessment is statutorily correct. On July 27, 2005, the Company responded to the North Carolina Department of Revenue providing additional information. On September 7, 2005, the Department of Revenue responded and our analysis continues regarding possible settlement. 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. During third quarter 2005, the Company accrued a reserve of $2.1 million for what we currently estimate its liability for this tax claim could be.

McGreevey Litigation

In late 2002, the Company was served with a complaint in a case styled McGreevey et al. v. Montana Power Company et al. in a Montana State court. The plaintiffs are former stockholders of Montana Power who filed their first complaint on August 16, 2001. This was the Plaintiffs’ Fourth Amended Complaint which added Westmoreland as a defendant to a suit against Montana Power Company, various officers of Montana Power Company, the Board of Directors of Montana Power Company, financial advisors and lawyers representing Montana Power Company and the purchasers of some of the businesses formerly owned by Montana Power Company and Entech, Inc., a subsidiary of Montana Power Company. The plaintiffs seek to rescind the sale by Montana Power of its generating, oil and gas, and transmission businesses, and the sale by Entech of its coal business or to compel the purchasers to hold these businesses in trust for the shareholders. The Plaintiffs contend that they were entitled to vote to approve the sale by Entech to the Company even though they were not shareholders of Entech. Westmoreland has filed an answer, various affirmative defenses and a counterclaim against the plaintiffs.

The litigation was transferred to the U.S. District Court in Billings, Montana. On July 12, 2004, the plaintiffs filed a status report with the U.S. District Court. In the status report, the plaintiffs stated that the insurance companies that insure the former officers and directors of Montana Power had agreed to pay $67 million into escrow, pending approval of a settlement agreement and a determination by the bankruptcy court that no other claimant or class of claimants is entitled to any portion of the settlement proceeds. As part of the proposed settlement, the McGreevey plaintiffs would dismiss their claims against us and our subsidiaries, among others. The parties continue to negotiate the terms of the proposed settlement. Regardless of the outcome the Company has a claim for indemnification against Entech if it incurs any losses as a result of the McGreevey litigation. The Company has not accrued any amount for the claims.

Combined Benefit Fund

In 1992, Congress enacted the Coal Act. Among other things, the Coal Act merged the UMWA 1950 and 1974 Benefit Plans into a new plan called the Combined Benefit Fund (“CBF”). Beneficiaries of the CBF were assigned to coal companies across the country, and each coal company was required to pay a monthly per-person premium to the CBF.

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,i.e., 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.

This issue has been in litigation for over ten years 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 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 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 by more than $6 million for the period from 1993 through 2005. Prospectively, the difference is approximately $528,000 per year.

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. We expect it to be denied. The Commissioner of Social Security and the Trustees are expected to appeal the decision of the Maryland District Court to the United States Court of Appeals for the Fourth Circuit. We believe that the decision of the District Court will not be overturned on appeal.

The premium is recalculated each October. Through September 2003, we paid a monthly premium of approximately $400,000. From October 2003 through September 2004 the Company paid $859,000 per month including the retroactive amount. Commencing October 2004, the Company resumed paying approximately $396,000 per month to the CBF. The Trustees have not yet invoiced premiums for the upcoming fiscal year. The Company commenced withholding monthly payments in September 2005 but continues to expense the estimated monthly premiums.

1992 UMWA Benefit Plan Surety Bond

On May 11, 2005, XL Specialty Insurance Company and XL Reinsurance America, Inc. (referred to together as “XL”) filed in the U.S. District Court, Southern District of New York, a Complaint for Declaratory Judgment against Westmoreland Coal Company and named Westmoreland Mining LLC as a co-defendant. The Complaint asks the Court to declare that (1) the plaintiffs have the right to cancel a $21.3 million bond that secures Westmoreland’s obligation to provide benefits to the UMWA 1992 Plan, (2) Westmoreland must immediately pay $21.3 million to XL and (3) after cancellation of the bond, Westmoreland must indemnify XL for all claims, demands, losses and expenses in conjunction with termination of the bond.

It is our position that XL has no right to cancel the bond and, if it chooses to unilaterally cancel the bond, the UMWA Plan Trustees can draw the full amount of bond, which is approximately $21.3 million. We further believe that in the event of such a draw, the Company is under no obligation to reimburse XL for the amount drawn unless the Company has defaulted on its payment obligations relating to the UMWA 1992 Plan. No such default has occurred, nor do we anticipate defaulting on any of our obligations under the UMWA 1992 Plan. Therefore, we will contest vigorously the request by XL for a Declaratory Judgment. In addition, we do not believe that Westmoreland Mining LLC should have been named as a co-defendant, and we do not believe that the plaintiffs have any basis for a claim against Westmoreland Mining LLC. We have also filed a motion asking the court to dismiss on the grounds that New York is not the appropriate venue for the case.

The Company is a party to other claims and lawsuits with respect to various matters in the normal course of business. The ultimate outcome of these matters is not expected to have a material adverse effect on the Company’s financial condition, results of operations or liquidity.

ROVA ACQUISITION

On August 25, 2004, we signed an Interest Purchase Agreement with a subsidiary of LG&E Energy LLC. In that agreement, the Company agreed to acquire LG&E’s 50% interest in the ROVA project for (1) a cash payment to LG&E at closing of approximately $22 million and (2) the assumption by the Company’s subsidiaries of LG&E’s portion of the ROVA project’s debt. LG&E’s share of this debt is approximately $103 million at December 31, 2004. In addition, the Company must post cash or letters of credit with a value of approximately $9.8 million to replace LG&E’s portion of the ROVA project’s debt service reserve accounts. The purchase price will be reduced by the amount of any distributions LG&E receives from the ROVA project between August 2004 and closing. Based on distributions LG&E received through September 30, 2005, the cash payment to LG&E would be reduced to $12.0 million. In November 2004, Dominion Virginia Power, the purchaser of the electricity generated by the ROVA Project, asserted that it had a right of first refusal with respect to LG&E’s interest. The Company was negotiating with Dominion Virginia Power to address its claim when, on March 24, 2005, Dominion Virginia Power filed a Petition for Declaratory Judgment in Virginia in the Circuit Court of the City of Richmond seeking an order validating its alleged first right of refusal under the power purchase agreement to acquire LG&E’s partnership interest in the ROVA project. On April 29, 2005, the ROVA partnership filed a demurrer in the Circuit Court of the City of Richmond requesting the Petition for Declaratory Judgment be denied.

On September 2, 2005, the Richmond Circuit Court granted the Partnership’s demurrer motion, effectively denying Dominion’s claim that it has a right of refusal. Dominion has filed a motion for reconsideration of the court’s ruling. A decision is expected before the end of the year. If Dominion’s motion for reconsideration is denied, which the Company’s believes is likely, it is expected that Dominion will appeal the ruling. Such an appeal would prevent completion of the acquisition while the appeal was pending.

The Company and LG&E are currently in negotiations with Dominion Virginia Power in an effort to resolve this dispute. If the negotiations do not lead to an agreement in the absence of a favorable outcome of the litigation, it is unclear whether, or when, we may be able to complete the acquisition of LG&E’s interest in the project. The current litigation brought by Dominion could extend for more than a year if Dominion exhausts all available appeals. LG&E has expressed its intention to complete the sale of its interest when the litigation is resolved.

RECENT ACCOUNTING PRONOUNCEMENTS

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” or SFAS 123R, which replaces SFAS No. 123 and supersedes APB Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005, with early adoption encouraged. In April 2005, the FASB changed the effective date of SFAS 123R to the first interim or annual period after December 15, 2005. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition.

As a result the Company will adopt SFAS 123R on January 1, 2006. The Company has not yet determined the method of adoption or the effect of adopting SFAS 123R. The Company must first determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost, and the transition method to be used at the date of adoption. The effect on net income and earnings per share in the periods following adoption of SFAS No. 123R are expected to be consistent with our pro forma disclosure under SFAS No. 123 (see Note 4 to Consolidated Financial Statements), except that estimated forfeitures will be considered in the calculation of compensation expense under SFAS No. 123R. The effect on net income and earnings per share going forward will depend upon the number and fair value of options granted in future years.

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs: An Amendment of ARB 43, Chapter 4” (SFAS No. 151). This statement clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). It requires that amounts be recognized as current period charges. In addition, this statement requires that allocation of fixed production overheads to the costs of inventory be based on the normal capacity of the production facilities. The provisions of this statement are effective for fiscal years beginning after June 15, 2005. The Company does not expect this guidance to have a material impact on its consolidated results of operations and financial condition.

