SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2005
	OR
o	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 1-10389

WESTERN GAS RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware	84-1127613
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
1099 18th Street, Suite 1200, Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

(303) 452-5603

Registrant’s telephone number, including area code

No Changes

(Former name, former address and former fiscal year, if changed since last report).

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 o  No ý

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

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

As of December 12, 2005, there were 75,326,025 shares of the registrant’s Common Stock, par value $0.10, outstanding.

Western Gas Resources, Inc.

Form 10-Q

Table of Contents

PART I - Financial Information
Item 1.	Financial Statements
	Consolidated Balance Sheet - September 30, 2005 and December 31, 2004
	Consolidated Statement of Cash Flows - Nine Months Ended September 30, 2005 and 2004
	Consolidated Statement of Operations – Three and Nine Months Ended September 30, 2005 and 2004
	Consolidated Statement of Changes in Stockholders’ Equity - Nine Months Ended September 30, 2005
	Notes to Consolidated Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosures about Market Risk
Item 4.	Controls and Procedures
PART II - Other Information
Item 1.	Legal Proceedings
Item 6.	Exhibits
Signatures

2

PART I - FINANCIAL INFORMATION

ITEM 1.FINANCIAL STATEMENTS

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Unaudited)

(Dollars in thousands, except share data)

	September 30,			December 31,
	2005			2004
				Restated
ASSETS
Current assets:
Cash and cash equivalents	$	19,533		$	390
Trade accounts receivable, net	445,747			385,811
Margin deposits	110,723			7,939
Product inventory	129,886			94,604
Assets from price risk management activities	36,011			19,893
Deferred income taxes	48,735			—
Other	4,906			12,494
Total current assets	795,541			521,131
Property and equipment:
Gas gathering, processing and transportation	1,241,221			1,150,904
Oil and gas properties and equipment (successful efforts method)	593,859			495,314
Construction in progress	255,803			150,273
	2,090,883			1,796,491
Less: Accumulated depreciation, depletion and amortization	(650,926		)	(570,582		)
Total property and equipment, net	1,439,957			1,225,909
Other assets:
Gas purchase contracts (net of accumulated amortization of $42,093 and $40,652, respectively)	32,557			27,704
Assets from price risk management activities	4,438			249
Equity investments	40,231			35,729
Other	25,192			26,676
Total other assets	102,418			90,358
TOTAL ASSETS	$	2,337,916		$	1,837,398
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	483,161		$	400,672
Accrued expenses	83,926			60,472
Liabilities from price risk management activities	171,087			4,321
Deferred income taxes	—			5,618
Dividends payable	3,773			3,704
Total current liabilities	741,947			474,787
Long-term debt	524,500			382,000
Liabilities from price risk management activities	8,304			180
Other long-term liabilities	60,941			51,827
Deferred income taxes payable, net	282,956			243,835
Total liabilities	1,618,648			1,152,629
Stockholders’ equity:
Common stock, par value $0.10; 100,000,000 shares authorized; 75,135,201 and 74,078,733 shares issued, respectively	7,535			7,430
Treasury stock, at cost; 50,032 common shares in treasury	(788		)	(788		)
Unearned compensation	(10,207		)	—
Additional paid-in capital	419,237			392,437
Retained earnings	338,099			281,428
Accumulated other comprehensive (loss) income	(34,608		)	4,262
Total stockholders’ equity	719,268			684,769
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,337,916		$	1,837,398

The accompanying notes are an integral part of the consolidated financial statements.

3

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Nine Months Ended
	September 30,
	2005			2004
				(restated)
Reconciliation of net income to net cash provided by operating activities:
Net income	$	68,070		$	67,548
Add income items that do not affect cash:
Depreciation, depletion and amortization	92,339			67,013
Loss on sale of assets	214			1,409
Deferred income taxes	11,669			36,589
Non-cash change in fair value of derivatives	93,265			14,414
Cumulative effect of a change in accounting principle	—			(4,714		)
Compensation expense from common stock options and restricted stock	2,680			482
Other non-cash items, net	(1,480		)	1,986
Adjustments to working capital to arrive at net cash provided by operating activities:
(Increase) decrease in trade accounts receivable	(60,382		)	27,003
(Increase) in margin deposits	(102,784		)	(3,878		)
(Increase) in product inventory	(31,716		)	(37,738		)
(Increase) in other current assets	(18,752		)	(2,365		)
(Increase) decrease in other assets and liabilities, net	(865		)	205
Increase (decrease) in accounts payable	49,159			(41,076		)
Increase (decrease) in accrued expenses	48,251			(200		)
Net cash provided by operating activities	149,668			126,678
Cash flows from investing activities:
Purchases of property and equipment, including acquisitions	(301,147		)	(147,103		)
(Contributions to) distributions from equity investees	(1,427		)	1,196
Proceeds from the dispositions of property and equipment	1,856			1,022
Net cash used in investing activities	(300,718		)	(144,885		)
Cash flows from financing activities:
Proceeds from exercise of common stock options	12,134			6,760
Change in balance of outstanding checks	26,725			22,624
Borrowings under revolving credit facility	3,097,865			1,390,330
Payments on revolving credit facility	(2,945,365		)	(1,346,830		)
Borrowings of long-term debt	25,000			100,000
Payments on long-term debt	(35,000		)	(165,000		)
Debt issue costs paid	(39		)	(1,850		)
Payments for the redemption of preferred stock	—			(1,930		)
Dividends paid	(11,127		)	(9,294		)
Net cash provided by (used in) financing activities	170,193			(5,190		)
Net increase (decrease) in cash and cash equivalents	19,143			(23,397		)
Cash and cash equivalents at beginning of period	390			26,116
Cash and cash equivalents at end of period	$	19,533		$	2,719

The accompanying notes are an integral part of the consolidated financial statements.

4

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

(Dollars in thousands, except share and per share amounts)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
				Restated						Restated
	2005			2004			2005			2004
Revenues:
Sale of gas	$	821,485		$	561,157		$	2,195,791		$	1,822,348
Sale of natural gas liquids	191,559			124,464			474,009			319,400
Gathering, processing and transportation revenue	26,931			25,080			78,634			66,319
Price risk management activities	(79,850		)	(17,592		)	(88,893		)	(11,613		)
Other	1,285			570			4,002			2,743
Total revenues	961,410			693,679			2,663,543			2,199,197
Costs and expenses:
Product purchases	834,911			585,774			2,249,781			1,845,282
Plant and transportation operating expense	31,031			23,976			85,561			68,165
Oil and gas exploration and production expense	28,289			18,510			77,244			55,432
Depreciation, depletion and amortization	32,462			22,039			92,339			67,013
(Gain) loss on sale of assets	187			(230		)	214			1,409
Selling and administrative expense	15,961			10,305			46,030			37,506
(Earnings) from equity investments	(2,638		)	(1,542		)	(7,018		)	(5,244		)
Loss from early extinguishment of debt	—			—			—			10,662
Interest expense	4,764			3,912			12,317			15,065
Total costs and expenses	944,967			662,744			2,556,468			2,095,290
Income before taxes	16,443			30,935			107,075			103,907
Provision for income taxes:
Current	13,814			1,949			27,336			4,484
Deferred	(8,106		)	9,521			11,669			36,589
Total provision for income taxes	5,708			11,470			39,005			41,073
Income before cumulative effect of change in accounting principle	10,735			19,465			68,070			62,834
Cumulative effect of change in accounting principle, net of tax of $2,710	—			—			—			4,714
Net income	10,735			19,465			68,070			67,548
Preferred stock requirements	—			—			—			(835		)
Income attributable to common stock	$	10,735		$	19,465		$	68,070		$	66,713
Net income per share of common stock before cumulative effect of change in accounting principle	$	.14		$	.26		$	.92		$	.86
Cumulative effect of change in accounting principle	$	—		$	—		$	—		$	.07
Earnings per share of common stock	$	.14		$	.26		$	.92		$	.93
Weighted average shares of common stock outstanding	74,373,114			73,778,729			74,251,936			71,887,962
Income attributable to common stock – assuming dilution	$	10,735		$	19,465		$	68,070		$	66,713
Earnings per share of common stock – assuming dilution	$	.14		$	.26		$	.90		$	.91
Weighted average shares of common stock outstanding - assuming dilution	76,556,084			74,998,146			75,914,906			72,934,517

The accompanying notes are an integral part of the consolidated financial statements.

5

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(Dollars in thousands, except share amounts)

																Accumulated
		Shares														Other			Total
	Shares	of Common									Additional					Comprehensive			Stock-
	of Common	Stock	Common		Treasury			Unearned			Paid-In		Retained			Income (Loss)			holders’
	Stock	in Treasury	Stock		Stock			Compensation			Capital		Earnings			Net of Tax			Equity
Balance at December 31, 2004 (Restated)	74,078,733	50,032	$	7,430	$	(788	)	$	—		$	392,437	$	281,428		$	4,262		$	684,769
Comprehensive income:
Net income	—	—	—		—			—			—		68,070			—			68,070
Translation adjustments	—	—	—		—			—			—		—			(1,004		)	(1,004		)
Other comprehensive income
From equity investees	—	—	—		—			—			—		—			66			66
Reclassification adjustment for settled contracts	—	—	—		—			—			—		—			(827		)	(827		)
Changes in fair value of outstanding hedge positions	—	—	—		—			—			—		—			(17,729		)	(17,729		)
Change in estimated ineffectiveness	—	—	—		—			—			—		—			51			51
Fair value of new hedge positions	—	—	—		—			—			—		—			(19,427		)	(19,427		)
Change in accumulated derivative comprehensive income	—	—	—		—			—			—		—			(37,932		)	(37,932		)
Total comprehensive income, net of tax	—	—	—		—			—			—		—			—			29,200
Stock options exercised	683,078	—	68		—			—			12,066		—			—			12,134
Compensation expense from common stock options	—	—	—		—			—			1,233		—			—			1,233
Unearned compensation on restricted stock	373,390	—	37		—			(10,207		)	11,617		—			—			1,447
Tax benefit related to stock options exercised	—	—	—		—			—			1,884		—			—			1,884
Dividends declared on common stock	—	—	—		—			—			—		(11,399		)	—			(11,399		)
Balance at September 30, 2005	75,135,201	50,032	$	7,535	$	(788	)	$	(10,207	)	$	419,237	$	338,099		$	(34,608	)	$	719,268

The accompanying notes are an integral part of the consolidated financial statements.

6

WESTERN GAS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 – GENERAL

We have prepared the accompanying unaudited interim consolidated financial statements under the rules and regulations of the Securities and Exchange Commission, or SEC.  As provided by such rules and regulations, we have condensed or omitted certain information and notes normally included in annual financial statements prepared in conformity with accounting principles generally accepted in the United States of America.

The interim consolidated financial statements presented herein should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2004.  The interim consolidated financial statements as of September 30, 2005 and for the three and nine-month periods ended September 30, 2005 and 2004 included herein are unaudited but reflect, in the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to fairly state the results for such periods.  The results of operations for the three and nine-months ended September 30, 2005 are not necessarily indicative of the results of operations expected for the year ended December 31, 2005.

We have revised our classification in the Statement of Cash Flows for the nine months ended September 30, 2004, of the Change in the balance of outstanding checks, from a component of Net cash provided by operating activities to a component of Cash flows from financing activities.  This change in classification had the effect of decreasing previously reported cash provided by operating activities by $22.6 million for the nine months ended September 30, 2004, with a corresponding decrease in cash flows used in financing activities.

RESTATEMENT OF CONSOLIDATED FINANCIAL STATEMENTS

Upon adoption of FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities”, or “FAS 133”, in 2001, we analyzed our gas storage and gas transportation contracts in detail, and determined that these contracts had the characteristics of a derivative as described in FAS 133. The treatment of these contracts as derivatives has been consistently applied since adoption of FAS 133 as reflected in our consolidated financial statements.  Historically, we recorded these contracts at fair value with the changes in fair value reflected in earnings. On November 8, 2005, after the release of our third quarter 2005 results and prior to the filing of the Form 10-Q for the quarter ended September 30, 2005, it came to our attention that these contracts may not meet the definition of a derivative.  On November 21, 2005, we announced that our management and our audit committee had completed a review of the accounting treatment of our gas storage and gas transportation contracts and determined that these contracts do not meet the definition of a derivative under generally accepted accounting principles. Specifically, after a detailed review of the contracts and the market for those contracts, we determined that these contracts do not meet the definition of a derivative as: (i) the market for these types of contracts is not sufficiently liquid for us to receive fair value in a ready market and (ii) if any contract is assigned, there is no assurance that we will be relieved of our rights and obligations under that contract.  Accordingly, we have restated our audited financial statements for the years from 2001 through 2004 and our unaudited financial statements for the first two quarters of 2005 as well as all quarters in 2004 and 2003.

Historically, the non-cash mark-to-market valuation of the gas storage and gas transportation contracts which, prior to the restatement were considered to be derivatives, effectively offset non-cash mark-to-market changes to the forward derivative contracts to sell our stored or transported natural gas.  The changes in both of these mark-to-market valuations were reflected in Price risk management activities on the Consolidated statement of operations and as reported in the marketing segment.  After the adjustments to correct the prior accounting for the gas storage and gas transportation contracts, the non-cash mark-to-market of the forward derivative contract on the sale of gas will fluctuate through earnings with changes in market prices and will not be offset by a corresponding mark to market on the gas storage and transportation contracts.  As the stored or transported natural gas is sold and the forward sale derivatives are settled, we will realize the benefit of the storage and transportation transactions through earnings.

The following table summarizes the impact of the accounting adjustments necessary to correct the treatment of storage and transportation contracts on our previously reported Net income in our original Quarterly Report on Form 10-Q/A for the period ended September 30, 2004 as filed on November 23, 2004 (000s):

	Three months ending			Nine months ending
	September 30, 2004			September 30, 2004
Net income as previously reported	$	35,118		$	78,181
Accounting correction for derivatives (pre-tax)	(24,576		)	(16,577		)
Tax impact of above	8,923			5,944
Net income as restated	$	19,465		$	67,548

7

The following is a summary of the impact of these accounting adjustments on our Consolidated Balance Sheet and Consolidated Statement of Operations as previously reported in the original Quarterly Report on Form 10-Q/A for the period ended September 30, 2004 as filed on November 23, 2004.  The aforementioned restatement adjustments do not affect cash flows provided by operating activities, net cash used in investing activities and net cash provided by (used in) financing activities, although certain components of cash flows provided by operating activities have been restated.