In March 2005, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 04-6 “Accounting for Stripping Costs in the Mining Industry” (EITF 04-6). This guidance defines stripping costs as variable production costs that should be considered a component of mineral inventory cost subject to the provisions of ARB 43. According to the provisions of ARB 43, all costs of producing the reserves should be considered costs of the extracted minerals under a full absorption costing system and recognized as a component of cost of sales-coal in the same period as the related revenue. The Company classifies stripping costs as overburden removal costs, is evaluating the impact of adopting EITF 04-6, and has not yet determined the effect adoption will have on its consolidated results of operations and financial position. The provisions of EITF 04-6 are effective for fiscal years beginning after December 15, 2005.

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

Material Changes in Financial Condition from December 31, 2004 to September 30, 2005

Forward-Looking Disclaimer

Throughout this Form 10-Q, we make statements which are not historical facts or information and that may be deemed “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements include, but are not limited to, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations. For example, words such as “may,” “will,” “should,” “estimates,” “predicts,” “potential,” “continue,” “strategy,” “believes,” “anticipates,” “plans,” “expects,” “intends,” and similar expressions are intended to identify forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties and other factors, which may cause the actual results, levels of activity, performance or achievements, or industry results, to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others, the following: general economic and business conditions; health care cost trends; the cost and capacity of the surety bond market; the Company’s ability to manage growth and significantly expanded operations; the ability of the Company to implement its growth and development strategy; the Company’s ability to pay the preferred stock dividends that are accumulated but unpaid; the Company’s ability to retain key senior management; the Company’s access to financing; the Company’s ability to maintain compliance with debt covenant requirements; the Company’s ability to achieve anticipated cost savings and profitability targets; the Company’s ability to successfully identify new business opportunities; the Company’s ability to negotiate profitable coal contracts, price reopeners and extensions; the Company’s ability to predict or anticipate commodity price changes; the Company’s ability to maintain satisfactory labor relations; changes in the industry; competition; the Company’s ability to utilize its income tax net operating losses; the ability to reinvest cash, including cash that has been deposited in reclamation accounts, at an acceptable rate of return; weather conditions; the availability of transportation; price of alternative fuels; costs of coal produced by other countries; the demand for electricity; the performance of the ROVA Project and the structure of the ROVA Project’s contracts with its lenders and Dominion Virginia Power; our ability to complete the acquisition of the portion of the ROVA project that we do not currently own; the effect of regulatory and legal proceedings; environmental issues, including the cost of compliance with existing and future environmental requirements; the contingencies of the Company discussed in Note 7 to the Consolidated Financial Statements; the risk factors set forth below; and the other factors discussed in Items 1, 2, 3 and Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission. As a result of the foregoing and other factors, no assurance can be given as to the future results and achievement of the Company’s goals. The Company disclaims any duty to update these statements, even if subsequent events cause its views to change.

Overview

We are an energy company. We mine coal, which is used to produce electric power, and we own interests in power-generating plants. All of our five mines supply baseloaded power plants. Several of these power plants are located adjacent to our mines and we sell virtually all our coal under long-term contracts. Consequently, our mines enjoy relatively stable demand and pricing compared to competitors who sell more of their production on the spot market.

The Company’s coal market strategy is based on long-term sales agreements with a limited number of customer plants rather than spot market sales to a wider market. This strategy reduces, but does not eliminate, the Company’s exposure to market volatility, delivering relatively stable prices and sales levels, but also limits the Company’s ability to immediately capture market price increases. Certain sales agreements are currently scheduled for renewal or renegotiation in the near term, as described below under “Coal Markets and Rail Delivery Issues”.

We currently own a 50% interest in the ROVA I and II coal-fired plants, which have a total generating capacity of 230 MW. We also retain a 4.49% interest in the gas-fired Fort Lupton Project, which has a generating capacity of 290 MW and provides peaking power to the local utility. The ROVA Project is baseloaded and supplies power pursuant to a long-term contract.

Challenges

We believe that our principal current challenges include the following:

•

re-determining sales prices to reflect significantly higher market prices and commodity and production costs and separately addressing the potential impact of limited availability of tires for heavy equipment used at our mines;

•

high ongoing heritage health benefit costs associated with inflation in medical costs and potentially longer life expectancies for retirees and active employees;

•

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

•

funding required contributions to pension plans that were underfunded as a result of lower discount rates used in determining the present value of these obligations at the end of 2004;

•

providing adequate capital for growth;

•

completing the acquisition of LG&E's 50% interest in the ROVA project;

•

implementation of a new company-wide computer system to support our mining and corporate segments;

•

integration of new personnel, especially in the area of finance and accounting;

•

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

•

claims for potential taxes and royalties asserted by various governmental entities.

We discuss these issues, as well as the other challenges we face, elsewhere in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, and under “Risk Factors.”

Critical Accounting Estimates and Related Matters

Our discussion and analysis of financial condition, results of operations, liquidity and capital resources is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require that we make estimates and judgments. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. Actual results may differ materially from these estimates.

We have made significant judgments and estimates in connection with the following accounting matters. Our senior management has discussed the development, selection and disclosure of the accounting estimates in the section below with the Audit Committee of our Board of Directors.

In connection with our discussion of these critical accounting matters, and in order to reduce repetition, we also use this section to present information related to these judgments and estimates.

Postretirement Benefits and Pension Obligations

Our most significant long-term liability is the obligation to provide postretirement medical benefits, pension benefits, workers’ compensation and pneumoconiosis (black lung) benefits. We provide these benefits to our current and former employees and their dependents.

Estimates and Judgments

We estimate the total amount of these obligations with the help of third party professionals using actuarial assumptions and information. Our estimate is sensitive to judgments made about the discount rate, about the rate of inflation in medical costs, and about participation and mortality rates.

Related Information

The present value of our actuarially determined liability for postretirement medical costs increased approximately $6.3 million between December 31, 2004 and September 30, 2005. Actuarial valuations project that our retiree health benefit expenses and cash costs may continue to escalate in the next few years and then will decline to zero over the next approximately sixty years as the number of eligible beneficiaries declines. We incurred cash costs of $5.5 million and $14.6 million for postretirement medical costs during the third quarter of 2005 and first nine months of 2005, respectively. This compares to cash costs of $5.8 million and $19.4 million for postretirement medical costs during the third quarter of 2004 and first nine months of 2004, respectively. We expect to incur approximately $20 million of these cash costs in all of 2005 (including the benefit from the monthly payments withheld beginning in September from the Combined Benefit Fund) compared to $25.1 million paid in 2004 (including $3.5 million of the Combined Benefit Fund’s retroactive assessment, which was paid in 2004 pending the outcome of that litigation).

Our worker’s compensation liability is recorded on an undiscounted basis on the balance sheet. We incurred cash costs of $0.8 million for workers’ compensation benefits during the first nine months of 2005 compared to $1.3 million in 2004. We expect to incur lower cash costs for workers’ compensation benefits in 2005 than we did in 2004 and expect that amount to decline over time. We anticipate that these costs will decline because we are no longer self-insured for workers’ compensation benefits and have had no new claimants since 1995.

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, 2005, our pension trusts are underfunded as a result of lower interest rates, which increased the present value of the remaining obligations, and as a result we will contribute approximately $1.6 million to the pension trusts in 2005. Of that amount, $1.5 million was contributed in the nine months ended September 30, 2005. Based upon recent actuarial estimates, our pension contributions will remain approximately the same in 2006 and then are expected to rise sharply in 2007 and 2008 as a result of lower interest rates at the end of 2004 to determine the amount of future obligations. The amount of future payments may be less severe depending upon the level of year-end 2005 interest rates. As of September 30, 2005, our black lung trust is overfunded by $3.4 million and we do not expect to be required to make additional contributions to this trust in the foreseeable future.

One of the estimates we have made relates to the implementation of the Medicare Prescription Drug Improvement and Modernization Act of 2003 (“Medicare Reform Act”). As provided for under that Act, we recognized a benefit to our anticipated future prescription drug costs for retirees and their dependents in 2003 based on a coordinated implementation of the Medicare Reform Act and our existing benefit programs, including the UMWA 1992 Plan. Earlier this year the government issued regulations which make the subsidy approach the only practical alternative given our existing programs. In October 2005, we adopted the subsidy approach for 2006. The subsidy approach will limit our annual benefit to 28% (to a maximum of $1,330/participant) of actual costs. We expect that a revised actuarial analysis could result in a reduction of approximately $5 million in the projected net present value benefit to us from the Medicare Reform Act and a higher resultant future annual expense of approximately $1.3 million than we had anticipated with a coordinated benefits approach.