Consolidated Balance Sheet

	December 31, 2004
	As		As
(000s)	Reported		Restated
Assets:
Current assets from price risk management activities	22,238		19,893
Long-term assets from price risk management activities	618		249
Total Assets	$	1,840,112	$	1,837,398
Liabilities and Stockholders’ equity
Current liabilities from price risk management activities	11,099		4,321
Deferred income taxes	—		5,618
Long-term liabilities from price risk management activities	417		180
Deferred income taxes payable, net	247,893		243,835
Total liabilities	1,158,084		1,152,629
Stockholders’ equity
Retained earnings	278,687		281,428
Total stockholders’ equity	682,028		684,769
Total liabilities and stockholders’ equity	$	1,840,112	$	1,837,398

Consolidated Statement of Operations

	Three Months Ended,					Nine Months Ended,
	September 30, 2004					September 30, 2004
	As		As			As		As
(000s)	Reported		Restated			Reported		Restated
Revenues:
Price risk management activities	6,984		(17,592		)	4,964		(11,613		)
Total revenues	$	718,255	$	693,679		$	2,215,774	$	2,199,197
Income before income taxes	55,511		30,935			120,484		103,907
Provision for income taxes:
Deferred	18,444		9,521			42,533		36,589
Total provision for income taxes	20,393		11,470			47,017		41,073
Income before cumulative effect of change in accounting principle	35,118		19,465			73,467		62,834
Net income	35,118		19,465			78,181		67,548
Income attributable to common stock	35,118		19,465			77,346		66,713
Earnings per share of common stock before cumulative effect of change in accounting principle	0.48		0.26			1.01		0.86
Earnings per share of common stock	0.48		0.26			1.08		0.93
Income attributable to common stock - assuming dilution	35,118		19,465			77,346		66,713
Earnings per share of common stock - assuming dilution	$	0.47	$	0.26		$	1.06	$	0.91

8

The net impact of this restatement was to adjust Net income by ($15.7) million for the three months ended September 30, 2004 and ($10.6) million for the nine months ended September 30, 2004.   The net impact of this restatement was to adjust Earnings per share of common stock – assuming dilution by ($0.21) for the three months ended September 30, 2004 and ($0.15) for the nine months ended September 30, 2004

Conversion of Preferred Stock.  In December 2003, we issued a notice of redemption for a total of 800,000 shares of our $2.625 cumulative convertible preferred stock.  The holders of these shares had the right to convert them into shares of our common stock in lieu of receiving the redemption price in cash.   In January 2004, we issued an additional 1,979,244 shares of common stock to holders who elected to convert their shares and paid $672,000 in cash proceeds to complete this redemption.   In March 2004, we issued an additional notice of redemption for the remaining 1,260,000 shares of our $2.625 cumulative convertible preferred stock.  In April 2004, we issued an additional 3,113,582 shares of common stock to holders who elected to convert their shares and paid $391,000 in cash proceeds to complete this redemption.

Earnings Per Share of Common Stock.  Earnings per share of common stock are computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding.  In addition, earnings per share of common stock - assuming dilution is computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding as adjusted for potential common shares.  Income attributable to common stock is net income less preferred stock dividends.   The following table presents the dividends declared by us for each class of our outstanding equity securities (dollars in thousands, except per share amounts):

	Quarter Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Common Stock	$	3,774	$	3,697	$	11,399	$	9,146
Preferred Stock	—		—		—		835
Total Dividends Declared	$	3,774	$	3,697	$	11,399	$	9,981
Dividends Declared Per Share:
Common Stock	$	0.05	$	0.05	$	0.15	$	0.15
Preferred Stock	—		—		—		$	.66

Common stock options, unvested restricted stock granted and, until the final conversion or redemption in April 2004, our $2.625 cumulative convertible preferred stock are potential common shares.  The following is a reconciliation of the weighted average shares of common stock outstanding to the weighted average common shares outstanding – assuming dilution.

	Quarter Ended September 30,		Nine Months Ended September 30,
	2005	2004	2005	2004
Weighted average shares of common stock outstanding	74,373,114	73,778,729	74,251,936	71,887,962
Potential common shares from:
Common stock options and restricted stock	2,182,970	1,219,417	1,662,970	1,046,555
$ 2.625 Cumulative Convertible Preferred Stock	—	—	—	—
Weighted average shares of common stock outstanding - assuming dilution	76,556,084	74,998,146	75,914,906	72,934,517

The calculation of fully diluted earnings per share reflects potential common shares, if dilutive, and any related preferred dividends.

Accumulated Other Comprehensive Income.  Included in Accumulated other comprehensive (loss) income at September 30, 2005 were unrealized losses of $37.5 million, which is net of $21.6 million of deferred taxes,  from the fair value of derivatives designated as cash flow hedges and unrealized losses of $2.9 million, which is net of $1.0 million of deferred taxes, as a result of cumulative foreign currency translation adjustments.

The gains and losses currently reflected in Accumulated other comprehensive (loss) income will be reclassified to earnings as the hedged gas or NGLs are sold.  Based on the prices for our products on September 30, 2005, approximately $37.5 million of losses in Accumulated other comprehensive (loss) income will be reclassified to earnings, of which $17.9 million will be reclassified in the remainder of 2005.

9

Revenue Recognition.   In the Gas Gathering, Processing and Treating segment, we recognize revenue for our services at the time the service is performed. We record revenue from our gas and natural gas liquid, or NGL, marketing activities, including sales of our equity production, upon transfer of title.  In accordance with Emerging Issues Task Force, or EITF, 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes as Defined in Issue No. 02-3”, we record revenue on our physical gas and NGL marketing activities on a gross basis versus sales net of purchases basis because we obtain title to all the gas and NGLs that we buy including third-party purchases; we bear the risk of loss and credit exposure on these transactions; and it is our intention upon entering these contracts to take physical delivery of the product.  Gas imbalances on our production are accounted for using the sales method.  Gas imbalances on our production at September 30, 2005 and 2004 are immaterial.  For our marketing activities, we utilize mark-to-market accounting for our derivatives.  In our Transportation segment, we realize revenue on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes delivered into the pipeline.

Depreciation, Depletion and Amortization of Oil and Gas Properties.  We follow the successful efforts method of accounting for oil and gas exploration and production activities.  Effective January 1, 2004, we redefined the asset groupings for the calculation of depreciation and depletion on our oil and gas properties from a well-by-well basis to a field-wide basis for each of the Jonah, Pinedale and Sand Wash fields and to a grouping of all wells drilled into related coal seams for the Powder River Basin.  The cumulative effect of the change in depreciation and depletion methodology for the nine months ended September 30, 2004 was a benefit of $4.7 million, net of tax, or $0.07 per share of common stock - assuming dilution, and is presented in the Consolidated Statement of Operations under the caption Cumulative effect of change in accounting principle, net of tax.

Price Reporting to Gas Trade Publications.   In 2003, we learned that several employees in our marketing department furnished inaccurate information regarding natural gas transactions to energy publications, which compile and report energy index prices.  In July 2004, we reached a settlement of this matter with the Commodities Futures Trading Commission, or CFTC.  In conjunction with this settlement, we paid a civil penalty of $7.0 million, and as a result our earnings per common share in the nine months ended September 30, 2004 were reduced by $0.09.   In the second quarter of 2005, we reached a settlement of a related claim with a private litigant for $3.8 million after-tax, or $0.05 per common share for the nine months ended September 30, 2005.  For additional information on this related claim, see Legal Proceedings in these Notes to Consolidated Financial Statements.

Income Taxes.  The Total provision for income taxes, as a percentage of Income before taxes, was approximately 34.7% and 36.4%, respectively, during the quarter and nine months ended September 30, 2005 as compared to 37.1% and 39.5%, respectively, in the same periods of 2004.  The decrease in the percentage of income taxes in the nine-month periods is primarily due to the civil penalty paid to the CFTC in 2004, which was non-deductible for tax purposes.

Supplementary Cash Flow Information.  Interest paid was $18.4 million and  $17.6 million for the nine months ended September 30, 2005 and 2004, respectively. A total of $20.2 million and $7.7 million was paid in income taxes in the nine months ended September 30, 2005 and 2004, respectively.  Asset retirement obligation assets of $9.4 million were recorded for capitalized assets and asset retirement obligation liabilities of $11.0 million were recorded for the nine months ended September 30, 2005.  The asset retirement and associated obligations are non-cash transactions for presentation on the Consolidated Statement of Cash Flows.

NOTE 2 - DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES.

A net loss was recognized in earnings through Sale of gas and Sale of natural gas liquids during the three and nine months ended September 30, 2005 from hedging activities of $2.7 million and $2.9 million, respectively.  Also during these periods we recognized a loss from hedge ineffectiveness of $30,000 and $208,000, respectively, through Price risk management activities.   At September 30, 2005, we had margin deposits posted of $110.7 million, which is included in Trade accounts receivable, net.  The amount of margin posted has decreased to $53.8 million on November 7, 2005, and we will receive these margin deposits back as these positions expire during the fourth quarter of 2005 and the first quarter of 2006 or as commodity prices decline.

10

NOTE 3 - STOCK COMPENSATION.

As permitted under SFAS No. 123, “Accounting for Stock-Based Compensation”, we have elected to continue to measure compensation costs for stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.”  We have complied with the pro forma disclosure requirements of SFAS No. 123 as required under the pronouncement.  We realize an income tax benefit from the exercise of non-qualified stock options related to the amount by which the market price at the date of exercise exceeds the option price.  This tax benefit is credited to Additional paid-in capital.

In the first nine months of 2005, we granted 933,000 options to purchase our common stock at the market based on the average closing price for the ten days prior to grant, and 374,000 shares of restricted common stock to our employees.  In conjunction with the grant of restricted common stock, we will record as compensation expense over the three-year vesting period, the value of the restricted common stock on the date of grant.  Accordingly, we recorded compensation expense of $984,000 and $1.4 million, respectively, related to our restricted stock in the third quarter and nine months ended September 30, 2005.

SFAS No. 123 requires pro forma disclosures for each quarter that a Statement of Operations is presented.  The following is a summary of the options to purchase our common stock granted during the quarters and nine months ended September 30, 2005 and 2004, respectively.

	Quarter Ended September 30,		Nine Months Ended September 30,
	2005	2004	2005	2004
1999 Plan	—	141,000	—	141,000
2002 Plan	17,000	846,000	154,000	921,000
2002 Directors’ Plan	—	—	32,000	32,000
2005 Plan	—	—	747,000	—
Total options granted	17,000	987,000	933,000	1,094,000

The following is a summary of the weighted average fair value per share of the options granted during the quarters and nine months ended September 30, 2005 and 2004, respectively.

	Quarter Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
1999 Plan	—		$	13.12	—		$	13.12
2002 Plan	$	18.20	$	13.09	$	15.36	$	13.09
2002 Directors’ Plan	—		—		$	14.79	$	12.13
2005 Plan	—		—		$	13.25	—

These values for the options granted during the quarter and nine months ended September 30, 2005 were estimated using the Black-Scholes option-pricing model with the following assumptions:

	Quarter Ended September 30, 2005					Nine Months Ended September 30, 2005
	2002 Plan			2002 Directors’ Plan	2005 Plan	2002 Plan			2002 Directors’ Plan			2005 Plan
Risk-free interest rate	4.52		%	—	—	4.37		%	4.38		%	4.27		%
Expected life (in years)	7			—	—	7			7			7
Expected volatility	36		%	—	—	37		%	37		%	37		%
Expected dividends (quarterly)	$	0.05		—	—	$	0.05		$	0.05		$	0.05

11

Under SFAS No. 123, the fair market value of the options at the grant date is amortized over the appropriate vesting period for purposes of calculating compensation expense.  If we had recorded compensation expense for our grants under our stock-based compensation plans consistent with the fair value method under this pronouncement, our net income, income attributable to common stock, earnings per share of common stock and earnings per share of common stock - assuming dilution would approximate the pro forma amounts below (dollars in thousands, except per share amounts):

	Quarter Ended September 30,
					Restated		Restated
	2005		2005		2004		2004
	As Reported		Pro Forma		As Reported		Pro Forma
Net income	$	10,735	$	8,731	$	19,465	$	17,758
Net income attributable to common stock	10,735		8,731		19,465		17,758
Earnings per share of common stock	0.14		0.12		0.26		0.24
Earnings per share of common stock - assuming dilution	0.14		0.11		0.26		0.24
Stock-based employee compensation cost, net of related tax effects, included in net income	311		—		4		—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	2,378	$	—	$	1,711

	Nine Months Ended September 30,
					Restated		Restated
	2005		2005		2004		2004
	As Reported		Pro Forma		As Reported		Pro Forma
Net income	$	68,070	$	61,820	$	67,548	$	63,533
Net income attributable to common stock	68,070		61,820		66,713		62,698
Earnings per share of common stock	0.92		0.83		0.93		0.87
Earnings per share of common stock –assuming dilution	0.90		0.82		0.91		0.87
Stock-based employee compensation cost, net of related tax effects, included in net income	614		—		305		—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	6,864	$	—	$	4,320

NOTE 4 - SEGMENT REPORTING.

We operate in four principal business segments, as follows:  Gas Gathering, Processing and Treating; Exploration and Production; Marketing; and Transportation.  Management separately monitors these segments for performance against our internal forecast, and these segments are consistent with our internal financial reporting package.  These segments have been identified based upon the differing products and services, regulatory environment and the expertise required for these operations.

Gas Gathering, Processing and Treating.  In this segment, we connect producers’ wells (including those of our Exploration and Production segment) to our gathering systems for delivery to our processing or treating plants, process the natural gas to extract NGLs and treat the natural gas in order to meet pipeline specifications.  In some areas, where no processing is required, we gather and compress producers’ gas and deliver it to pipelines for further delivery to market.  Except for volumes taken in kind by our producers, the Marketing segment sells the residue gas and NGLs extracted at most of our facilities.

Substantially all gas flowing through our gathering, processing and treating facilities is supplied under three types of contracts providing for the purchase, treating or processing of natural gas for periods ranging from one month to twenty years or in some cases for the life of the oil and gas lease.  Approximately 74% of our plant facilities’ gross margin, or revenues at the plant less product purchases, for the month of September 2005 was pursuant to percentage-of-proceeds agreements in which we are typically responsible for the marketing of the gas and NGLs.  Under these agreements, we pay producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs.