Asset Retirement Obligations, Reclamation Costs and Reserve Estimates

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

The liability “Asset retirement obligations” on our consolidated balance sheet represents our estimate of the present value of the cost of closing our mines and reclaiming land that has been disturbed by mining. This liability increases as land is mined and decreases as reclamation work is performed and cash expended. The asset, “Property, plant and equipment – capitalized asset retirement costs,” remains constant until new liabilities are incurred or old liabilities are re-estimated. We annually estimate the future costs of reclamation using standards for mine reclamation that have been established by the government agencies that regulate our operations as well as our own experience in performing reclamation activities. These estimates may change. Developments in our mining program also affect this estimate by influencing the timing of reclamation expenditures

We amortize our acquisition costs, development costs, capitalized asset retirement costs and some plant and equipment using the units-of-production method and estimates of recoverable proven and probable reserves. We review these estimates on a regular basis and adjust them to reflect our current mining plans. The rate at which we record depletion also depends on the estimates of our reserves. If the estimates of recoverable proven and probable reserves decline, the rate at which we record depletion increases. Such a decline in reserves may result from geological conditions, coal quality, effects of governmental, environmental and tax regulations, and assumptions about future prices and future operating costs.

Deferred Income Taxes

Our net income is sensitive to estimates we make about our ability to use our Federal net operating loss carryforwards, or NOLs.

As of December 31, 2004 we had approximately $180 million of NOLs. These NOLs expire at various dates through 2024. When we have taxable income, we can use our NOLs to shield that income from regular U.S. Federal income tax. Our ability to use our NOLs thus depends on all the factors that determine taxable income, including operational factors, such as new coal sales, and non-operational factors, such as changes in heritage health benefit costs. Under Federal tax law, our ability to use our NOLs would be limited if we had a “change of ownership” within the meaning of the Federal tax code.

Our NOLs are one of our deferred income tax assets. We have reduced our deferred income tax assets by a valuation allowance. The valuation allowance is primarily an estimate of the deferred tax assets that may not be realized in future periods. On a quarterly and annual basis, we estimate how much of our NOLs we will be able to use to shield future taxable income and make corresponding adjustments in the valuation allowance. The estimate of future taxable income and use of the NOL’s may change the valuation allowance in connection with an updated assessment of the status of the Company’s business plan.

If we increase our estimated utilization of NOLs, we decrease the valuation allowance, increase our net deferred income tax assets and recognize an income tax benefit in earnings. If we decrease our estimated utilization of NOLs, we increase the valuation allowance, decrease our net deferred income tax assets and increase income tax expense. These changes can materially affect our net income and our assets. In the nine months ended September 30, 2005, for example, we decreased the valuation allowance by $1.5 million because of an increase in this period’s estimate of the expected amount of Federal net operating losses to be used in this and future years. We also made other adjustments in our net deferred tax assets. As a result of these estimates and adjustments and changes in temporary differences between book and tax accounting, our net deferred income tax assets increased from $84.7 million at December 31, 2004 to $92.5 million at September 30, 2005, and we recognized an income tax benefit of $5.5 million.

We previously reported that we expect that our alternative minimum income tax net operating loss carryforwards would be fully utilized in 2005, and that AMT payments in 2006 and beyond will increase significantly. The Energy Bill, which was signed into law on August 8, 2005, includes production tax credits available to us beginning January 1, 2006 for tons sold at our Absaloka Mine from coal reserves owned by the Crow Indians. We expect these tax credits will significantly reduce our liability for AMT in 2006 and beyond, but have not yet completed a full assessment of the value that the Company could receive.

Liquidity and Capital Resources

In 2004, Westmoreland Mining LLC borrowed an additional $35 million from its lenders pursuant to what we call the add-on facility. The add-on facility was intended to permit Westmoreland Mining to undertake certain significant capital projects in the near term without adversely affecting cash available to us. We believe that Westmoreland Mining’s add-on facility substantially improves our near term liquidity. In addition, even though the requirements, including debt service requirements, of Westmoreland Mining’s basic term loan agreement, sometimes referred to as our acquisition debt, restrict our access to some of Westmoreland Mining’s cash, Westmoreland Mining itself provides significant liquidity.

Cash provided by operating activities was $17.0 million for the nine months ended September 30, 2005, compared to the cash provided of $10.7 million for the nine months ended September 30, 2004. Cash from operations in 2005 compared to 2004 increased primarily because of lower distributions from the ROVA project in 2004 as a result of the project’s lenders withholding cash for the Halifax County tax dispute. Working capital was $8.0 million at September 30, 2005 compared to $18.9 million at December 31, 2004. The decrease in working capital resulted primarily from an increase in trade receivables, inventories and deferred overburden removal costs which was more than offset by increases in trade payables due to normal timing differences and the current portion of asset retirement obligations, production taxes payable and the current portion of asset retirement obligations.

We used $18.3 million of cash in investing activities in the nine months ended September 30, 2005 and $20.5 million in the nine months ended September 30, 2004. Cash used in investing activities in 2005 included $15.5 million of additions to property, plant and equipment for mine equipment and development projects and investment in a new corporate-wide software system. Cash used in investing activities in 2005 also included an increase of $3.4 million in restricted accounts pursuant to Westmoreland Mining’s term loan agreement and required collateral for surety bonds. In 2004, additions to property and equipment using cash were $11.7 million, and increases in restricted cash accounts were $9.1 million.

Cash of $1.6 million was used in financing activities in the nine months ended September 30, 2005 primarily due to $7.6 million used for the repayment of long-term debt reduced by $6.5 million borrowings of revolving lines of credit. Cash provided from financing activities of $12.0 million in the first nine months of 2004 included $19.6 million from new borrowing of long-term debt, net of debt issuance costs. We used net cash of $7.3 million for repayment of long-term and revolving debt in the first nine months of 2004.

Consolidated cash and cash equivalents at September 30, 2005 totaled $8.3 million, including $5.9 million at Westmoreland Resources, and $3.2 million at our captive insurance subsidiary. Consolidated cash and cash equivalents at December 31, 2004 totaled $11.1 million, including $4.6 million at Westmoreland Mining, $4.1 million at Westmoreland Resources, and $2.5 million at the captive insurance subsidiary. The cash at Westmoreland Mining is available to us through quarterly distributions, as described below. The cash at Westmoreland Resources is available to us through dividends. In addition, we had restricted cash and bond collateral, which were not classified as cash or cash equivalents, of $34.0 million at September 30, 2005 and $32.7 million at December 31, 2004. The restricted cash at September 30, 2005 included $22.1 million in Westmoreland Mining’s debt service reserve and long-term prepayment accounts. At September 30, 2005, our reclamation, workers’ compensation and postretirement medical cost obligation bonds were collateralized by interest-bearing cash deposits of $11.1 million, which amounts we have classified as non-current assets. In addition, we had accumulated reclamation deposits of $57.7 million at September 30, 2005, which we received from customers of the Rosebud Mine to pay for reclamation. We also had $13.2 million in interest-bearing debt reserve accounts for the ROVA project at September 30, 2005. This cash is restricted as to its use and is classified as part of our investment in independent power projects.

Westmoreland Mining’s term loan agreement restricts Westmoreland Mining’s ability to make distributions to Westmoreland Coal Company from ongoing operations. Until Westmoreland Mining has fully paid the original acquisition debt, which is scheduled for December 31, 2008, Westmoreland Mining may only pay Westmoreland Coal Company a management fee and distribute to Westmoreland Coal Company 75% of Westmoreland Mining’s surplus cash flow. Westmoreland Mining is depositing the remaining 25% into an account that will fund the $30 million balloon payment due December 31, 2008. The add-on facility only restricts distributions to the extent funds are needed to maintain a debt service reserve equal to the next six months principal and interest payments.

Westmoreland Mining has a revolving credit facility which expires in April 2007 of $12 million. As of September 30, 2005, $11.0 million of the facility was available to borrow.

As of September 30, 2005, Westmoreland Coal Company had $8.5 million of its $14.0 million revolving line of credit available to borrow.

On July 28, 2004, we filed a registration statement for a possible rights offering. If the registration statement becomes effective, it would permit holders of our common stock to purchase additional shares of common stock. As stated in the registration statement, the additional equity capital would be used to support our growth and development strategy and for general corporate purposes.

Liquidity Outlook

We described certain liquidity comparisons in the Liquidity Outlook section of the Annual Report on Form 10-K for the year ended December 31, 2004. All of the items described in that report continue to be important to us.