Approximately 16% of our plant facilities’ gross margin for the month of September 2005 was pursuant to contracts that are primarily fee-based from which we receive a set fee for each Mcf of gas gathered and/or processed. This type of contract

12

provides us with a steady revenue stream that is not dependent on commodity prices, except to the extent that low prices may cause a producer to delay drilling.

Approximately 10% of our plant facilities’ gross margin for the month of September 2005 was pursuant to contracts with “keepwhole” arrangements, the majority of which also include fees for gathering, compression or treating services, or wellhead purchase contracts.  Under keepwhole contracts, we retain the NGLs recovered by the processing facility and keep the producers whole by returning to the producers at the tailgate of the plant an amount of residue gas equal on a Btu basis to the natural gas received at the plant inlet.  The “keepwhole” component of the contracts permits us to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream.  However, we are adversely affected when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream.

Exploration and Production.  The activities of the Exploration and Production segment include the exploration and development of gas properties primarily in the Rocky Mountain area and other unconventional gas plays, including those where our gathering and/or processing facilities are located.  The Marketing segment sells the majority of the production from these properties and remits to the Exploration and Production segment all of the proceeds from the sales of its gas, net of transportation charges.

Exploratory lease rentals and geological and geophysical costs are charged to expense as incurred.  Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proven reserves.  A determination as to whether a well has found proven reserves is made shortly after drilling is completed. The determination is based upon a process that relies on interpretations of available geological, geophysical, and engineering data.  If an exploratory well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made.  If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether proven reserves have been found only as long as: i) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made, and ii) the drilling of additional exploratory wells is under way or firmly planned for the near future. If the drilling of additional exploratory wells in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired, and its costs are charged to expense.

The following table reflects the net changes in capitalized exploratory well costs during the nine months ended September 30, 2005 (dollars in thousands).

	Nine Months Ended September 30, 2005
Beginning balance at December 31, 2004	$	48,546
Additions to capitalized exploratory well costs pending the determination of proven reserves	60,059
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves	(11,239		)
Capitalized exploratory well costs charged to expense	(1,597		)
Ending balance at September 30, 2005	$	95,769

Substantially all of our exploratory wells that have been capitalized for a period greater than one year are located in the Powder River Basin.  In this basin, we drill wells into various coal seams.  In order to produce gas from the coal seams, a period of dewatering lasting from a few to twenty-four months, or in some cases longer, is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering, and to classify the reserves as proven.  In order to accelerate the dewatering time, we drill additional exploratory wells in these areas.

Marketing.  Our Marketing segment buys and sells gas and NGLs in the United States and Canada from and to a variety of customers.  Revenues in this segment are sensitive to changes in the market prices of the underlying commodities.  The marketing of products purchased from third parties typically results in low sales margins relative to the sales price.  We sell our products under agreements with varying terms and conditions in order to match seasonal and other changes in demand.  Also included in this segment are our Canadian marketing operations, which are conducted through our wholly owned subsidiary WGR Canada, Inc. and which are immaterial for separate presentation.

Transportation.  The Transportation segment reflects the operations of Western’s MIGC, Inc. and MGTC, Inc. pipelines.   The majority of the revenue presented in this segment is derived from transportation of residue gas for our Marketing

13

segment and other third parties.  The Transportation segments’ firm capacity contracts range in duration from fifteen months to approximately thirteen years.

Segment Information. The following tables set forth our segment information as of and for the quarter and nine months ended September 30, 2005 and 2004 (dollars in thousands).  Due to our integrated operations, the use of allocations in the determination of business segment information is necessary.  Inter-segment revenues are valued at prices comparable to those of unaffiliated customers.

Quarter Ended September 30, 2005

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Other			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	1,297		$	2,643		$	816,395		$	293		$	—		$	—		$	820,628
Sale of natural gas liquids	239			—			194,861			—			—			—			195,100
Equity hedges:
Residue	185			672			—			—			—			—			857
Liquids	(3,541		)	—			—			—			—			—			(3,541		)
Gathering, processing and transportation revenue	25,278			—			—			1,653			—			—			26,931
Total revenues from unaffiliated customers:	23,458			3,315			1,011,256			1,946			—			—			1,039,975
Inter-segment sales	370,775			102,890			21,235			3,493			9			(498,402		)	—
Price risk management activities	44			4,440			(84,334		)	—			—			—			(79,850		)
Interest Income	0			6			2			1			14,232			(14,241		)	—
Other, net	968			8			(6		)	—			315			—			1,285
Total revenues	395,245			110,659			948,153			5,440			14,556			(512,643		)	961,410
Product purchases	297,526			916			1,023,022			937			0			(487,490		)	834,911
Plant and transportation operating expense	30,609			25			0			1,503			—			(1,106		)	31,031
Oil and gas exploration and production expense	0			38,103			—			—			—			(9,814		)	28,289
(Earnings) from equity investments	(2,638		)	—			—			—			—			—			(2,638		)
Segment operating profit	69,748			71,615			(74,869		)	3,000			14,556			(14,233		)	69,817
Depreciation, depletion and amortization	11,646			18,357			35			497			1,927						32,462
Selling and administrative expense	—			—			—			—			15,970			(9		)	15,961
(Gain) loss from sale of assets	(29		)	0			—			216			—			—			187
Interest expense	—			(3		)	330			(233		)	18,911			(14,241		)	4,764
Income before tax	$	58,131		$	53,261		$	(75,234	)	$	2,520		$	(22,252	)	$	17		$	16,443
Identifiable assets:
Equity investments	$	34,957		—			—			$	877		$	935,443		$	(931,046	)	$	40,231
Property and equipment	762,999			$	579,021		$	12		38,081			59,844			—			1,439,957
Other allocated assets	10,259			21,802			259,445			39,027			609,676			(82,481		)	857,728
Total identifiable assets	$	808,215		$	600,823		$	259,457		$	77,985		$	1,604,963		$	(1,013,527	)	$	2,337,916

14

Quarter Ended September 30, 2004

(Restated)

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Other			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	878		$	2,375		$	557,315		$	282		$	—		$	—		$	560,850
Sale of natural gas liquids	(559		)	—			130,057			—			—			—			129,498
Equity hedges:
Residue	(16		)	324			—			—			—			—			308
Liquids	(5,035		)	—			—			—			—			—			(5,035		)
Gathering, processing and transportation revenue	23,469			—			—			1,611			—			—			25,080
Total revenues from unaffiliated customers:	18,737			2,699			687,372			1,893			—			—			710,701
Inter-segment sales	257,310			62,547			12,601			3,560			—			(336,018		)	—
Price risk management activities	(30		)	—			(17,562		)	—			—			—			(17,592		)
Interest Income	—			1			—			1			5,460			(5,462		)	—
Other, net	112			9			(42		)	2			489			—			570
Total revenues	276,129			65,256			682,369			5,456			5,949			(341,480		)	693,679
Product purchases	210,347			636			700,209			867			—			(326,285		)	585,774
Plant and transportation operating expense	22,976			7			4			1,848			—			(859		)	23,976
Oil and gas exploration and production expense	—			27,468			—			—			—			(8,958		)	18,510
(Earnings) from equity investments	(1,542		)	—			—			—			—			—			(1,542		)
Segment operating profit	44,348			37,145			(17,844		)	2,741			5,949			(5,378		)	66,961
Depreciation, depletion and amortization	9,769			10,245			35			415			1,575			—			22,039
Selling and administrative expense	—			—			—			—			10,315			(10		)	10,305
(Gain) loss from sale of assets	(20		)	(218		)	—			—			8			—			(230		)
Interest expense	—			(1		)	115			(91		)	9,351			(5,462		)	3,912
Income before tax	$	34,599		$	27,119		$	(17,994	)	$	2,417		$	(15,300	)	$	94		$	30,935
Identifiable assets:
Equity investments	$	38,021		$	—		$	—		$	3,822		$	698,127		$	(701,949	)	$	38,021
Property and equipment	641,898			354,044			18			37,226			52,986			—			1,086,172
Other allocated assets	6,214			5,059			36,228			24,598			385,054			(52,446		)	404,707
Total identifiable assets	$	686,133		$	359,103		$	36,246		$	65,646		$	1,136,167		$	(754,395	)	$	1,528,900

15

Nine months ended September 30, 2005

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Other			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	2,026		$	9,718		$	2,179,964		$	1,447		$	—		$	—		$	2,193,155
Sale of natural gas liquids	290			—			479,209			—			—			—			479,499
Equity hedges:
Residue	360			2,276			—			—			—			—			2,636
Liquids	(5,490		)	—			—			—			—			—			(5,490		)
Gathering, processing and transportation revenue	73,724			(162		)	—			5,072			—			—			78,634
Total revenues from unaffiliated customers:	70,910			11,832			2,659,173			6,519			—			—			2,748,434
Inter-segment sales	946,955			250,533			63,879			10,288			29			(1,271,684		)	—
Price risk management activities	(81		)	4,440			(93,252		)	—			—			—			(88,893		)
Interest Income	—			14			20			1			36,169			(36,204		)	—
Other, net	3,161			128			(3		)	—			716			—			4,002
Total revenues	1,020,945			266,947			2,629,817			16,808			36,914			(1,307,888		)	2,663,543
Product purchases	773,510			3,280			2,711,076			2,571			—			(1,240,656		)	2,249,781
Plant and transportation operating expense	83,100			193			146			4,967			—			(2,845		)	85,561
Oil and gas exploration and production expense	—			105,397			—			—			—			(28,153		)	77,244
(Earnings) from equity investments	(7,018		)	—			—			—			—			—			(7,018		)
Segment operating profit	171,353			158,077			(81,405		)	9,270			36,914			(36,234		)	257,975
Depreciation, depletion and amortization	34,518			50,885			106			1,336			5,494			—			92,339
Selling and administrative expense	—			—			—			—			46,059			(29		)	46,030
(Gain) loss from sale of assets	(211		)	61			—			364			—			—			214
Interest expense	5			1			919			(581		)	48,177			(36,204		)	12,317
Income before tax	$	137,041		$	107,130		$	(82,430	)	$	8,151		$	(62,816	)	$	(1	)	$	107,075
Identifiable assets:
Equity investments	$	34,957		—			—			$	877		$	935,443		$	(931,046	)	$	40,231
Property and equipment	762,999			$	579,021		$	12		38,081			59,844			—			1,439,957
Other allocated assets	10,259			21,802			259,445			39,027			609,676			(82,481		)	857,728
Total identifiable assets	$	808,215		$	600,823		$	259,457		$	77,985		$	1,604,963		$	(1,013,527	)	$	2,337,916

16

Nine months ended September 30, 2004

(Restated)

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Other			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	2,767		$	6,158		$	1,808,586		$	1,147		$	—		$	—		$	1,818,658
Sale of natural gas liquids	(556		)	—			329,968			—			—			—			329,412
Equity hedges:
Residue	249			3,441			—			—			—			—			3,690
Liquids	(10,012		)	—			—			—			—			—			(10,012		)
Gathering, processing and transportation revenue	61,311			—			—			5,008			—			—			66,319
Total revenues from unaffiliated customers:	53,759			9,599			2,138,554			6,155			—			—			2,208,067
Inter-segment sales	766,734			178,903			40,202			10,705			—			(996,544		)	—
Price risk management activities	(56		)	—			(11,557		)	—			—			—			(11,613		)
Interest Income	—			4			—			1			13,802			(13,807		)	—
Other, net	924			10			(37		)	49			1,797			—			2,743
Total revenues	821,361			188,516			2,167,162			16,910			15,599			(1,010,351		)	2,199,197
Product purchases	638,467			1,568			2,170,903			3,822			—			(969,478		)	1,845,282
Plant and transportation operating expense	65,264			77			(168		)	5,420			—			(2,428		)	68,165
Oil and gas exploration and production expense	—			80,053			—			—			—			(24,621		)	55,432
(Earnings) from equity investments	(5,244		)																(5,244		)
Segment operating profit	122,874			106,818			(3,573		)	7,668			15,599			(13,824		)	235,562
Depreciation, depletion and amortization	27,981			32,111			87			1,239			5,595			—			67,013
Selling and administrative expense	—			—			—			—			37,542			(36		)	37,506
(Gain) loss from sale of assets	224			(414		)	—			—			300			1,299			1,409
Loss from early extinguishment of debt	—			—			—			—			10,662			—			10,662
Interest expense	—			41			292			(224		)	28,763			(13,807		)	15,065
Income before tax	$	94,669		$	75,080		$	(3,952	)	$	6,653		$	(67,263	)	$	(1,280	)	$	103,907
Identifiable assets:
Equity investments	38,021			—			—			3,822			698,127			(701,949		)	38,021
Property and equipment	641,898			354,044			18			37,226			52,986			—			1,086,172
Other allocated assets	6,214			5,059			36,228			24,598			385,054			(52,446		)	404,707
Total identifiable assets	686,133			359,103			36,246			65,646			1,136,167			(754,395		)	1,528,900

NOTE 5 - LEGAL PROCEEDINGS.

Gracey et al. v. Western Gas Resources, Inc. et al., United States District Court, Southern District of New York, Case No. 
03-CV-6186 (vm) (S.D.N.Y.).  On September 17, 2004, the plaintiffs, traders of natural gas futures contracts on NYMEX, filed this action on behalf of themselves and a putative class of other similarly situated plaintiffs.  In the complaint, the plaintiffs claim that we manipulated the prices of natural gas futures on the NYMEX in violation of the Commodity Exchange Act, or CEA, by reporting allegedly “inaccurate, misleading and false trading information” to trade publications that compile and publish indices of natural gas spot prices.  In addition, the complaint asserts that we aided and abetted the alleged CEA violations of others.  In June 2005, while admitting no liability, we entered into a Stipulation and Agreement of Settlement with the plaintiffs for $5.9 million and accrued the liability in the second quarter of 2005.  This settlement was approved by the court and was paid in October 2005.

United States of America and ex rel. Jack J. Grynberg v. Western Gas Resources, Inc., et al., United States District Court, District of Colorado, Civil Action No. 97-D-1427.  We, along with over 300 other natural gas companies, are defendants in litigation filed on September 30, 1997, in 72 separate actions filed by Mr. Grynberg on behalf of the federal government.  The allegations made by Mr. Grynberg are that established gas measurement and royalty calculation practices improperly deprived the federal government of appropriate natural gas royalties and violate 31U.S.C. 3729(a)(7) of the False

17

Claims Act.  The cases have been consolidated to the United States District Court for the District of Wyoming.  Discovery on the jurisdictional issues is being completed to determine if this matter qualifies as a qui tam, or class, action.  The defendants’ joint Motion to Dismiss was argued before a special master on March 17 and 18, 2005 and, as a result thereof, the special master has recommended to the court that claims against several of the defendants, including Western, be dismissed. The recommendation is pending before the court.

J.P. Morgan Trust Company, National Association, in its Capacity as Trustee of the FI Liquidating Trust v. Oneok Inc. et al., United States District Court, for the District of Kansas, Case No. 05-2389CM.  On October 17, 2005, the plaintiff, in its capacity as the liquidating trustee of the successor in interest to Farmland Industries, Inc., filed an amended complaint, joining us and other defendants to this action.  The complaint claims that the defendants violated the Kansas Restraint of Trade Act by reporting allegedly “misleading or knowingly inaccurate reports concerning trade information” to trade publications that compile and publish indices of natural gas prices for natural gas trading hubs throughout the United States.  The complaint asserts that these alleged activities had the effect of increasing prices charged by the defendants for natural gas and preventing full and free competition. The plaintiff seeks to recover damages in the amount of the full consideration of its purchases of natural gas during the time period from January 1, 2000 through December 31, 2001, together with its costs of litigation including attorney’s fees.  We believe that the claims are without merit and intend to vigorously contest the allegations in this case.

Learjet, Inc., Cross Oil Refining & Marketing, Inc. Topeka Unified School District 501, on Behalf of Themselves and All Other Similarly Situated Direct Purchasers of Natural Gas in the State of Kansas v. Oneok, Inc. et al, In the District Court of Wyandotte County, Kansas, Civil Action No. 05-CV-1500.  On November 4, 2005, the plaintiffs, on behalf of themselves and all others similarly situated, filed an amended Petition for Damages, joining us and other defendants to this action.  The Petition claims that the defendants violated the Kansas Restraint of Trade Act by reporting allegedly “misleading or knowingly inaccurate reports concerning trade information” to trade publications that compile and publish indices of natural gas prices for natural gas trading hubs throughout the United States.  The complaint asserts that the allegedly anticompetitive effect of the defendant’s actions was to artificially inflate the prices paid by the plaintiffs for natural gas. The plaintiffs are bringing the action as a class action on behalf of all persons and entities in Kansas who made direct purchases of natural gas, for their own use and or consumption, during the time period from January 1, 2000 through October 31, 2002.  The plaintiffs are seeking judgment for the full consideration of their purchases of natural gas purchased during such time period, together with costs of litigation including attorney’s fees.  We believe that the claims are without merit and intend to vigorously contest the allegations in this case.

Other Litigation. We are involved in various other litigation and administrative proceedings arising in the normal course of business.  In the opinion of our management, any liabilities that may result from these claims will not, individually or in the aggregate, have a material adverse effect on our financial position, results of operations or cash flow.

NOTE 6 - RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS.

We continually monitor and revise our accounting policies as new rules are issued.  At this time, there are several new accounting pronouncements that have recently been issued, but not yet adopted, which will have an impact on our accounting when they become effective.

SFAS No. 123(R).   SFAS No. 123(Revised 2004), “Share Based Payment”, or SFAS No. 123(R),was issued in December 2004 and now must be adopted for annual periods that begin after June 15, 2005.  This pronouncement requires companies to expense the fair value of employee stock options and other forms of stock based compensation.  We intend to adopt this pronouncement in the first quarter of 2006.  Currently, we are complying with the pro forma disclosure requirements of SFAS No. 123, “Accounting for Stock Based Compensation.   SFAS 123(R) provides for various methods of adoption.  We have not yet determined which method of adoption we will utilize or the effect this statement will have on our financial position, results of operations or cash flows.

SFAS No. 151.    SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4” was issued in November 2004 and is effective for the Company for inventory costs incurred in fiscal years beginning after June 15, 2005, and will be applied prospectively.  SFAS No. 151 amends APB Opinion No. 43, Chapter 4, “Inventory Pricing” to clarify the accounting for abnormal amounts of costs and the allocation of fixed production overheads.  We will adopt SFAS No. 151 on January 1, 2006 and believe that the adoption of this pronouncement will not affect our results of operations, financial position or cash flows.

SFAS No. 153.    SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29” was issued in December 2004 and is effective for the Company for nonmonetary asset exchanges occurring in fiscal periods

18

beginning after June 15, 2005.  SFAS No. 153 amends APB Opinion No. 29, Accounting for Nonmonetary Transactions.  The guidance in APB Opinion No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged but included certain exceptions to that principle.  SFAS No. 153 amends APB Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance.  A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange.  We adopted SFAS No. 153 on July 1, 2005, and the adoption of this pronouncement had no effect on our results of operations, financial position or cash flows.

EITF No. 04-13.   At its September 2005 meeting, the Emerging Issues Task Force, or EITF, of the FASB approved Issue No. 
04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.”  This Issue addresses the question of when it is appropriate to measure non-monetary purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold.  EITF 04-13 requires two or more exchange transactions involving inventory with the same counterparty that are entered into in contemplation of one another should be combined for the purposes of evaluating the effect of APB Opinion No. 29, “Accounting for Nonmonetary Transactions”.

In order to minimize transportation costs or make product available at a location of our customer’s preference, from time to time, we will enter into arrangements to buy product from a party at one location and arrange to sell a like quantity of product to this same party at another location.  In accordance with EITF 04-13, these transactions will be required to be reported on a sales net of purchases basis.  This EITF is effective for transactions entered into or modified after March 15, 2006.  To the extent transactions are required to be netted, it will result in a reduction of revenues and costs by an equal amount, but will have no impact on net income or cash flows.

In accordance with EITF 03-11, we record revenue on these transactions on a gross basis versus sales net of purchases basis because we obtain title to the product that we buy, bear the risk of loss, credit and performance exposure on these transactions, and take physical delivery of the product.  For the quarters ended September 30, 2005 and 2004, we recorded revenues of $42.3 million and $18.4 million, respectively, and product purchases of $41.5 million and $19.2 million, respectively, for transactions which were entered into concurrently and with the intent to buy and sell like quantities with the same counterparty at different locations and at market prices at those locations.  For the nine months ended September 30, 2005 and 2004, we recorded revenues of $105.6 million and $67.8 million, respectively, and product purchases of $99.0 million and $63.7 million, respectively, for these types of transactions.

FASB Interpretation No. 47.  FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143”, or FIN 47, was issued in March 2005 and is effective in fiscal periods ending after December 15, 2005.  FIN 47 clarifies the term “conditional asset retirement obligation” as used in FASB Statement 143, “Accounting for Asset Retirement Obligations”.  Conditional asset retirement obligations as used in FASB Statement 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform an asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. When sufficient information exists, uncertainty about the timing and (or) method of settlement should be factored into the measurement of the liability. We will adopt this interpretation as required and do not expect the pronouncement to have a material impact on our results of operation, financial position or cash flows.

SFAS No. 154.   In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of Accounting Principles Board Opinion (APB) No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements.” This Statement requires retrospective application to prior periods’ financial statements of a change in accounting principle. It applies both to voluntary changes and to changes required by an accounting pronouncement if the pronouncement does not include specific transition provisions. APB 20 previously required that most voluntary changes in accounting principles be recognized by recording the cumulative effect of a change in accounting principle. SFAS 154 is effective for fiscal years beginning after December 15, 2005. We plan to adopt this statement on January 1, 2006 and it is not expected to have a material effect on the financial statements upon adoption.

19

NOTE 7 – SUBSEQUENT EVENT- AMENDMENT AND RESTATEMENT OF REVOLVING CREDIT FACILITY.

In November 2005, we amended and restated our existing revolving credit facility.  The amended and restated facility is a five-year, $700 million revolving credit facility maturing in November 2010.  Loans made under this facility are secured by a pledge of the capital stock of our significant subsidiaries, and these subsidiaries also guarantee the borrowings under the facility.  Under the credit facility, we are subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55% and maintaining a ratio of EBITDA, as defined in the credit facility, to interest over the last four quarters in excess of 3.0 to 1.0.  The credit facility ranks equally with borrowings under our master shelf agreement with The Prudential Insurance Company.  The borrowings under this credit facility bear interest at Eurodollar rates or a base rate, as requested by us, plus an applicable percentage based on our debt to capitalization ratio.  The base rate is the agent’s published prime rate.  We also pay a quarterly commitment fee on undrawn amounts ranging between 0.10% and 0.30%, depending on our debt to capitalization ratio.  This fee is paid on unused amounts of the commitment.  As of November 30, 2005, the interest rate payable on borrowings under this facility was approximately 5.18% per year.

20

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

The following discussion and analysis relates to factors that have affected our consolidated financial condition and results of operations for the three and nine months ended September 30, 2005 and 2004.  Certain prior year amounts have been reclassified to conform to the presentation used in 2005.  You should also refer to our interim consolidated financial statements and notes thereto included elsewhere in this document.  This section, as well as other sections in this Form 10-Q, contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by the use of forward-looking terminology, such as “may,” “intend,” “will,” “expect,” “anticipate,” “estimate,” or “continue” or the negative thereof or other variations thereon or comparable terminology.  In addition to the important factors referred to herein, numerous factors affecting the gas processing industry generally and in the specific markets for gas and NGLs in which we operate could cause actual results to differ materially from those in such forward-looking statements.

Restatement of Previously Issued Financial Statements

Upon adoption of FAS 133 in 2001, we analyzed our gas storage and gas transportation contracts in detail, and determined that these contracts had the characteristics of a derivative under generally accepted accounting principles.  On November 21, 2005, we announced that our management and our audit committee have completed a review of the accounting treatment of our gas storage and gas transportation contracts and determined that these contracts do not meet the definition of a derivative.  Specifically, after a detailed review of the contracts and the market for those contracts, we subsequently determined that these contracts do not meet the definition of a derivative as: (i) the market for these types of contracts is not sufficiently liquid for us to receive fair value in a ready market and (ii) if any contract is assigned, there is no assurance that we will be relieved of our rights and obligations under that contract.

Historically, the non-cash mark-to-market valuation of the gas storage and transportation contracts which, prior to the restatement, were considered to be derivatives effectively offset non-cash mark-to-market changes to the future sale derivatives for our stored or transported natural gas.  Without this offsetting valuation, the non-cash mark-to-market of the future sale derivative contracts on the sale of gas will fluctuate through earnings with changes in market prices and will not be offset by a corresponding mark to market on the gas storage and transportation contracts which are no longer derivatives.  As the stored or transported natural gas is sold and the forward derivatives are settled, we will realize the benefit of the storage and transportation transactions through earnings.

The effect of the restatement for each of the three and nine months ending September 30, 2004 is as follows. Additional information on the nature and impact of these accounting corrections is provided in the Notes to Consolidated Financial Statements included elsewhere in this Form 10-Q (amounts in thousands, except per share amounts):

	Three months ending				Nine months ending
	September 30, 2004				September 30, 2004
	As		As		As		As
	Reported		Restated		Reported		Restated
Total revenues	$	718,255	$	693,679	$	2,215,774	$	2,199,197
Income before taxes	55,511		30,935		120,484		103,907
Net income	35,118		19,465		78,181		67,548
Earnings per share-assuming dilution	0.47		0.26		1.06		0.91
Cash flow from operating activities	$	38,546	$	38,546	$	126,678	$	126,678

COMPANY OVERVIEW

Business Strategy.   Maximizing the value of our existing core assets is the focal point of our business strategy.   Our core assets are our fully integrated upstream and midstream assets in the Powder River and Greater Green River Basins in Wyoming, and the San Juan Basin in New Mexico; and our midstream operations in west Texas and Oklahoma.  Our long-term business plan is to increase stockholder value by: (i) doubling proven natural gas reserves and equity production of natural gas from the levels achieved in 2001 over a five year period; (ii) meeting or exceeding throughput projections in our midstream operations; and (iii) optimizing annual returns.

Industry and Company Overview.   In North America, our industry has experienced several consecutive years of declining natural gas production despite increased drilling activity.  Most of the major gas producing areas, such as the Gulf

21

of Mexico, are mature and are in production decline.  Our efforts, while concentrated in the Rocky Mountain area, extend into a variety of diverse unconventional gas plays, where there are estimated to be large quantities of undeveloped gas.   We are well positioned for future production growth with a large inventory of undeveloped drilling locations in the Powder River, the Greater Green River and San Juan Basins to meet the growing demand for clean burning natural gas.  In addition, our exploration effort leverages off of our upstream and midstream expertise in unconventional natural gas resource plays in order to add new company-building projects and to position us for long-term growth.

In the United States, the federal government largely retains the mineral rights to the undeveloped reserves in the areas in which we are active; accordingly, the development and production of these reserves requires permits from federal governmental agencies including the Bureau of Land Management, or BLM, and state agencies such as the Wyoming Department of Environmental Quality, or DEQ.  A significant challenge in developing these reserves is the difficulty encountered by the industry in obtaining the required permits in a timely manner.  We believe that our technical expertise in developing environmentally responsible solutions to the problems encountered in the development of gas reserves will be a competitive advantage in overcoming this challenge.

Additionally, to date we have been successful in obtaining drilling rigs and related oil field services to accomplish our drilling plans.  However, we believe that as we expand into new areas and continue the development of the areas in which we currently participate, obtaining rigs, related services and experienced employees in a timely manner will become increasingly difficult.

Our operations are conducted through the following four business segments:

Exploration and Production.  We explore for, develop and produce natural gas reserves independently and to enhance and support our existing gathering and processing operations. Our producing properties are primarily located in the Powder River, Greater Green River, San Juan, and Sand Wash Basins.  These plays provide relatively low geologic risk, and are multi-year development projects.  These provide us with the opportunity to steadily increase our production volume over time at reasonable operating and low finding and development costs.  In the third quarter of 2005, our average production sold was 177 MMcfe per day, which is a 14% increase over the daily average production volume sold in the third quarter of 2004.

We continue to seek to add additional upstream core projects that are focused on unconventional gas reservoirs.  We will utilize our expertise in exploration and low-risk development of unconventional gas reservoirs including tight-gas sands, coal bed methane, biogenic, and shale gas plays to evaluate acquisitions of either additional leaseholds, proven and undeveloped reserves or companies.  While we have historically focused on the Rocky Mountain region, we may also evaluate unconventional gas reservoirs in areas outside the Rockies where we can leverage our related exploration, production and gathering expertise.  In January 2005, we opened an office in Calgary, Alberta, Canada to evaluate opportunities and participate in drilling operations in the Western Canadian Sedimentary Basin.  Overall, at September 30, 2005, we have acquired the drilling rights on approximately 1.6 million net acres in various Rocky Mountain and other basins and continue to expand our leasehold positions.