Jewett Mine Supply Contract

Texas Westmoreland Coal Co. and Texas Genco are party to a lignite supply agreement that expires in 2015 and that provides annual price redeterminations based on an equivalent cost of Southern Powder River Basin (SPRB) coal used at the Limestone Electric Generating Station. In January 2004, the parties agreed to fix a price for the period 2004 through 2007, with pricing thereafter to be determined pursuant to the underlying contract. Subsequent dramatic and unexpected increases in commodity costs, including costs for diesel fuel and steel, among other items, rendered the four-year fixed price agreement uneconomic. At the same time, market prices for SPRB coal and associated rail rates have also increased dramatically. Texas Westmoreland and Texas Genco have been negotiating revisions to the fixed price agreement and potentially the underlying long-term agreement. A new interim agreement was reached in September 2005 that enhances the economics of the Jewett Mine over previous interim pricing arrangements, provides capital to support mine development, improves the mechanics for determining equivalent market pricing pursuant to the parties’ underlying contract after 2007, and should return Texas Westmoreland to a stable and satisfactory level of financial performance through the end of 2007, when the contract calls for a reversion to annual, equivalent market value pricing or until the current long-term supply agreement is modified further or restructured. Payments of $4.9 million related to the first nine months of 2005 will be recorded as revenue in the fourth quarter as related performance obligations are completed and payments are received from the customer.

Combined Benefit Fund

As noted in Note 7 to the Consolidated Financial Statements, on August 12, 2005 the United States District Court for the District of Maryland ruled that the UMWA Combined Benefit Fund (“CBF”) has been charging an excessive premium to coal operators since 1992. In our case, the total of the overpayment is approximately $6 million.

We expect the CBF Trustees and the Commissioner of Social Security to appeal the District Court decision. However, we believe that the decision will be upheld on appeal. At that time, the Company would recognize the $6 million as income. In the interim, the Company is offsetting its monthly premium against the overpayment, thereby benefiting cash flow in the amount of approximately $350,000 per month.

Indian Coal Production Tax Credit

In August 2005 the Energy Policy Act of 2005 was enacted. Among other provisions, it contains a tax credit for the production of coal owned by Indian tribes. The credit is $1.50 per ton beginning 2006 through 2009 and $2.00 per ton from 2010 through 2012, with both amounts escalating for inflation. The credit may be used against regular corporate income tax for all years and against Alternative Minimum Tax for the initial period. The Company’s 80%-owned Absaloka Mine, which produces coal under a lease with the Crow Tribe, produces about 7 million tons per year. A significant portion of the credit will be shared with the Crow Tribe when it is realized.

Coal Markets and Rail Delivery Issues

Significant events have occurred over the past several months in the market for coal from the Southern Powder River Basin (“SPRB”) of Wyoming, the market benchmark for most of the Company’s sales. First, the Burlington Northern Santa Fe (“BNSF”) and Union Pacific (“UP”) railroads have experienced significant disruptions in their ability to carry coal out of the SPRB on the so-called Joint Line due to continued increases in demand for SPRB coal and due to a major rail bed ballast rehabilitation project that has limited capacity on that route. The railroads have stated that the rehabilitation work should be largely completed prior to year-end, and they report that train cycling has begun to improve. These rail issues, combined with increasing demand for SPRB coal, resulted in a marked increase in prices for SPRB coal during the third quarter, a trend that continues into the fourth quarter. Prices for higher Btu, ultra-low sulfur SPRB coal have made further gains due to the rise in market prices for sulfur dioxide (“SO₂”) emission allowances, which are required by most coal-fired power plants for compliance with regulations under the federal Clean Air Act.

Two-thirds of the Company’s coal sales are delivered to its customers via conveyor belt, coal haulers, or highway trucks, while the remaining third is delivered via the BNSF. The Company’s BNSF-served mines, in Montana and North Dakota, are not directly affected by the Joint Line rehabilitation project. Rather, Company mines have been affected indirectly, and to a much lesser extent than the SPRB mines, because the BNSF has shifted some crews and locomotives to the SPRB from time-to-time to help to alleviate the issues there. Unlike the SPRB producers, the Company does not expect to lose production or sales in 2005 as a result of the on-going rail issues.

Market prices for SPRB coal have increased significantly from the first half of the year. Eighteen percent of the Company’s total sales tonnage is scheduled for price re-determination on January 1, 2006, and most of these tons will generally be benchmarked to SPRB market prices. The extent of the increases we receive will depend on, among other things, the price adjustment provisions of the various contracts, the price of SPRB coal at the time of the last re-determination, and circumstances unique to each customer. Higher SO2 allowance prices may also limit the increase we receive, because our coal has somewhat higher sulfur content than SPRB coal and thus requires the use of more SO2 allowances. Our ability to capture further market gains is restricted by the facts that almost all of our production is sold under term contracts. In addition, our mines are now producing at maximum in-place capacity. About 5% of total Company tons will be open to market or market-benchmarked price re-determinations on January 1, 2007, 18% on January 1, 2008, and, if certain customers elect not to invoke extension options, 10% on January 1, 2009 (plus an additional 22% in 2008 and 2009 if the market-based pricing mechanism under the Jewett Mine’s contract with Texas Genco is preserved in the renegotiation of a long-term supply agreement).

Growth and Development

In Note 8 to our Consolidated Financial Statements in this Form 10-Q, we describe our possible acquisition of LG&E's interest in the ROVA Project, including the current status of the litigation with Dominion Virginia Power that is the factor preventing us from completing that acquisition. We describe the financial implications of that transaction in our Annual Report on Form 10-K for the year ended December 31, 2004 under "Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Implications of the ROVA Acquisition." Because of the passage of time since the agreement with LG&E was executed, either party may withdraw at any time. However, we believe that LG&E would complete the transaction with us, if the dispute with Dominion were to be resolved and all other conditions to closing satisfied.

Continued growth remains an important part of our strategy. The application for an air permit for our Gascoyne Project in North Dakota was filed in May 2004 and a completeness determination was received in July 2004. The North Dakota Department of Health (Department of Health) issued a draft air permit on March 29, 2005. The Department of Health started a 30-day public comment period on April 2, 2005 that included a public hearing on April 21. The public comment period concluded on May 1, 2005. The Department of Health issued the final air permit in June 2005. The Company also continues to identify and evaluate other potential growth opportunities in the coal and independent power sectors.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements within the meaning of the rules of the Securities and Exchange Commission.

RESULTS OF OPERATIONS

Quarter Ended September 30, 2005 Compared to Quarter Ended September 30, 2004.

Coal Operations. Coal sold was 8.0 million tons in the third quarter ended September 30, 2005 compared to 7.3 million tons in the third quarter of 2004. All of our mines except the Savage Mine increased both tons and revenues. Production at the Jewett Mine was higher in the third quarter of 2005 than in the third quarter of 2004 because heavy rain, flooding, and ground saturation depressed production in the third quarter of 2004. Our overall revenue has increased year over year for the third quarter due to an increase in tons sold, and higher contract prices, including the increased price under the new interim agreement at the Jewett Mine. As discussed in the Liquidity Outlook section of this Form 10-Q under Jewett Mine Supply Contract, payments of $4.9 million related to the first nine months of 2005 will be recorded as revenue in the fourth quarter as related performance obligations are completed and payments are received from the customer. Revenues also increased because arrangements allowed the Company’s mining operations to recover portions of cost increases for commodities. The Company’s coal sales contracts generally protect our operations against cost inflation, either through direct pass-through or through index adjustments, and we are in the process of negotiating provisions to cover commodity price risk under certain contracts where such provisions have been temporary or absent. Cost of sales increased for the third quarter of 2005 compared to the comparable period in 2004 primarily as a result of more tons produced and increased commodity prices.

The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods for actual results as reported:

		Quarter Ended
		September 30,
		2005		2004	Change


Revenues – thousands	$	94,377	$	78,826	20%

Volumes – millions of equivalent coal tons		8.010		7.303	10%

Cost of sales – thousands	$	78,498	$	63,624	23%

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

Depreciation, depletion and amortization increased to $4.8 million in the third quarter of 2005 compared to $4.0 million in 2004‘s third quarter. The increase is primarily related to increased capital expenditures at the mines for both continued mine development and the replacement of mining equipment and increased amortization of capitalized asset retirement costs.

Independent Power. Our equity in earnings from independent power operations decreased to $1.7 million in the third quarter 2005 from $5.3 million in the quarter ended September 30, 2004. For the quarters ended September 30, 2005 and 2004, the ROVA project produced 381,000 and 457,000 megawatt hours, respectively, and achieved average capacity factors of 82% and 99%, respectively. The third quarter of 2005 had a planned maintenance outage at the ROVA I plant, resulting in a lower capacity factor than in the third quarter of 2004, which had no planned outage. Also in 2005, ROVA experienced more unscheduled outages to repair tube leaks than in 2004. In the quarter, the Company accrued an additional $0.9 million for its share of the anticipated cost to settle the Halifax County property tax assessment discussed in Note 7 (“Contingencies”) to our Consolidated Financial Statements. We recognized $70,000 in equity earnings in third quarter 2005, compared to $35,000 in the quarter ended September 30, 2004, from our 4.49% interest in the Ft. Lupton project.

Costs and Expenses.Selling and administrative expenses increased to $9.2 million in the quarter ended September 30, 2005 compared to $7.7 million in the quarter ended September 30, 2004. Compensation costs, professional fees (including higher costs for Sarbanes-Oxley compliance) and legal costs were higher in the third quarter of 2005 compared to the third quarter of 2004. Long-term incentive compensation decreased $0.8 million in third quarter 2005 compared to the three months ended September 30, 2004 because the price of the Company’s stock increased less than our peer companies in the third quarter of 2005. The long-term incentive compensation is based upon the performance of the Company’s stock. In general, this expense increases or decreases as the market price of the Company’s common stock increases or decreases.

Heritage health benefit costs were $6.9 million in the third quarter of 2005 compared to $7.2 million for the third quarter of 2004. This reduction in expense was primarily because there was an increase in the overfunded amount in our Black Lung trust fund. In 2005, we experienced an increase in the amount by which the black lung trust is overfunded compared to a decrease in the third quarter of 2004. This change is a result of increased interest rates that decreased the present value of the trust’s obligations more than the decrease of the market value of the trust’s assets.

Interest expense was comparable for both the three months ended September 30, 2005 and 2004. Interest expense associated with WML’s Series D Notes, which were issued in December of 2004, and with the increased use of the revolving lines of credit, was largely offset by the pay-down of WML’s Series B Notes which were issued during 2001 in connection with the purchase of certain coal operations. Interest income increased in 2005 due to higher interest rates on larger restricted cash and surety bond collateral balances that are invested.

As a result of the acquisitions we completed in the spring of 2001, the Company recognized a $55.6 million deferred income tax asset in April 2001, which assumed that a portion of previously unrecognized net operating loss carryforwards would be utilized because of the projected generation of future taxable income. That amount has grown over the years as it is estimated more net operating losses will be used. The deferred tax asset increased to $92.5 million as of September 30, 2005 from $84.7 million at December 31, 2004 because of temporary differences (such as accruals for pension and reclamation expense, which are not deductible for tax purposes until paid) arising during the intervening period and due to a reduction of the deferred income tax valuation allowance discussed above. Deferred tax assets are comprised of both a current and long-term portion. When taxable income is generated, the deferred tax asset relating to the Company’s net operating loss carryforwards is reduced and a deferred tax expense (non-cash) is recognized although no regular Federal income taxes are paid. The current income tax expense for the third quarter of 2005 is the result of income tax obligations for State income taxes as a result of the expense of $2.1 million tax in North Carolina for the Rensselaer assessment, net of the impact of changes in deferred tax assets and liabilities. There was a deferred tax benefit of $3.2 million recognized in the third quarter of 2005.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Coal Operations. Coal revenues increased to $266.2 million for the nine months ended September 30, 2005 from $243.0 million for the nine months ended September 30, 2004 primarily as a result of an increase in tons sold to 22.7 million from 21.4 million and higher prices, including a one-time “catch-up” payment of $2.4 million for past cost increases for commodities received in the first quarter of 2005. As discussed in the Liquidity Outlook section of this Form 10-Q under Jewett Mine Supply Contract, payments of $4.9 million related to the first nine months of 2005 will be recorded as revenue in the fourth quarter as related performance obligations are completed and payments are received from the customer. The year-to-date 2004 revenue includes the $16.3 million Colstrip 1&2 arbitration award in 2004 for the price reopener with the owners of Colstrip Units 1&2 for coal shipped from July 30, 2001 to May 31, 2004. Production taxes and royalties on those revenues totaled $5.1 million. The increase in tons sold in 2005 came from new or extended sales contracts at the Rosebud mine as well as increases at the Jewett and Absaloka Mines. Cost of sales increased for the nine months of 2005 compared to 2004 primarily as a result of increased tons produced, commodity prices and higher stripping ratios. In 2005, very difficult mining conditions at the Beulah Mine and unusually heavy rainfall there increased costs. Costs in 2004 included unplanned repairs to a primary dragline, a customer outage that extended beyond its planned duration and weather related production interruptions at the Jewett Mine.

The following table shows comparative coal revenues, sales volumes, cost of sales and percentage changes between the periods for actual results as reported and on a pro forma basis (which excludes the impact of the Colstrip arbitration award in the first nine months of 2004):

	Nine Months Ended September 30,
	Actual						Pro forma

		2005		2004	Change		2004	Change*

Revenues - thousands	$	266,177	$	242,978	10%	$	226,678	17	%

Volumes - millions of equivalent coal tons		22.709		21.426	6%

Cost of sales - thousands	$	217,606	$	189,942	15%	$	184,842	18	%

* Change represents change between 2005 Actual amounts and 2004 Pro forma amounts.

Depreciation, depletion and amortization increased to $14.3 million in the nine months of 2005 compared to $11.4 million in the nine months of 2004. The increase is primarily related to increased capital expenditures at the mines for both continued mine development and the replacement of mining equipment and increased amortization of capitalized asset retirement costs.

Independent Power.Our equity in earnings from the independent power projects decreased to $10.3 million in the first nine months of 2005 from $12.4 million for the nine months ended September 30, 2004. For the nine months ended September 30, 2005 and 2004, the ROVA projects produced 1,191,000 and 1,310,000 megawatt hours, respectively, and achieved capacity factors of 87% in 2005 and 95% in 2004. The lower capacity factor in 2005 was discussed above in the quarterly results. In 2004, equity in earnings was reduced by the $2.0 million charge for contested retroactive Halifax County personal property tax assessments. The Company accrued an additional $0.9 million in third quarter 2005 related to these assessments. In 2005, the ROVA I and II plants had more scheduled outages for planned repairs that decreased the capacity factor, and they experienced unscheduled outages for repairs than in 2004. We recognized $296,000 in equity earnings in the nine months of 2005, compared to $223,000 in the nine months of 2004 from our 4.49% interest in the Ft. Lupton project.

Costs and Expenses. Selling and administrative expenses were $24.1 million for the nine months ended September 30, 2005 compared to $22.4 million for the nine months ended September 30, 2004. The 2005 period included the costs of the $1.2 million Entech settlement and litigation legal fees discussed in last quarter’s Form 10-Q. Compensation costs and professional fees were higher in 2005 than in 2004. Legal fees associated with the Company’s legal contingencies were higher in 2005. However, as a result of the performance of the Company’s common stock in the nine months of 2005, our long-term incentive performance unit plan resulted in a benefit of $1.2 million compared to an expense of $1.7 million in 2004.

Heritage health benefit costs were $0.3 million lower in the first nine months of 2005 compared to the first nine months of 2004. Postretirement medical plan payments to the Combined Benefit Fund decreased in 2005 and this was mostly offset by higher actuarially determined costs for postretirement medical plans.

Interest expense was $7.7 million and $7.5 million for the nine month periods ended September 30, 2005 and 2004, respectively. Interest associated with the increased debt outstanding from the Westmoreland Mining add-on facility and borrowing using the Company’s revolving credit facilities was partially offset by the lower interest expense on the acquisition financing obtained during 2001. Interest income decreased in 2005 in spite of larger balances in our restricted cash and surety bond collateral accounts because 2004 included $700,000 in interest relating to the Colstrip Units 1 & 2 arbitration decision.

When taxable income is generated, the deferred tax asset relating to the Company’s net operating loss carryforwards is reduced and a deferred tax expense (non-cash) is recognized although no regular Federal income taxes are paid. Current income tax expense in both 2005 and 2004 relate to obligations for State income taxes, including the $2.1 million expense recorded for tax assessments for prior years in North Carolina and Federal alternative minimum tax. During the nine months of 2005, the deferred tax benefit of $7.6 million includes a $1.5 million benefit caused by a reduction in the valuation allowance resulting from an increase in the amount of Federal net operating loss carryforwards we expect to utilize before their expiration.

Other Comprehensive Income.The other comprehensive income of $255,000, net of income taxes of $170,000, recognized during the nine months ended September 30, 2005 represents the change in the unrealized loss on an interest rate swap agreement on the ROVA debt caused by changes in market interest rates during the period. This compares to the other comprehensive income of $406,000, net of income taxes of $271,000, for the nine months ended September 30, 2004.