Gathering, Processing and Treating.  Our core operations are in well-established areas such as the Permian, Anadarko, Powder River, Greater Green River, and San Juan Basins.  We connect natural gas from gas and oil wells to our gathering systems for delivery to our processing or treating plants under contracts with terms ranging from one month to the life of the lease. At our plants, we process natural gas to extract NGLs and treat natural gas in order to meet pipeline specifications.  We provide these services to major oil and gas companies, to independent producers of various sizes and for our own production.  We believe that our low cost of operations, our high on-line time and our safety records are key elements in our ability to compete effectively and provide reliable service to our customers.  Our expertise in gathering, processing and treating operations can enhance the economics of developing new upstream projects.

This segment of our operations has provided a stream of operating profit that is available for reinvestment into other projects or other segments of our business.  Overall throughput in our facilities during the third quarter of 2005 increased 7% as compared to the same period in 2004 and averaged a total of 1.5 Bcf per day.

Transportation.   In the Powder River Basin, we own one interstate pipeline, MIGC, Inc., and one intrastate pipeline, MGTC, Inc., which transport natural gas for producers and energy marketers under fee schedules regulated by state or federal agencies.

Marketing.  The primary goal of our gas-marketing segment is to ensure that the product from our processing facilities and upstream activities is delivered timely to the market.  Additionally, our gas marketing operations seek to preserve and

22

enhance the value received for our equity volumes of natural gas.  This goal is achieved through the use of hedges on the production of our equity natural gas and NGLs and through the use of firm transportation capacity.  We also buy and sell natural gas and NGLs in the wholesale market in the United States and in Canada.  These third-party sales, our firm transportation capacity on interstate pipelines and our gas storage positions, combined with the stable supply of gas from our facilities and production, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods.

RESULTS OF OPERATIONS

Three and nine months ended September 30, 2005 compared to the three and nine months ended September 30, 2004

(Dollars in thousands, except per share amounts and operating data).

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
				2004			Percent					2004			Percent
	2005			Restated			Change		2005			Restated			Change
Financial results:
Revenues	$	961,410		$	693,679		39		$	2,663,543		$	2,199,197		21
Net income	10,735			19,465			(45	)	68,070			67,548			1
Earnings per share of common stock	0.14			0.26			(46	)	0.92			0.93			(1	)
Earnings per share of common stock - diluted	0.14			0.26			(46	)	0.90			0.91			(1	)
Net cash provided by (used in) operating activities	(10,434		)	34,332			(130	)	149,668			126,678			18
Net cash (used in) investing activities	(109,630		)	(66,561		)	(64	)	(300,718		)	(144,885		)	(108	)
Net cash (used in) provided by financing activities	$	133,559		$	32,061		317		$	170,193		$	(5,190	)	3379
Operating data:
Average gas sales (MMcf/D)	1,152			1,130			2		1,205			1,229			(2	)
Average NGL sales (MGal/D)	2,009			1,741			15		1,883			1,665			13
Average gas prices ($/Mcf)	$	7.72		$	5.38		43		$	6.65		$	5.39		23
Average NGL prices ($/Gal)	$	1.04		$	0.78		33		$	0.92		$	0.70		31

Net income decreased $8.7 million for the three months ended September 30, 2005, compared to the same period in 2004.  The decrease in net income was primarily attributable to the non-cash mark-to-market of our risk management activities, which more than offset higher production of equity gas volumes and higher commodity prices in the third quarter of 2005.

Net income increased $522,000 for the nine months ended September 30, 2005, compared to the same period in 2004. This increase was primarily attributable to higher production of equity gas volumes and higher commodity prices that were substantially offset by the non-cash mark-to-market of our risk management activities.  In the first nine months of 2005, we incurred an after-tax charge of $3.8 million recorded in connection with a settlement of litigation.   The 2004 period included an after-tax charge associated with a settlement with the CFTC of $7.0 million, and an after-tax charge associated with the early extinguishment of long-term debt of $6.7 million.  Partially offsetting these items in the 2004 period was the cumulative effect of a change in accounting principle.  Effective as of January 1, 2004, we revised our depreciation and depletion methodology for our oil and gas properties.  This change in accounting principle resulted in a cumulative reduction of depreciation for periods prior to 2004 of $4.7 million, net of tax, in 2004.

Revenues from the sale of gas increased $260.3 million to $821.5 million for the three months ended September 30, 2005 compared to the same period in 2004.  This increase was primarily due to a significant increase in product prices, which more than offset a decrease in sales volume of third-party product in the three months ended September 30, 2005 compared to the same period in 2004.  Average gas prices realized by us increased $2.34 per Mcf to $7.72 per Mcf for the quarter ended September 30, 2005 compared to the same period in 2004.  Included in the realized gas price was approximately $857,000 of gains recognized in the three months ended September 30, 2005 related to futures positions on equity gas volumes.  We have entered into additional futures positions for our equity gas for the remainder of 2005 and in 2006.  See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”  Average gas sales volumes increased slightly to 1,152 MMcf per day for the quarter ended September 30, 2005 compared to the same period in 2004.

23

Revenues from the sale of gas increased $373.4 million to $2,195.8 million for the nine months ended September 30, 2005 compared to the same period in 2004.  This increase was primarily due to a significant increase in product prices, which more than offset a decrease in sales volume of third-party product in the nine months ended September 30, 2005, compared to the same period in 2004.  Average gas prices realized by us increased $1.26 per Mcf to $6.65 per Mcf for the nine months ended September 30, 2005 compared to the same period in 2004.  Included in the realized gas price were approximately $2.6 million of gains recognized in the nine months ended September 30, 2005 related to futures positions on equity gas volumes.  We have entered into additional futures positions for our equity gas for the remainder of 2005 and in 2006.  See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”  Average gas sales volumes decreased slightly to 1,205 MMcf per day for the nine months ended September 30, 2005 compared to the same period in 2004.

Revenues from the sale of NGLs increased $67.1 million to $191.6 million for the three months ended September 30, 2005 compared to the same period in 2004.  This is due to a significant increase in product prices and an increase in sales volumes.  Average NGL prices realized by us increased $0.26 per gallon to $1.04 per gallon for the three months ended September 30, 2005 compared to the same period in 2004.  Included in the realized NGL price were approximately $3.5 million of losses recognized in the three months ended September 30, 2005 related to futures positions on equity NGL volumes.  We have entered into additional futures positions for our equity NGL production for the remainder of 2005 and in 2006.  See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”  Average NGL sales volumes increased 268 MGal per day to 2,009 MGal per day for the three months ended September 30, 2005 compared to the same period in 2004.  This increase is due to the acquisition of several facilities in February 2005.

Revenues from the sale of NGLs increased approximately $154.6 million to $474.0 million for the nine months ended September 30, 2005 compared to the same period in 2004.  This is primarily due to a significant increase in product prices and, to a lesser extent, an increase in sales volumes.  Average NGL prices realized by us increased $0.22 per gallon to $0.92 per gallon for the nine months ended September 30, 2005 compared to the same period in 2004.  Included in the realized NGL price were approximately $5.5 million of losses recognized in the nine months ended September 30, 2005 related to futures positions on equity NGL volumes.  We have entered into additional futures positions for our equity NGL production for the remainder of 2005 and in 2006.  See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”  Average NGL sales volumes increased 218 MGal per day to 1,883 MGal per day for the nine months ended September 30, 2005 compared to the same period in 2004. This increase is due to the acquisition of several facilities in February 2005.

Price risk management activities changed from ($17.6) million for the quarter ended September 30, 2004 to ($79.9) million for the quarter ended September 30, 2005.  This change was due to the non-cash mark-to-market of our risk management activities.  This account is primarily impacted by changes in the forward price of natural gas in the 2005 quarter as compared to the 2004 quarter and the impact of those price changes on the fair value of the forward sale derivatives for our gas in storage.

Price risk management activities changed from ($11.6) million for the nine months ended September 30, 2004 to ($88.9) million for the nine months ended September 30, 2005.  This change was due to the non-cash mark-to-market of our risk management activities.  This account is primarily impacted by changes in the forward price of natural gas in the 2005 period as compared to 2004 period and the impact of those price changes on the fair value of the forward sale derivatives for our gas in storage.

Product purchases increased by $249.1 million and $404.5 million for the quarter and nine months ended September 30, 2005, respectively, compared to the same periods in 2004.  These increases in product purchases were the result of higher product prices.  On a consolidated basis, combined product purchases, as a percentage of sales of all products was 81% in the quarter ended September 30, 2005 compared to 84% in the quarter ended September 30, 2004.  Combined product purchases as a percentage of sales of all products decreased to 84% for the nine months ended September 30, 2005 from 86% in 2004.  The reduction in this percentage is primarily the result of an increase in revenues from the sale of equity production.

Plant and transportation operating expense increased by $7.1 million and $17.4 million, respectively, for the three and nine months ended September 30, 2005 compared to the same periods in 2004.  The increase for the quarter and nine month periods ended September 30, 2005 as compared to the same period in 2004 was substantially due to increased fees paid for the use of third party gathering systems behind our facilities, property tax, labor and repairs and maintenance expenses and the October 2004 and February 2005 asset acquisitions.

24

Oil and gas exploration and production expense increased by $9.8 million and $21.8 million, respectively, for the three and nine months ended September 30, 2005 compared to the same periods in 2004.  The increase for the quarter ended September 30, 2005 as compared to the same period in 2004 was substantially due to increased production taxes and expenses associated with the San Juan properties acquired in October 2004. The increase for the nine months ended September 30, 2005 as compared to the same period in 2004 was substantially due to increased lease operating expenses, or LOE, in the Powder River Basin coal bed development and expenses associated with the San Juan properties acquired in 2004. Overall, LOE averaged $0.81 per Mcf and $0.82 per Mcf for the quarter and nine months ended September 30, 2005, respectively and LOE in the Powder River Basin coal bed development averaged $0.92 and $0.89 per Mcf in the quarter and nine months ended September 30, 2005, respectively.  In the Powder River Basin, these represent increases of $0.16 and $0.11 per Mcf from the same periods in 2004.  The increase in LOE per Mcf  in the Powder River Basin is substantially due to higher water handling charges on dewatering wells in several new pilot areas that have no offsetting gas production as yet, contract labor, and fuel and operating costs of wellhead blowers in the Powder River Basin as well as increased costs related to initiating operations of the San Juan Basin production assets.  We anticipate upward pressure on LOE in 2006 due to increased labor and supply costs as well as increased use of water treatment facilities.

Depreciation, depletion and amortization, or DD&A, increased by $10.4 million and $25.3 million, respectively, for the three and nine months ended September 30, 2005 as compared to the same periods in 2004.  For the quarter ended September 30, 2005 as compared to the same period in 2004, we had a $1.8 million increase in DD&A in our midstream operations primarily due to our expanding CBM gathering system in the Powder River Basin and the October 2004 acquisition of additional midstream assets in the San Juan Basin, and a $8.2 million increase in DD&A in our upstream operations primarily due to our continued development in the Powder River Basin, downward revisions to reserves in the Powder River Basin based on the December 2004 reserve report, and our October 2004 acquisition of producing properties in the San Juan Basin.  For the nine months ended September 30, 2005 as compared to the same period in 2004, we had a $6.5 million increase in DD&A in our midstream operations and a $18.8 million increase in our upstream operations primarily due to those items mentioned above.

Selling and administrative expenses increased by $5.7 million and $8.5 million for the three and nine months ended September 30, 2005 as compared to the same period in 2004.   The increase in selling and administrative expenses for the quarter ended September 30, 2005 as compared to 2004 was primarily the result of increased administrative salaries and benefits, donations to the hurricane relief efforts, bad debt expense, and compensation expense related to our restricted stock plan.  The increase in selling and administrative expenses for the nine months ended September 30, 2005 as compared to 2004 was primarily the result of increased administrative salaries and benefits, insurance, audit expenses, donations to the hurricane relief efforts, bad debt expense, and compensation expense related to our restricted stock plan.  Additionally, the nine months ended September 30, 2005 included a charge of $5.9 million in connection with a settlement of litigation and the nine months ended September 30, 2004 included a $7.0 million charge for a settlement with the CFTC.

The Total provision for income taxes, as a percentage of Income before taxes was approximately 35.9% and 36.2%, respectively, during the quarter and nine months ended September 30, 2005 as compared to 36.7% and 39.0%, respectively, in same periods of 2004.  The decrease in the percentage of income taxes in the nine-month periods is primarily due to the civil penalty paid to the CFTC in 2004, which was non-deductible for tax purposes.

Cash Flow Information

Cash flows from operating activities increased by $23.0 million in the first nine months of 2005 compared to the same period in 2004. This increase was primarily due to the increase in net income, which was partially offset by margin calls paid in the 2005 period on financial sales of the gas in our storage positions.  At September 30, 2005, we had a total of $110.7 million of margin posted with our counterparties for these transactions.  The amount of margin posted has decreased to $53.8 million on November 7, 2005 and we will receive these margin deposits back as these positions expire during the fourth quarter of 2005 and the first quarter of 2006, or as the commodity price declines.

Cash flows used in investing activities increased by $155.8 million in the first nine months of 2005 compared to the same period in 2004.  This increase was primarily due to an increased level of capital expenditures including the February 2005 acquisition of additional midstream assets in the Greater Green River Basin.

Cash flows provided by financing activities increased by $175.4 million in the first nine months of 2005 compared to the same period in 2004.  This increase was due to the utilization of funds provided by financing activities in 2005 to fund our capital investments and margin calls on financial sales of our storage positions.

25

Segment Information

Gas Gathering, Processing and Treating.  The Gas Gathering, Processing and Treating segment realized segment-operating profit of $171.4 million for the nine months ended September 30, 2005 compared to $122.9 million in the same period in 2004.  The increase in operating profit in this segment in the 2005 periods is primarily due to higher realized prices and the resulting increase in net margin as shown below. 

	Quarter Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Gross Margin ($/Mcf)  (1)	$	0.72	$	0.55	$	0.65	$	0.52
Segment Plant operating and transportation expense ($/Mcf)	0.22		0.18		0.21		0.18
Net Margin ($/Mcf)	$	0.50	$	0.37	$	0.44	$	0.34
Average gas volumes gathered (MMcf/D)		1,490		1,389		1,414		1,361

(1) Gross Margin is segment Total revenues excluding net equity hedging losses less segment product purchases.

Exploration and Production.  The Exploration and Production segment realized segment-operating profit of $158.1 million for the nine months ended September 30, 2005 compared to $106.8 million in 2004. The increase is due to increased equity production, higher product prices, and the acquisition of production assets in the San Juan basin in the fourth quarter of 2004.   During the first nine months of 2005, our production of natural gas as compared to the same period in 2004 increased by 13% to 45.8 Bcfe.  The following table sets forth the average sales price received for our oil and gas products in the quarter and nine months ended September 30, 2005 and 2004.

	Quarter Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Average sales price: (1)
Oil ($/Bbl)	$	52.91	$	35.32	$	48.22	$	35.34
Gas ($/Mcf),  excluding the effect of hedging positions	6.46		4.53		5.59		4.50
Gas ($/Mcf), including the effect of hedging positions	6.50		4.55		5.64		4.59
Production and other costs:
Lease operating expense ($/Mcfe)	0.81		0.61		0.82		0.64
Production tax expense ($/Mcfe)	0.72		0.46		0.60		0.48
Gathering and transportation expense ($/Mcfe)
Inter-segment charges	0.60		0.63		0.57		0.60
Third-party charges	0.19		0.15		0.21		0.14
Other expenses ($/Mcfe)	0.02		0.03		0.02		0.02
Total costs ($/Mcfe)	$	2.34	$	1.88	$	2.22	$	1.88

(1)The prices received for NGLs are included in the price received for gas.

Marketing.  The Marketing segment realized segment-operating profit of ($83.0) million for the nine months ended September 30, 2005 compared to ($3.6) million in the same period of 2004.  The decrease was primarily due to non-cash mark-to-market losses from our price risk management activities related to future sales of gas utilizing our storage and transportation capacity.  As the stored or transported natural gas is sold and the future sale derivatives are settled, we will realize the benefit of the storage and transportation transactions through earnings in the quarter in which the gas is physically sold.

Transportation.  The Transportation segment realized segment-operating profit of $9.3 million for the nine months ended September 30, 2005 compared to $7.7 million in the same period of 2004.  The Transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin.

Recently Issued Accounting Pronouncements.  We continually monitor and revise our accounting policies as new rules are issued.  See Note 6 of Notes to Consolidated Financial Statements (Unaudited) in Item 1 of this Form 10-Q for a detailed description of recently issued accounting pronouncements.

LIQUIDITY AND CAPITAL RESOURCES

Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of debt and equity securities.  In the past, these sources have been sufficient to meet our needs and finance the growth of our business.  We can give no assurance that the historical

26

sources of liquidity and capital resources will be available for future development and acquisition projects, and we may be required to seek additional or alternative financing sources.  Product prices, hedges of equity production, sales of inventory, the volume of natural gas processed by our facilities, the volume of natural gas produced from our producing properties, the margin on third-party product purchased for resale, as well as the timely collection of our receivables and the availability of oil field services and supplies such as concrete and steel pipe are all expected to have significant influences on our future net cash provided by operating activities.  Additionally, our future growth will be dependent upon the success and timing of our exploration and production activities, obtaining additions to dedicated plant reserves, acquisitions, new project development, marketing results, efficient operation of our facilities and our ability to obtain financing at favorable terms.

During the past several years, we have been successful in developing additional reserves of natural gas and increasing our equity natural gas production.  However, the overall level of drilling and production associated with our producing properties will depend upon, among other factors, the price for gas, availability of transportation capacity to market centers, the energy and environmental policy and regulation by governmental agencies, the drilling schedules of the operators of our non-operated properties, the issuance of drilling and water disposal permits, the availability of oil field services, and the length of time for wells in the Powder River Basin to be dewatered, none of which is within our control.  A significant reduction in the level of our production or a significant reduction in natural gas prices could have a material adverse effect on our financial condition, results of operations and cash flows.

Although some of our plants have experienced natural declines in dedicated reserves, overall we have been successful in connecting additional reserves to more than offset these declines.  However, the overall level of drilling associated with our plant facilities will depend upon, among other factors, the prices for oil and gas, the drilling budgets of third-party producers, availability of transportation capacity to market centers, the energy and environmental policy and regulation by governmental agencies, the pace at which drilling permits are received, none of which is within our control. There is no assurance that we will continue to be successful in replacing the dedicated reserves processed at our facilities.  Any prolonged reduction in prices for natural gas and NGLs may depress the levels of exploration, development and production by third parties.  Lower levels of these activities could result in a corresponding decline in the demand for our gathering, processing and treating services.  A significant reduction in any of these activities could have a material adverse effect on our financial condition, results of operations and cash flows.

In the third quarter of 2005, the Gulf Coast of the United States was impacted by two major hurricanes.  These storms resulted in the curtailment of natural gas and oil production from the Gulf of Mexico, and the operations of major refineries and gas processing facilities in Texas, Louisiana and Mississippi.  Our operations did not sustain any physical damage from these hurricanes, and our liquidity was not materially impacted as our counterparties and customers continued to make timely payments.  However, in September 2005, one of our customers, a utility serving the New Orleans area, filed for bankruptcy protection under Chapter 11 of the Bankruptcy Code.  At the time of the bankruptcy filing, we had an outstanding account receivable from this utility of $4.1 million.  In the third quarter of 2005, we reserved $800,000 against this amount, which represents our best estimate of the current market value of this receivable.  Also as a result of these storms, natural gas and crude oil prices have increased substantially resulting in significant margin calls to us primarily from financial instruments entered into by us to pre-sell our natural gas and NGL storage positions.  At September 30, 2005, we had margin deposits posted of $110.7 million.  The amount of margin posted has decreased to $53.8 million on November 7, 2005, and we will receive this margin back as these positions expire during the fourth quarter of 2005 and the first quarter of 2006 or as commodity prices decline.

Even with the impact of, and the market uncertainty caused by, these storms, we believe that the amounts available to be borrowed under our financing facilities, together with the net cash provided by operating activities, will provide us with sufficient funds to connect new reserves, maintain our existing facilities and complete our current capital expenditure program.  Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital.  Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third-parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or use a combination of these alternatives.  While we believe that we would be able to secure additional financing, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing.

In September 2005, our board of directors announced its intent to increase our annual dividend on common stock from $0.20 per share to $0.30 per share.  This increase, if declared, will be effective beginning with the dividend paid to holders of record on December 31, 2005.  We expect our dividends to total approximately $22.5 million in 2006 and that they will be funded with net cash provided by operating activities.

27

Sources and Uses of Funds.  Our sources and uses of funds for the nine months ended September 30, 2005 are summarized as follows (dollars in thousands):

Sources of funds:
Borrowings under our revolving credit facility	$	3,097,865
Borrowings under our master shelf agreement	25,000
Proceeds from the dispositions of property and equipment	1,856
Net cash provided by operating activities	149,668
Distributions from equity investments	897
Change in outstanding checks	26,725
Proceeds from exercise of common stock options	12,134
Total sources of funds	$	3,314,145
Uses of funds:
Payments related to long-term debt (including debt issue costs)	$	2,945,404
Capital expenditures	301,147
Payments made under our master shelf agreement	35,000
Contributions to equity investments	2,324
Common dividends paid	11,127
Total uses of funds	$	3,295,002

Capital Investment Program.  We currently anticipate capital expenditures in 2005 of approximately $419.1 million.   Overall, capital expenditures in the Powder River Basin CBM development and in the Greater Green River Basin operations represent 36% and 30%, respectively, of the total 2005 budget.  Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2005 will not change or that we will actually incur this level of capital expenditures.  This budget may be increased to provide for acquisitions if approved by our board of directors.

The 2005 capital budget and our capital expenditures during the nine months ended September 30, 2005 are presented in the following table (dollars in millions):

Type of Capital Expenditure	2005 Capital Budget		Year to Date Capital Expenditures
Gathering, processing, treating and pipeline assets (1)	$	169.4	$	107.8
Exploration and production and lease acquisition activities	210.4		161.6
Acquisition of Greater Green River Basin midstream assets	28.0		28.0
Information technology and other items	3.0		2.9
Capitalized interest and overhead	8.3		9.4
Total Capital Expenditures	$	419.1	$	309.7

(1) Includes $13.7 million budgeted in 2005 and $7.0 million expended in the nine months ended September 30, 2005 for maintaining existing facilities.

Contractual Commitments and Obligations

Contractual Cash Obligations.  A summary of our contractual commitments and cash obligations as of September 30, 2005 is as follows (dollars in thousands):

			Payments by Period
Type of Obligation	Total Obligations		Due in 2005		Due in 2006 – 2007		Due in 2008 – 2009		Due Thereafter
Guarantee of Fort Union Project Financing	$	4,555	$	246	$	2,146	$	2,163	$	—
Operating Leases	76,576		4,508		33,568		25,734		12,766
Firm Transportation Capacity Agreements	254,976		10,809		86,117		75,131		82,919
Firm Storage Capacity Agreements	29,255		2,695		12,720		5,041		8,799
Long-term Debt	524,500		—		20,000		379,500		125,000
Interest on Long-term Debt (1)	121,560		7,105		54,967		43,597		15,891
Total Contractual Cash Obligations	$	1,011,422	$	25,363	$	209,518	$	531,166	$	245,375

(1)The interest rate assumed on the revolving credit facility at September 30, 2005 is 5.1% per annum.

28

Guarantee of Fort Union Project Financing.   We own a 15% equity interest in Fort Union Gas Gathering, L.L.C., or Fort Union, and are the construction manager and field operator.  Fort Union gathers and treats natural gas in the Powder River Basin in northeast Wyoming.  Initial construction and any expansions of the gathering header and treating system have been project financed by Fort Union.  This debt is amortizing on an annual basis with the final payment due in 2009.   Our requirement to fund under this guarantee would be reduced by the value of assets held by Fort Union.  This guarantee is not reflected on our Consolidated Balance Sheet.

Operating Leases.  In the ordinary course of our business operations, we enter into operating leases for office space, and for office, communication, transportation and compression equipment.  Payments made on these leases are a component of operating expenses and are reflected on the Consolidated Statement of Operations and, as operating leases, are not reflected on our Consolidated Balance Sheet.  Our leases have terms ranging from one month to ten years and the majority of the leases have return or fair market purchase options available at various times during the lease.   If we were to exercise the purchase options on all the leased compression equipment, these purchase options would require the capital expenditure of approximately $45.0 million between 2007 and 2013.

Firm Transportation Capacity.  Access to firm transportation is also a significant element of our business strategy.  Firm transportation ensures that our equity production has access to downstream markets and allows us to capture incremental profit when pricing differentials between physical locations occur.    Firm transportation agreements generally require the payment of fixed monthly fees regardless of the quantity of gas that flows under a particular agreement.  These agreements are not reflected on our Consolidated Balance Sheet.

At September 30, 2005, the fixed fees associated with our existing contracts for firm transportation capacity during 2005 will average approximately $0.15 per Mcf.  The associated contract periods range from one month to twelve years.  Under firm transportation contracts, we are required to pay the fees associated with these contracts whether or not the transportation is used.

Firm Storage Capacity Agreements.   We customarily store gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and to capture seasonal price differentials.  As of September 30, 2005, we had contracts in place for approximately 17.6 Bcf of storage capacity at various third-party facilities.  Firm storage agreements generally require the payment of fixed monthly fees regardless of the quantity of gas that is in storage under a particular agreement.  Of the total storage capacity under contract, approximately 7.0 Bcf is under contract to our Canadian subsidiary, WGR Canada, Inc., and Western guarantees the subsidiary’s performance under these contracts.  This subsidiary is wholly owned by us and fully consolidated in our financial statements.

The fees associated with these contracts in 2005 will average $0.59 per Mcf of annual capacity.  The associated contract periods at September 30, 2005 had an average term of 32 months.  At September 30, 2005, we held gas in our contracted storage facilities and in imbalances of approximately 19.5 Bcf at an average cost of $6.89 per Mcf compared to 19.6 Bcf at an average cost of $5.39 per Mcf at September 30, 2004.  These positions are for storage withdrawals within the next nine months.  At the time we place product into storage, we contract for the sale of that product, physically or financially, and do not speculate on the future value of the product.

At September 30, 2005, we held NGLs in line pack and in storage at various third-party facilities of 3,045 MGal, consisting primarily of propane and ethane, at an average cost of $0.41 per gallon compared to 2,877 MGal at an average cost of $0.32 per gallon at September 30, 2004.

Long-term Debt

Revolving Credit Facility.  At September 30, 2005, the commitment under the revolving credit facility was $500 million and matured in June 2009.  At September 30, 2005, $379.5 million was outstanding under this facility.   Loans made under this facility are secured by a pledge of the capital stock of our significant subsidiaries, and these subsidiaries also guarantee the borrowings under the facility.  In October 2005, we increased the commitment under the revolving credit facility to $580 million to assure adequate liquidity in a rising price environment.

The borrowings under our credit facility bear interest at Eurodollar rates or a base rate, as requested by us, plus an applicable percentage based on our debt to capitalization ratio.  The base rate is the agent’s published prime rate.  We also

29

pay a quarterly commitment fee on undrawn amounts ranging between 0.20% and 0.375%, depending on our debt to capitalization ratio.  This fee is paid on unused amounts of the commitment.  As of September 30, 2005, the interest rate payable on borrowings under this facility was approximately 5.1% per year.  Under the credit facility, we are subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55% and maintaining a ratio of EBITDA, as defined in the credit facility, to interest over the last four quarters in excess of 3.0 to 1.0.  The credit facility ranks equally with borrowings under our master shelf agreement with The Prudential Insurance Company.  This facility has been rated Ba1 by Moody’s and BB+ by S&P.

In November 2005, we amended and restated our existing revolving credit facility.  The amended and restated facility is a five-year, $700 million revolving credit facility maturing in November 2010.  The covenants under the amended facility remained the same as the existing facility and our borrowing rate was reduced by approximately 50 basis points.