RISK FACTORS

In addition to the trends and uncertainties described in Items 1 and 3 of our Annual Report on Form 10-K for the year ended December 31, 2004 and elsewhere in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, we are subject to the risks set forth below.

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

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

•

unplanned equipment failures, which could interrupt production and require us to expend significant sums to repair our capital equipment, including our draglines, the large machines we use to remove the soil that overlies coal deposits;

•

geological conditions, such as variations in the quality of the coal produced from a particular seam, variations in the thickness of coal seams and variations in the amounts of rock and other natural materials that overlie the coal that we are mining; and

•

weather conditions.

Examples of recent conditions or events of these types include the following:

•

A dragline at Jewett experienced mechanical failures in July 2005 that took the machine out of service and reduced production for approximately four weeks.

•

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 5 days. This resulted in a reduction in coal production during the quarter.

•

In the second quarter of 2004, our Jewett Mine received approximately 93% more rain than normal, impeding production.

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

In 2004, we sold approximately 98% of our coal under long-term contracts and about three-fourths of our coal under contracts that obligate our customers to purchase all or almost all of their coal requirements from us, or which give us the right to supply all of the plant’s coal, lignite or fuel requirements. Three of our contracts, with the owners of the Limestone Electric Generating Station, Colstrip Units 3&4 and with Colstrip Units 1&2, accounted for 26%, 22% and 16%, respectively, of our coal revenues in 2004. (The contract with the owners of Colstrip Units 1&2 accounted for this percentage of our 2004 revenues because we received, in 2004, an arbitration award that covered coal delivered to Colstrip Units 1&2 from July 2001 to May 2004.) Interruption in the purchases by or operations of our principal customers could significantly affect our revenues and profitability. Unscheduled maintenance outages at our customers’ power plants and unseasonably moderate weather are examples of conditions that might cause our customers to reduce their purchases. Four of our five mines are dedicated to supplying customers located adjacent to or near the mines, and these mines may have difficulty identifying alternative purchasers of their coal if their existing customers suspend or terminate their purchases.

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

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

We may not be able to complete the ROVA acquisition.

In August 2004, we signed an Interest Purchase Agreement with LG&E in which we agreed to acquire from LG&E the 50% interest in the ROVA Project that we do not currently own. In November 2004, Dominion Virginia Power asserted that it had a right of first refusal with respect to LG&E's interest in this project, and in March 2005, Dominion Virginia Power filed a Petition for Declaratory Judgment in the Circuit Court of the City of Richmond, Virginia, seeking an order validating its alleged first right of refusal. In September 2005, the Richmond Circuit Court issued a decision effectively denying Dominion Virginia Power's claim. Dominion Virginia Power has filed a motion for reconsideration of the court's ruling. We will not be able to complete the acquisition while Dominion Virginia Power's claim is pending. In addition, because of the passage of time since the Interest Purchase Agreement with LG&E was executed, either party could withdraw from the agreement at any time. In view of Dominion Virginia Power's claim, there can be no assurance that we will be able to acquire LG&E's interest in the ROVA Project.

Even if we are able to resolve the claim of Dominion Virginia Power, the completion of the ROVA transaction is subject to the following conditions specified in our Interest Purchase Agreement with LG&E:

•

Both we and LG&E must have performed and complied with, in all material respects, the obligations and covenants that we and LG&E are required to perform and comply with prior to the closing.

•

Our representations and warranties, and the representations and warranties of LG&E, must be true and correct in all material respects on the closing date.

•

Since August 25, 2004, there must not have been a material adverse effect on the assets, business, condition, or results of operations of the partnership that owns the ROVA Project; the condition, use, or operation of the ROVA Project itself; the payments owed to the ROVA Project by Dominion Virginia Power under the power purchase agreement; or LG&E’s 50% interest in the ROVA Project.

•

LG&E and we must have received all necessary consents to the transaction from all regulatory authorities and third parties, including the consents of the lenders to the ROVA Project.

•

We must have obtained replacement insurance that satisfies the insurance requirements of the ROVA Project’s credit agreement with its lenders.

•

LG&E and its affiliates must have been released from their obligations under the ROVA Project’s existing letters of credit, and the beneficiaries of those letters of credit must not have drawn under them.

The closing of the ROVA acquisition is also subject to other customary conditions. Many of the conditions to the closing of the ROVA acquisition are beyond our control, and there can be no assurance that those conditions will be satisfied.

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

We are a party to several legal proceedings, which are described more fully in our Annual Report on Form 10-K for the year ended December 31, 2004 under Item 3 – “Legal Proceedings”, and in Note 7 (“Contingencies”) to our Consolidated Financial Statements in this Quarterly Report on Form 10-Q. Adverse outcomes in some or all of the pending cases could result in substantial damages against us or harm our business.

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

At the end of 2000, we owned one mine and employed 31 people. In the spring of 2001, we acquired the Rosebud, Jewett, Beulah and Savage Mines from Entech and Knife River Corporation, and at the end of 2004, we employed 943 people. This growth has placed significant demands on our management as well as our resources and systems. One of the principal challenges associated with our growth has been, and we believe will continue to be, our need to attract and retain highly skilled employees and managers. In the second quarter of 2005, we hired a new Chief Financial Officer, General Counsel, Controller, and Assistant Controller. Eight of the eleven professional positions in our corporate-level finance and accounting department and both of the positions in our legal department are or will be filled by individuals who have joined the Company since the beginning of 2005. To manage our financial, accounting and legal matters effectively, these individuals must absorb considerable, necessary background information on the Company and we must successfully integrate them into our ongoing activities. In the second quarter of 2005, we began to implement a new Company-wide computer system. The start-up of this new system has imposed increased demands on employees, particularly our finance and accounting staff. If we are unable to attract and retain the personnel we need to manage our increasingly large and complex operations, if we are unable to integrate successfully our new officers and employees, and if we are unable to complete successfully the implementation of our new computer system, our ability to manage our operations effectively and to pursue our business strategy could be compromised.

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

We are in the process, continuing into 2006, of implementing a new company-wide computer system to replace the various systems that have been in place at our corporate offices, at the operations we owned in 2001, and at the operations we acquired in 2001. Once implemented, we expect this system to help establish standard, uniform, best practices and reporting in a number of areas, increase productivity and efficiency, and enhance management of our business. Certain aspects of our information technology infrastructure and operational activities have and may continue to experience difficulties in connection with this transition and implementation. Such difficulties can cause delay, be time consuming and more resource intensive than planned, and cost more than we have anticipated. There can be no assurance that we will achieve the cost savings and return on investment intended from this project.

Our growth and development strategy could require significant resources and may not be successful.

We regularly seek opportunities to make additional strategic acquisitions, to expand existing businesses, to develop new operations and to enter related businesses. We may not be able to identify suitable acquisition candidates or development opportunities, or complete any acquisition or project, on terms that are favorable to us. Acquisitions, investments and other growth projects involve risks that could harm our operating results, including difficulties in integrating acquired and new operations, diversions of management resources, debt incurred in financing such activities and unanticipated problems and liabilities. We anticipate that we would finance acquisitions and development activities by using our existing capital resources, borrowing under existing bank credit facilities, issuing equity securities or incurring additional indebtedness. We may not have sufficient available capital resources or access to additional capital to execute potential acquisitions or take advantage of development opportunities.

Our expenditures for postretirement medical and life insurance benefits could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.

We provide various postretirement medical and life insurance benefits to current and former employees and their dependents. We estimate the amounts of these obligations based on assumptions described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Estimates and Related Matters” herein. We accrue amounts for these obligations, which are unfunded, and we pay as costs are incurred. If our assumptions change, the amount of our obligations could increase, and if our assumptions are inaccurate, we could be required to expend greater amounts than we anticipate. We estimate that our gross obligation for postretirement medical and life insurance benefits was $259.8 million at December 31, 2004. We had an accrued liability for postretirement medical and life insurance benefits of $140.6 and $134.2 million at September 30, 2005 and December 31, 2004, respectively, and we expect to accrue an additional $122.1 million over the next ten years, as permitted by Statement of Financial Accounting Standards No. 106. We regularly revise our estimates, and the amount of our accrued obligations is subject to change.

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, 2005, our total gross indebtedness was approximately $116 million, which included Westmoreland Mining’s obligations under its term loan agreement, including the add-on facility described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” We will assume significant non-recourse debt upon completion of the ROVA acquisition, we may incur additional indebtedness to finance the ROVA acquisition and we may incur additional indebtedness in the future, including indebtedness under our two existing revolving credit facilities.