Master Shelf Agreement.  Amounts outstanding under our master shelf agreement at September 30, 2005 are as indicated in the following table (dollars in thousands):

Issue Date	Amount		Interest Rate		Final Maturity	Principal Repayment Schedule
July 28, 1995	$	20,000	7.61	%	July 28, 2007	$10,000 on July 28, 2006 and 2007
June 30, 2004	100,000		5.92	%	June 30, 2011	Single payment at maturity
January 18, 2005	25,000		5.57	%	January 18, 2015	Single payment at maturity
Total	$	145,000

Our borrowings under our master shelf agreement are secured by a pledge of the capital stock of our significant subsidiaries.  These subsidiaries also guarantee the borrowings under this facility.  All of the borrowings under our master shelf agreement can be prepaid prior to their final maturity by paying a yield-maintenance fee.   Under our master shelf agreement, we are subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55% and maintaining a quarterly test of EBITDA, as defined in our master shelf agreement, to interest for the last four quarters in excess of 3.0 to 1.0.

Upstream Operations

A vital aspect of our long-term business plan is to double proven natural gas reserves and equity production of natural gas from the level at December 31, 2001 over a five-year period.  In order to achieve this goal, we will focus on continued development of our leasehold positions in the Powder River Basin CBM development, the Greater Green River Basin, the San Juan Basin, and the Sand Wash Basin. Each of our existing upstream projects is fully integrated with our midstream operations.  In other words, in each of these areas, we provide the gathering, compression, processing, marketing or transportation services for both our own production and for third-party operators.  Additionally, we are actively pursuing new exploration, development and producing property acquisition opportunities.

Our principal upstream operations are summarized in the following table: 

	As of September 30, 2005
Production Area	Gross Acres Under Lease	Net Acres Under Lease	Gross Productive Gas Wells	Net Productive Gas Wells	Net Production  Sold (Mmcfe per day)*
Powder River Basin	1,035,000	528,000	4,896	2,331	114
Jonah/Pinedale Field	165,000	46,000	323	36	38
San Juan Basin	28,000	27,000	167	147	11
Sand Wash Basin	120,000	113,000	21	21	5
Denver-Julesburg Basin	393,000	339,000	9	9	—
Canada	14,000	13,000	2	2	—
Other	625,000	546,000	13	3	1
Total	2,380,000	1,612,000	5,431	2,549	169

* Average for the nine months ended September 30, 2005.

30

Drilling Results.  The following table sets forth the number of wells we drilled during the nine months ended September 30, 2005 and 2004 in each of our major producing areas.  This information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

		Nine Months Ended September 30,
		2005		2004
Production Area	Type of Well Drilled	Gross	Net	Gross	Net
Powder River Basin CBM	Productive	703	343	512	246
Jonah/Pinedale Field	Productive	70	7	50	5
	Dry exploratory	1	0	0	0
San Juan Basin	Productive	30	28	0	0
Sand Wash Basin	Productive	5	5	5	5
	Dry exploratory	1	1	1	1
Canada	Productive	2	2	0	0
Other	Exploratory productive	10	4	0	0

Powder River Basin Coal Bed Methane.  We continue to develop our Powder River Basin CBM reserves and expand the associated gathering system in northeast Wyoming.  Our net production sold from the Powder River Basin CBM averaged 114 MMcf per day in the first nine months of 2005.

Our production from the Big George coal continues to increase and was 140 MMcf per day gross at October 31, 2005, or 59 MMcf per day net.  In the Big George coal, as of October 31, 2005, we had 909 gross wells dewatering and producing gas, 521 gross wells dewatering and 802 gross wells drilled and in various stages of completion and hook-up in preparation for dewatering and production.

Drilling in the Powder River Basin is dependent on the receipt of various regulatory permits, including BLM drilling permits, DEQ water discharge permits, and the Wyoming State Engineer’s Office reservoir permits.  Most of our undeveloped prospects from the Big George formation are located in the Powder River drainage area.  Water management techniques utilized by us, and approved by the DEQ on a site-specific basis, have included containment or treating.  In order to facilitate the processing of our water discharge permit applications, on the west side of the basin, and in advance of the receipt of final requirements of the DEQ, we have installed and are evaluating various types of water treatment facilities to test their effectiveness.  We are treating the water produced in some areas of the basin and, with the approval of the DEQ, discharging this water into the Powder River.  We believe many of the future developments in the Big George coal will likely require water treatment facilities.  These treating operations have added and will add to the cost of development and operations in these areas.  We continue to evaluate several options for water treatment and are working with the governmental agencies to identify effective and cost efficient methods.  Depending upon the type of water treatment system, that proves to be the most effective and cost efficient, we may incur additional costs and/or delays in production to deploy these facilities in all our operating areas.

Our 2005 capital budget for the Powder River Basin coal bed project is estimated at $103.0 million for the drilling of 850 gross wells, of which $86.2 million was spent in the first nine months of 2005.  In 2005, in the Big George and related coals, we plan to participate in the drilling of 730 gross wells, or 365 net wells, and in the Wyodak and related coals, we plan to participate in an additional 120 gross wells, or 60 net wells.  Together with our co-developer, we have received the drilling and water discharge permits required for the remainder of our drilling program for 2005.  Further, we and our co-developer have received federal drilling permits and water discharge permits for approximately one-half of our expected 2006 drilling program.  There is, however, no assurance as to the future timing of the receipt of drilling and water discharge permits, any changes in regulations governing drilling and water discharge, restrictions placed on water discharge and/or quality by Wyoming or other states, the success of our drilling program, or the dewatering time as our development progresses into the western and northern parts of the Powder River Basin.

On April 30, 2003, the BLM issued the final Record of Decision, or ROD, for the Powder River Basin Oil & Gas Environmental Impact Statement, or EIS.  The ROD requires additional surveys for plant and animal species, cultural surveys and noxious weed mitigation prior to the BLM granting a drilling permit.  A number of cases have been filed by environmental groups against the BLM in Wyoming disputing the validity of the EIS and ROD.  Due to our interests in developing federal leases in the Powder River Basin, we are an intervenor defendant in each of the foregoing cases.  In one of these cases filed in the United States District Court of Montana, the court was asked to address the adequacy of the Montana Powder River Basin ROD and whether the BLM should have issued a single EIS for the Powder River Basin.  Under an Order dated March 4, 2005, the court found that a single EIS for the Powder River Basin is not required under the

31

National Environmental Policy Act, or NEPA. This Order was subsequently appealed.  As these cases proceed, the BLM, in the event of any adverse rulings, may be required to perform further environmental analysis and, in addition, could be ordered to cease issuing drilling permits until it has completed such further analysis.   Consequently, our ability to receive permits and develop our leases may be delayed or restricted by the outcome of these cases.

A complaint was filed on January 31, 2005 in the U.S. District Court of Wyoming against the BLM and the Department of Interior.  The complaint alleges that the BLM violated NEPA “as described in Pennaco Energy, Inc. v. United States Department of the Interior” because the BLM did not consider the effects of CBM development prior to issuing five leases, including one issued to us.  On July 12, 2005, the plaintiffs amended their complaint by deleting four of the five leases included in their January 31, 2005 complaint, including the lease in which we hold an interest.  Additionally, the plaintiffs added 45 other leases to their Amended Complaint, including nine leases in which we hold an interest.  These nine leases cover approximately 5,300 gross and 2,650 net acres.  The plaintiffs asked the court for a  “review of the issuance” of these leases.  In September 2005, the plaintiffs filed a Notice of Dismissal of this complaint.

Jonah/Pinedale Fields.  Our exploration and production assets in the Green River Basin of southwest Wyoming are located in the Pinedale Anticline and Jonah Field areas.  During 2005, we expect to participate in the drilling of 85 to 90 gross wells, or approximately ten net wells, on the Pinedale Anticline.  Our capital budget for 2005 in the Pinedale Anticline area provides for expenditures of approximately $52.3 million for drilling costs and production equipment, of which $38.6 million was spent in the first nine months of 2005.  Due to drilling and regulatory uncertainties, which are beyond our control, including changes to existing air quality, water quality, and/or surface use regulations, there can be no assurance that we will incur this level of capital expenditure during 2005.

Midstream Operations

Our midstream operations consist of our gathering, processing, treating, marketing and transportation operations.  An important element of our long-term business plan is to meet or exceed throughput projections in these areas and to optimize their profitability.  To achieve this goal, we must continue our efforts to add to natural gas throughput levels through new well connections and through the expansion or acquisition of gathering or processing systems in those basins in which we currently operate or in new basins.  We also seek to increase the efficiency of our operations by modernization of equipment and the consolidation of existing facilities.

Gas Gathering, Processing and Treating. We operate a variety of gathering, processing and treating facilities, or plant operations, as presented on the Principal Gathering and Processing Facilities Table set forth below.  Our operations are located in some of the most actively drilled oil and gas producing basins in the United States.  Six of our processing plants can further separate, or fractionate, the mixed NGL stream into ethane, propane, normal butane and natural gasoline to obtain a higher value for the NGLs, and three of our plants are capable of processing and treating natural gas containing hydrogen sulfide or other impurities that require removal prior to delivery to market pipelines.   In addition to our integrated upstream and midstream operations in the Powder River and Green River Basins in Wyoming, and in the San Juan Basin in New Mexico, our core assets include our plant operations located in west Texas and Oklahoma.  We believe that our core assets have stable production rates, significant proven reserves connected to our systems, provide a significant operating cash flow and continue to provide us with strategic growth opportunities.

In February 2005, we completed the purchase of certain natural gas gathering and processing assets in the eastern Greater Green River Basin for approximately $28.0 million, before closing adjustments.  In the third quarter of 2005, we connected the Wamsutter and Red Desert systems into the acquired assets.

In April 2005, we entered into an agreement to acquire a 200 MMcf per day cryogenic processing facility for $9.0 million.  We intend to spend an additional $28.5 million to install this facility and expand our Chaney Dell/Westana processing and gathering complex in Oklahoma.  We currently expect that this facility will be operational in the second quarter of 2006.

32

Principal Gathering and Processing Facilities Table.  The following table provides information concerning our principal gathering, processing and treating facilities at September 30, 2005.

	Year	Gas	Gas	Average for the Nine Months Ended September 30, 2005
Facilities (1)	Placed in Service	Gathering System Miles	Throughput Capacity (MMcf/D)(2)	Gas Throughput (MMcf/D) (3)	Gas Production (MMcf/D)(4)	NGL Production (MGal/D) (4)
Texas
Gomez Treating (5)	1971	389	280	87	78	—
Midkiff/Benedum	1949	2,354	165	143	91	861
Mitchell Puckett Treating (5)	1972	126	120	34	22	1
Wyoming
Coal Bed Methane Gathering	1990	1,398	548	395	360	—
Desert Springs Gathering	1979	65	10	6	5	22
Fort Union Gas Gathering(11)	1999	167	635	421	421	—
Granger Complex (6)	1987	732	332	313	261	383
Granger Straddle Plant	2004	—	200	125	—	9
Hilight Complex (6)	1969	658	124	18	13	66
Kitty/Amos Draw (6)	1969	321	17	5	3	24
Newcastle (6)	1981	146	5	3	2	22
Patrick Draw(6) (8)	1997	284	150	35	38	116
Red Desert (6) (13)	1979	137	42	23	34	80
Rendezvous (9)	2001	238	325	349	349	—
Reno Junction (7)	1991	—	—	—	—	114
Table Rock Gathering	1979	100	20	12	12	—
Wamsutter Gathering (10)	1979	279	50	50	45	40
Wind River Gathering	1979	137	80	48	48	—
Oklahoma
Chaney Dell/Westana	1966	3,382	187	201	177	313
New Mexico
San Juan River (5)	1955	277	60	26	22	40
Utah
Four Corners Gathering	1988	104	15	3	2	18
Yellow Creek (8) (12)	1985	—	—	—	—	74
Total		11,294	3,365	2,297	1,983	2,183

(1)	Our interest in all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%); Fort Union (14%) and Rendezvous (50%). We operate all facilities, and all data include our interests and the interests of other joint interest owners and producers of gas volumes dedicated to the facility. Unless otherwise indicated, all facilities shown in the table are gathering, processing or treating facilities.
(2)	Gas throughput capacity is as of September 30, 2005 and represents capacity in accordance with design specifications unless other constraints exist, including permitting or field compression limits.
(3)	Aggregate natural gas volumes delivered into our gathering systems.
(4)	Volumes of gas and NGLs are allocated to a facility when a well is connected to that facility; volumes exclude NGLs fractionated for third-parties, unless otherwise indicated.
(5)	Sour gas facility (capable of processing or treating gas containing hydrogen sulfide and/or carbon dioxide).
(6)	Processing facility that includes fractionation (capable of fractionating raw NGLs into end-use products).
(7)	NGL production includes conversion of third-party feedstock to iso-butane.
(8)	This facility was acquired in a transaction which was completed on February 1, 2005.
(9)	The majority of the gas gathered by the Rendezvous gas gathering system is delivered to our Granger facility and is included with the volume information reported for Granger.
(10)	A portion of the gas gathered by the Wamsutter gas gathering system is delivered to our Patrick Draw facility and is included with the volume information reported for Patrick Draw.
(11)	A portion of the gas gathered by Fort Union is also reported under Coal Bed Methane Gathering.
(12)	NGL fractionation facility that receives product from third-parties via liquids pipeline and truck.
(13)	A portion of this facility was taken out of operation in the third quarter of 2005. The gas gathered through this facility is now delivered to the Patrick Draw facility for processing.

33

Transportation Operations

We own and operate MIGC, Inc., an interstate pipeline located in the Powder River Basin, and MGTC, Inc., an intrastate pipeline located in northeast Wyoming.  MIGC charges a Federal Energy Regulatory Commission, or FERC, approved tariff and is connected to pipelines owned by Colorado Interstate Gas Company, Williston Basin Interstate Pipeline Company, Kinder Morgan Interstate Pipeline Co., Wyoming Interstate Company, Ltd. and MGTC.  MIGC earns fees on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline.  Contracts with third parties for capacity on MIGC range in duration from one month to approximately five years, and the fees charged averaged $0.35 per Mcf in the first nine months of 2005.  MGTC, a public utility, provides transportation and gas sales to various cities in Wyoming at rates that are subject to the approval of the Wyoming Public Service Commission.

The following table provides information concerning our principal transportation assets at September 30, 2005.

			Average for the Nine Months Ended September 30, 2005
Transportation Facilities (1)	Year Placed In Service	Transportation Miles	Pipeline Capacity (MMcf/D) (2)	Gas Throughput (MMcf/D) (3)
MIGC	1970	263	130	135
MGTC	1963	251	18	9
Total		514	148	144

(1)Our interest in both facilities is 100%, and we operate both facilities.

(2)Pipeline capacity represents certificated capacity at the Powder River junction only and does not include interruptible capacity or capacity at other delivery points.