Westmoreland Mining’s term loan agreement restricts its ability to distribute cash to Westmoreland Coal Company through 2011 and limits the types of transactions that Westmoreland Mining and its subsidiaries can engage in with Westmoreland Coal Company and our other subsidiaries. Westmoreland Mining executed the term loan agreement in 2001 and used the proceeds to finance its acquisition of the Rosebud, Jewett, Beulah and Savage Mines. The final payment on this indebtedness, which we call Westmoreland Mining’s acquisition debt, is in the amount of $30 million and is due on December 31, 2008. After payment of principal and interest, 25% of Westmoreland Mining’s surplus cash flow is dedicated to an account that is expected to fund this final payment. The $35 million add-on facility is scheduled to be paid-down from 2009 through 2011. Westmoreland Mining has pledged or mortgaged substantially all of its assets and the assets of the Rosebud, Jewett, Beulah and Savage Mines, and we have pledged all of our member interests in Westmoreland Mining, as security for Westmoreland Mining’s indebtedness. In addition, Westmoreland Mining must comply with financial ratios and other covenants specified in the agreements with its lenders. Failure to comply with these ratios and covenants or to make regular payments of principal and interest could result in an event of default.

A substantial portion of our cash flow must be used to pay principal of and interest on our indebtedness and is not available to fund working capital, capital expenditures or other general corporate uses. In addition, the degree to which we are leveraged could have other important consequences, including:

•

increasing our vulnerability to general adverse economic and industry conditions;

•

limiting our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements; and

•

limiting our flexibility in planning for, or reacting to, changes in our business and in the industry.

If our or Westmoreland Mining’s operating performance declines, or if we or Westmoreland Mining do not have sufficient cash flows and capital resources to meet our debt service obligations, we or Westmoreland Mining may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. If Westmoreland Mining were to default on its debt service obligations, a note holder may be able to foreclose on assets that are important to our business.

At September 30, 2005, the ROVA Project had total debt of approximately $183 million. The ROVA Project’s credit agreement restricts its ability to distribute cash, contains financial ratios and other covenants, and is secured by a pledge of the project and substantially all of the project’s assets. If the ROVA Project fails to comply with these ratios and covenants or fails to make regular payments of principal and interest, an event of default could occur. A substantial portion of the ROVA Project’s cash flow must be used to pay principal of and interest on its indebtedness and is not available to us. If the ROVA Project were to default on its debt service obligations, a creditor may be able to foreclose on assets that are important to our business.

If the cost of obtaining new reclamation bonds and renewing existing reclamation bonds continues to increase, our profitability could be reduced.

Federal and state laws require that we provide bonds to secure our obligations to reclaim lands used for mining. We must post a bond before we obtain a permit to mine any new area. These bonds are typically renewable on a yearly basis and have become increasingly expensive. Bonding companies are requiring that applicants collateralize a portion of their obligations to the bonding company. In 2004, we paid approximately $2.5 million in premiums for reclamation bonds and posted approximately $3.2 million in collateral, in addition to the collateral that we had previously posted, for those bonds. As we permit additional areas for our mines in 2005 and 2006, 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 and one in an amount of approximately $5.0 million. In December 2003, the issuer of our $21.3 million bond indicated a desire to exit the business of bonding Coal Act obligations. In February 2004, this company renewed our Coal Act bond. Although we believe that the issuer of this bond must continue to renew the bond so long as we do not default on our obligations to the 1992 Plan, the issuer of this bond filed a Complaint for Declaratory Judgment on May 11, 2005 to force our payment of $21.3 million and to cancel the bond. If either of the companies that issue our Coal Act bonds were to cancel or fail to renew our bonds, we may be required to post another bond or secure our obligations with a letter of credit or cash. At this time, we are not aware of any other company that would provide a surety bond to secure obligations under the Coal Act. We do not believe that we could now obtain a letter of credit without collateralizing that letter of credit in full with cash. The Company does not currently have $21.3 million in cash available.

We face competition for sales to new and existing customers, and the loss of sales or a reduction in the prices we receive under new or renewed contracts would lower our revenues and could reduce our profitability.

Approximately one-third of the coal tonnage that we will produce in 2005 will be sold under long-term contracts to power plants that take delivery of our coal from common carrier railroads. All of the Absaloka Mine’s sales are delivered by rail and about 20% of the Rosebud Mine’s and Beulah Mine’s sales are delivered by rail. Contracts covering 90% of those rail tons are scheduled to expire between December 2006 and December 2008. As a general matter, plants that take coal by rail can buy their coal from many different suppliers. We will face significant competition, primarily from mines in the Southern Powder River Basin of Wyoming, to renew our long-term contracts with our rail-served customers, and for contracts with new rail-served customers. Many of our competitors are larger and better capitalized than we are and have coal with a lower sulfur and ash content than our coal. As a result, our competitors may be able to adopt more aggressive pricing policies for their coal supply contracts than we can. If our existing customers fail to renew their existing contracts with us on terms that are at least equivalent to those in effect today, or if we are unable to replace our existing contracts with contracts of equal size and profitability from new customers, our revenues and profitability would be reduced.

Approximately two-thirds of the coal tonnage that we will sell in 2005 will be delivered under long-term contracts to power plants located adjacent to our mines. We will face somewhat less competition to renew these contracts upon their expiration, both because of the transportation advantage we enjoy by being located adjacent to these customers and because most of these customers would be required to invest additional capital to obtain rail access to alternative sources of coal. Our Jewett Mine is an exception because our customer has already built rail unloading and associated facilities that are being used to take coal from the Southern Powder River Basin as permitted under our contract with that customer.

Stricter environmental regulations, including regulations recently adopted by the EPA, could reduce the demand for coal as a fuel source and cause the volume of our sales to decline.

Coal contains impurities, including sulfur, mercury, nitrogen and other elements or compounds, many of which are released into the air when coal is burned. Stricter environmental regulation of emissions from coal-fired electric generating plants could increase the costs of using coal, thereby reducing demand for coal as a fuel source generally, and could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future. The U.S. Environmental Protection Agency, or EPA, has recently adopted regulations that could increase the costs of operating coal-fired power plants, including the ROVA Project. Congress has considered legislation that would have this same effect. At this time, we are unable to predict the impact of these new regulations on our business. However, we expect that the new regulations may alter the relative competitiveness among coal suppliers and coal types. The new regulations could also disadvantage some or all of our mines, and notwithstanding our coal supply contracts we could lose all or a portion of our sales volumes and face increased pressure to reduce the price for our coal, thereby reducing our revenues, our profitability and the value of our coal reserves.

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

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

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, the ROVA Project has “state of the art” emissions control technology that reduces its emissions of sulfur dioxide, nitrogen oxide and, collaterally, mercury.

•

The CAIR is likely to affect the existing national market for sulfur dioxide emissions allowances, thereby indirectly affecting coal producers and consumers that are not directly subject to the CAIR.

For all the foregoing reasons, and because it is unclear how States will allocate their emissions budgets, we are unable to predict at this time how these new rules will affect the Company.

The Company’s contracts protect our sales positions, including volumes and prices, to varying degrees. However, we could face disadvantages under the new regulations that could result in our inability to renew some or all of our contracts as they expire or reach scheduled price reopeners or that could result in relatively lower prices upon renewal, thereby reducing our relative revenue, profitability, and/or the value of our coal reserves.

New legislation or regulations in the United States aimed at limiting emissions of greenhouse gases could increase the cost of using coal or restrict the use of coal, which could reduce demand for our coal, cause our profitability to suffer and reduce the value of our assets.

A variety of international and domestic environmental initiatives are currently aimed at reducing emissions of greenhouse gases, such as carbon dioxide, which is emitted when coal is burned. If these initiatives were to be successful, the cost to our customers of using coal could increase, or the use of coal could be restricted. This could cause the demand for our coal to decrease or the price we receive for our coal to fall, and the demand for coal generally might diminish. Restrictions on the use of coal or increases in the cost of burning coal could cause us to lose sales and revenues, cause our profitability to decline or reduce the value of our coal reserves.

Demand for our coal could also be reduced by environmental regulations at the state level.

Environmental regulations by the states in which our mines are located, or in which the generating plants they supply operate, may negatively affect demand for coal in general or for our coal in particular. For example, Texas passed regulations requiring all fossil fuel-fired generating facilities in the state to reduce nitrogen oxide emissions beginning in May 2003. In January 2004, we entered into a supplemental settlement agreement with Texas Genco II pursuant to which the Limestone Station must purchase a specified volume of lignite from the Jewett Mine. In order to burn this lignite without violating the Texas nitrogen oxide regulations, the Limestone Station is blending our lignite with coal, produced by others in the Southern Powder River Basin, and using emissions credits. Considerations involving the Texas nitrogen oxide regulations might affect the demand for lignite from the Jewett Mine in the period after 2007, which is the last year covered by the four- year fixed price agreement. Texas Genco II might claim that it is less expensive for the Limestone Station to comply with the Texas nitrogen oxide regulations by switching to a blend that contains relatively more coal from the Southern Powder River Basin and relatively less of our lignite. Other states are evaluating various legislative and regulatory strategies for improving air quality and reducing emissions from electric generating units. Passage of other state-specific environmental laws could reduce the demand for our coal.

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 $314.1 million (with a present value of $145.9 million) at September 30, 2005. Of these liabilities, our customers have assumed a gross aggregate of $189.5 million and have secured a portion of these obligations by posting bonds in the amount of $50 million and funding reclamation escrow accounts that currently hold approximately $57.7 million, in each case at September 30, 2005. We estimate that our gross obligation for final reclamation that is not the contractual responsibility of others was $124.6 million at September 30, 2005.

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

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

Our profitability could be affected by unscheduled outages at the ROVA Project or if scheduled outages at the ROVA Project last longer than we anticipate. For example, the ROVA I unit was out of service for 20 days in September and early October 2005. Also, the ROVA II unit is scheduled to be out of service for 28 days in October and November 2005. The ROVA Project’s contract with Dominion Virginia Power is structured so that our annual revenues will not be adversely affected by the ROVA I outage, although they do impact quarterly revenues. However, if maintenance uncovers matters beyond those anticipated, the outage could be prolonged beyond the scheduled period, which could reduce the ROVA Project’s profitability and our revenues. In addition, if the maintenance uncovers a matter that must be remedied or repaired, the cost of those repairs may also adversely affect the ROVA Project’s profitability.

Increases in the cost of the fuel, electricity and materials 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 has increased drastically in 2005 as the supply has 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.

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

Over the next several years, we anticipate making significant capital expenditures, principally at the Rosebud Mine, in order to add to and refurbish our machinery and equipment and prepare new areas for mining. We also began implementing a new company-wide computer system in 2005. The costs of any of these expenditures could exceed our expectations, which could reduce our profitability and divert our capital resources from other uses.

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

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

Provisions of our certificate of incorporation, bylaws and Delaware law, and our stockholder rights plan, may have anti-takeover effects that could prevent a change of control of our company that you may consider favorable, and the market price of our common stock may be lower as a result.

Provisions in our certificate of incorporation and bylaws and Delaware law could make it more difficult for a third party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our bylaws impose various procedural and other requirements that could make it more difficult for stockholders to effect some types of corporate actions. In addition, a change of control of our Company may be delayed or deterred as a result of our stockholder rights plan, which was initially adopted by our Board of Directors in early 1993 and amended and restated in February 2003. Our ability to issue preferred stock in the future may influence the willingness of an investor to seek to acquire our company. These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control of Westmoreland.

ITEM 3
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

Commodity Price Risk

The Company, through its subsidiaries Westmoreland Resources, Inc. and Westmoreland Mining LLC, produces and sells coal to third parties from coal mining operations in Montana, Texas and North Dakota, and through its subsidiary, Westmoreland Energy, LLC, produces and sells electricity and steam to third parties from its independent power projects located in North Carolina and Colorado. Nearly all of the Company’s coal production and all of its electricity and steam production are sold through long-term contracts with customers. These long-term contracts serve to reduce the Company’s exposure to changes in commodity prices, although some of the Company’s contracts are adjusted periodically based upon market prices and some contracts provide for fixed pricing. The Company has not entered into derivative contracts to manage its exposure to changes in commodity prices, and was not a party to any such contracts at September 30, 2005.

Interest Rate Risk

The Company and its subsidiaries are subject to interest rate risk on its debt obligations. Long-term debt obligations have fixed interest rates, and the Company’s revolving lines of credit have a variable rate of interest indexed to either the prime rate or LIBOR. Based on balances outstanding on these instruments as of September 30, 2005, a one percent change in the prime interest rate or LIBOR would increase or decrease interest expense by $65,000 on an annual basis. Westmoreland Mining’s Series D Notes under its term debt agreement have a variable interest rate based on LIBOR. A one percent change in the LIBOR would increase or decrease interest expense by $146,000 on an annual basis. The Company’s heritage health benefit costs are also impacted by interest rate changes because its pension, pneumoconiosis and post-retirement medical benefit obligations are recorded on a discounted basis.

ITEM 4
CONTROLS AND PROCEDURES

The Company’s management, with the participation of the Company’s chief executive officer and chief financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of September 30, 2005. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Based on the evaluation of the Company’s disclosure controls and procedures as of September 30, 2005, the Company’s chief executive officer and chief financial officer concluded that, as of such date, the Company’s disclosure controls and procedures were effective at the reasonable assurance level.

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, 2005 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1
LEGAL PROCEEDINGS

As described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, “Item 3 — Legal Proceedings,” the Company has litigation which is still pending. For developments in these proceedings, see Notes 7 and 8 to our Consolidated Financial Statements, and Item 1, Legal Proceedings in the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, which are incorporated by reference herein.

ITEM 3
DEFAULTS UPON SENIOR SECURITIES

See Note 4 “Capital Stock” to our Consolidated Financial Statements, which is incorporated by reference herein.

ITEM 6
EXHIBITS

Exhibit Number		Description

10.1		*Letter Agreement Regarding Lignite Supply Agreement dated September 21, 2005, between Texas Genco II, L.P. and Texas Westmoreland Coal Co.

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

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

*Confidential treatment has been requested as to certain portions, which portions have been omitted and filed separately with the Securities and Exchange Commission.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	WESTMORELAND COAL COMPANY

Date: November 9, 2005	/s/ David J. Blair
	David J. Blair
	Chief Financial Officer
	(A Duly Authorized Officer)

	/s/ Diane M. Nalty
	Diane M. Nalty
	Controller
	(Principal Accounting Officer)

EXHIBIT INDEX

Exhibit Number		Description

10.1		*Letter Agreement Regarding Lignite Supply Agreement dated September 21, 2005, between Texas Genco II, L.P. and Texas Westmoreland Coal Co.

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

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

*Confidential treatment has been requested as to certain portions, which portions have been omitted and filed separately with the Securities and Exchange Commission.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

WESTMORELAND COAL (WLBAQ) Inactive 10-Q2005 Q3 Quarterly report

Content analysis

FORM 10-Q

PART I — FINANCIAL INFORMATION

ITEM 1
FINANCIAL STATEMENTS

Incentive Stock Options

Earnings per Share

Protection of the Environment

Royalty Claims and Taxes (Rosebud Mine)

Tax Assessments

McGreevey Litigation

Combined Benefit Fund

1992 UMWA Benefit Plan Surety Bond

Material Changes in Financial Condition from December 31, 2004 to September 30, 2005

Forward-Looking Disclaimer

Overview

Challenges

Critical Accounting Estimates and Related Matters

Liquidity and Capital Resources

Liquidity Outlook

Coal Markets and Rail Delivery Issues

Growth and Development

Off-Balance Sheet Arrangements

Quarter Ended September 30, 2005 Compared to Quarter Ended September 30, 2004.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

RISK FACTORS

Commodity Price Risk

Interest Rate Risk

PART II — OTHER INFORMATION

WESTMORELAND COAL (WLBAQ) Inactive 10-Q2005 Q3 Quarterly report

Content analysis

FORM 10-Q

PART I — FINANCIAL INFORMATION

ITEM 1FINANCIAL STATEMENTS

Incentive Stock Options

Earnings per Share

Protection of the Environment

Royalty Claims and Taxes (Rosebud Mine)

Tax Assessments

McGreevey Litigation

Combined Benefit Fund

1992 UMWA Benefit Plan Surety Bond

Material Changes in Financial Condition from December 31, 2004 to September 30, 2005

Forward-Looking Disclaimer

Overview

Challenges

Critical Accounting Estimates and Related Matters

Liquidity and Capital Resources

Liquidity Outlook

Coal Markets and Rail Delivery Issues

Growth and Development

Off-Balance Sheet Arrangements

Quarter Ended September 30, 2005 Compared to Quarter Ended September 30, 2004.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

RISK FACTORS

Commodity Price Risk

Interest Rate Risk

PART II — OTHER INFORMATION

ITEM 1
FINANCIAL STATEMENTS