(3)Aggregate volumes transported by a pipeline.

Marketing

Gas.We market gas produced at our wells and at our plants and gas purchased from third-parties to end-users, local distribution companies, or LDCs, pipelines and other marketing companies throughout the United States and Canada.  In addition to our offices in Denver, we have marketing offices in Houston, Texas and Calgary, Alberta.  Third-party sales, firm transportation capacity on interstate pipelines and our gas storage positions, combined with the stable supply of gas from our facilities and production, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods.  One of the primary goals of our gas marketing operations continues to be the preservation and enhancement of the value received for our equity volumes of natural gas.  This goal is achieved through the use of hedges on the production of our equity natural gas and through the use of firm transportation capacity.

NGLs.We market NGLs, or ethane, propane, iso-butane, normal butane, natural gasoline and condensate, produced at our plants and purchased from third-parties, in the Rocky Mountain, Mid-Continent and Southwestern regions of the United States.  A majority of our production of NGLs moves to the Gulf Coast area, which is the largest NGL market in the United States.  Through the development of end-use markets and distribution capabilities, we seek to ensure that products from our plants move on a reliable basis, avoiding curtailment of production. Consumers of NGLs are primarily the petrochemical industry, the petroleum refining industry and the retail and industrial fuel markets.  As an example, the petrochemical industry uses ethane, propane, normal butane and natural gasoline as feedstocks in the production of ethylene, which is used in the production of various plastics products.  Further, consumers use propane for home heating, transportation and agricultural applications.  Price, seasonality and the economy primarily affect the demand for NGLs.

34

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our commodity price risk management program has two primary objectives.  The first goal is to preserve and enhance the value of our equity volumes of gas and NGLs with regard to the impact of commodity price movements on cash flow and net income in relation to those anticipated by our operating budget.  The second goal is to manage price risk related to our marketing activities to protect profit margins.  This risk relates to fixed price purchase and sale commitments, the value of storage inventories and exposure to physical market price volatility.

We utilize a combination of fixed price forward contracts, exchange-traded futures and options, as well as fixed index swaps, basis swaps and options traded in the over-the-counter, or OTC, market to accomplish these goals.  These instruments allow us to preserve value and protect margins because corresponding losses or gains in the value of the financial instruments offset gains or losses in the physical market.

We also use financial instruments to reduce basis risk.  Basis is the difference in price between the physical commodity being hedged and the price of the futures contract used for hedging.  Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged.  Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations.

We enter into futures transactions on the New York Mercantile Exchange, or NYMEX, and OTC swaps and options with various counterparties, consisting primarily of investment banks, financial institutions and other natural gas companies.  We conduct credit reviews of all of our OTC counterparties and have agreements with many of these parties that contain collateral requirements.  We generally use standardized swap agreements that allow for offset of positive and negative OTC exposures with the same counterparty.  OTC exposure is marked-to-market daily for the credit review process.  Our exposure to OTC credit risk is reduced by our ability to require a margin deposit from our counterparties based upon the mark-to-market value of their net exposure.  We are also subject to margin deposit requirements under these same agreements and under margin deposit requirements for our NYMEX transactions.  As a result of the recent hurricane damage, the resultant curtailment of oil and gas production from the Gulf of Mexico, and impact to the operations of major refineries and gas processing facilities in Texas, Louisiana and Mississippi, oil and gas prices have increased substantially.  These increases have resulted in additional required postings of margin deposits totaling $110.7 million at September 30, 2005, which has subsequently decreased to $53.8 million on November 7, 2005.

We continually monitor and review the credit exposure to our marketing counterparties.  In recent months the prices of natural gas and NGLs, and therefore our credit exposures, have increased significantly.   Additionally, as a result of the damage in the Gulf States caused by hurricanes Katrina and Rita, prices increased even more dramatically, and several of our counterparties experienced a significant amount of damage to their operating assets.  In September 2005, one of our customers, a utility serving the New Orleans area, filed for bankruptcy protection under Chapter 11 of the Bankruptcy Code.  At the time of the bankruptcy filing, we had an outstanding account receivable from this utility of $4.1 million.  In the third quarter of 2005, we reserved $800,000 against this amount, which represents our best estimate of the current market value of this receivable.

In order to minimize our credit exposures, we have utilized existing netting agreements to reduce our net credit exposure, established new netting agreements with additional customers, negotiated accelerated payment terms with several customers, curtailed sales to certain counterparties, and increased the amount of credit which we make available to substantial companies which meet our credit requirements.  Although netting agreements similar to those that we utilize have been upheld by bankruptcy courts in the past, if any of the customers with whom we have netting agreements were to file for bankruptcy, we can provide no assurance that our agreements will not be challenged or as to the outcome of any challenge.

The use of financial instruments may expose us to the risk of financial loss in some circumstances, including instances when (i) our equity volumes are less than expected, (ii) our customers fail to purchase or deliver the contracted quantities of natural gas or NGLs, or (iii) our OTC counterparties fail to perform.  To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market.  However, we are similarly insulated against decreases in these prices.

Risk Policy and Control.We control the extent of risk management and marketing activities through policies and procedures that involve the senior level of management.  On a daily basis, our marketing activities are audited and monitored by our independent risk oversight department, or IRO.  This department reports to the Chief Financial Officer, thereby providing a separation of duties from the marketing department.  Additionally, the IRO reports monthly to the Risk Management Committee, or RMC.  This committee is comprised of corporate managers and officers and is responsible for

35

developing the policies and guidelines that control the management and measurement of risk, subject to the approval of the board of directors. The RMC is also responsible for setting risk limits including value-at-risk and dollar stop loss limits, subject to the approval of our board of directors.

Hedge Positions.   The hedge contracts are designated and accounted for as cash flow hedges.  As such, gains and losses related to the effective portions of the changes in the fair value of the derivatives are recorded in Accumulated other comprehensive income, a component of Stockholders’ equity.  Realized gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Sale of gas or Sale of natural gas liquids when the hedged transactions occur.

To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must be highly effective at offsetting changes in the price of the forecasted transaction being hedged so that our exposure to the risk of commodity price changes is reduced.  To meet this requirement, we hedge the price of the commodity and, if applicable, the basis between that derivative’s contract delivery location and the cash market location used for the actual sale of the product.  This structure attains a high level of effectiveness, ensuring that a change in the price of the forecasted transaction will result in an equal and opposite change in the price of the derivative instrument hedging the transaction. We utilize crude oil as a surrogate hedge for natural gasoline and condensate.  Our hedges are tested for effectiveness at inception and on a quarterly basis thereafter.  We use regression analysis based on a five-year period of time for this test.  Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Price risk management activities.  During the first nine months of 2005, we recognized a loss of $208,000 from the ineffective portions of our hedges.

Earnings Sensitivity.  Historically, the non-cash mark-to-market valuation of the gas storage and transportation contracts which were considered to be derivatives effectively offset non-cash mark-to-market changes to the forward derivative contract to sell our stored or transported natural gas.  After the adjustments to correct the prior accounting for these contracts as derivatives, the non-cash mark-to-market of the future sale derivative contract on the sale of gas will fluctuate through earnings with changes in market prices and will not be offset by a corresponding mark to market on the gas storage and transportation contracts.  For example, at September 30, 2005, we held gas in our contracted storage facilities and in imbalances of approximately 19.5 Bcf.  This inventoried gas was sold forward with derivatives.  Based on a $1.00 increase in the forward price of gas in the anticipated month of withdrawal, the change in the non-cash mark-to-market value of these derivatives will reduce pre-tax earnings by $19.5 million and a $1.00 decrease in the forward price of gas in the anticipated month of withdrawal will increase pre-tax earnings by $19.5 million. As the stored or transported natural gas is sold and the future sale derivatives are settled, we will realize the benefit of the storage and transportation transactions through earnings.

36

Outstanding Equity Hedge Positions and the Associated Basis for 2005 and 2006.  The following table details our hedge positions as of October 31, 2005.  In order to determine the hedged price to the particular operating region, deduct the basis differential from the settle price.  The prices for NGLs do not include the cost of the hedges of approximately $104,000 as of October 31, 2005.  There is no associated cost for the natural gas hedges.

Product	Year	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	2005	80,000 MMBtu per day with an average minimum price of $4.75 per MMBtu and an average maximum price of $8.88 per MMBtu.	Mid-Continent – 60,000 MMBtu per day with an average basis price of $0.42 per MMBtu. Permian – 5,000 MMBtu per day with an average basis price of $0.48 per MMBtu. Rocky Mountain – 15,000 MMBtu per day with an average basis price of $0.72 per MMBtu.
	2006	40,000 MMBtu per day with an average minimum price of $6.00 per MMBtu and an average maximum price of $10.13 per MMBtu. 45,000 MMBtu per day with an average minimum price of $9.00 per MMBtu and an average maximum price of $17.25 per MMBtu.	Mid-Continent – 40,000 MMBtu per day with an average basis price of $0.55 per MMBtu. Permian – 7,500 MMBtu per day with an average basis price of $0.97 per MMBtu. San Juan – 7,500 MMBtu per day with an average basis price of $1.38 per MMBtu. Rocky Mountain – 20,000 MMBtu per day with an average basis price of $1.44 per MMBtu. NGPL Texas Oklahoma – 10,000 MMBtu per day with an average basis price of $0.45 per MMBtu.
Crude, Condensate, Natural Gasoline	2005	50,000 Barrels per month with an average minimum price of $31.00 per barrel and an average maximum price of $48.01 per barrel.	Not Applicable
	2006	25,000 Barrels per month with an average minimum price of $40.00 per barrel and an average maximum price of $70.00 per barrel.	Not Applicable
Propane	2005	75,000 Barrels per month with an average minimum price of $0.52 per gallon and an average maximum price of $0.88 per gallon.	Not Applicable
Ethane	2005	75,000 Barrels per month. Floor at $0.38 per gallon.	Not Applicable

37

Account balances related to hedging transactions (designated as cash flow hedges under SFAS 133) at September 30, 2005 were $20.4 million in Current assets from price risk management activities, $1.3 million in Assets from price risk management activities, $71.6 million in Current liabilities from price risk management activities, $7.2 million in Liabilities from price risk management activities, ($20.8) million in Deferred income taxes payable, net, and a $36.2 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Stockholders’ equity.  Approximately $17.9 million of the unrealized loss in Accumulated other comprehensive income will be reclassified to earnings in the remainder of 2005.

Summary of Derivative Positions.  A summary of the net change in our derivative position from December 31, 2004 to September 30, 2005 is as follows (dollars in thousands):

Fair value of contracts outstanding at December 31, 2004	$	15,640
Decrease in value due to change in price	(39,665		)
Decrease in value due to new contracts entered into during the period	(121,720		)
(Gains) realized during the period from existing and new contracts	6,800
Changes in fair value attributable to changes in valuation techniques	—
Fair value of contracts outstanding at September 30, 2005	$	(138,945	)

A summary of our net outstanding derivative positions at September 30, 2005 is as follows (dollars in thousands):

	Fair Value of Contracts at September 30, 2005
Source of Fair Value	Total Fair Value			Maturing In 2005			Maturing In 2006-2007			Maturing In 2008-2009		Maturing Thereafter
Exchange published prices	$	(75,654	)	$	(40,282	)	$	(35,372	)	—		—
Other actively quoted prices (1)	9,912			8,507			1,371			$	34	—
Other valuation methods (2)	(73,203		)	(40,908		)	(32,744		)	449		—
Total fair value	$	(138,945	)	$	(72,683	)	$	(66,745	)	$	483	—

(1)Other actively quoted prices are derived from broker quotations, trade publications, and industry indices.

(2)Other valuation methods are the Black-Scholes option-pricing model utilizing prices and volatility obtained from broker quotations, trade publications, and industry indices.

Foreign Currency Derivative Market Risk.  As a normal part of our business, we enter into physical gas transactions which are payable in Canadian dollars.  We enter into forward purchases and sales of Canadian dollars from time to time to fix the cost of our future Canadian dollar denominated natural gas purchase, sale, storage, and transportation obligations.  This is done to protect marketing margins from adverse changes in the United States and Canadian dollar exchange rate between the time the commitment for the payment obligation is made and the actual payment date of such obligation.  As of September 30, 2005, we had sold forward contracts for  $53.1 million in Canadian dollars in exchange for $45.0 million in United States dollars, and the fair market value of these contracts was a loss of  $1.1 million in United States dollars.

ITEM 4.CONTROLS AND PROCEDURES

Disclosure Controls and Procedures.

The Company’s management evaluated, with the participation of the Chief Executive Officer and Chief Financial Officer, the effectiveness of the Company’s disclosure controls and procedures, as such term is defined under Rule 13a-15(e) of the Securities and Exchange Act of 1934, as of the end of the period covered by this Quarterly Report on Form 10-Q/A. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that because of the material weakness in internal control over financial reporting relating to the determination and periodic review of whether its gas storage and transportation contracts meet the definition of a derivative under generally accepted accounting principles, which was previously identified in “Management’s Report on Internal Control over Financial Reporting (as restated)” included in Item 8 of our Annual Report on Form 10-K/A for the year ended December 31, 2004 (“2004 Form 10-K/A”) had not yet been remediated, our disclosure controls and procedures were ineffective as of September 30, 2005. Notwithstanding this material weakness, the Company’s management believes that the consolidated financial condition, results of operations and cash flows are fairly presented in this Form 10-Q.

Remediation Efforts to Address This Material Weakness.

In the fourth quarter of 2005, we implemented controls to ensure that all contracts accounted for as derivatives are reviewed as to their terms and the markets on which they are traded to reaffirm that each contract meets the definition of a derivative.  This control will be performed on a monthly basis.

Changes in Internal Control Over Financial Reporting.

There were no material changes to internal controls over financial reporting during the first quarter ended September 30, 2005, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. Management continues to work on its remediation plan to address the material weakness relating to the accounting for gas transportation and storage contracts identified in our 2004 Form 10-K/A.

38

PART II - OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

Reference is made to “Notes to Consolidated Financial Statements (Unaudited)  – Legal Proceedings,” in Item 1 of this Form 10-Q and incorporated by reference in this Item 1.

39

ITEM 6.      EXHIBITS

Exhibit
Number	Description
3.1	Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.1 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.2	Certificate of Amendment to the Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.2 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.3	Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock (previously filed as part of Exhibit 1 to our Form 8-A filed on March 30, 2001 and incorporated herein by reference).
3.4	Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on May 7, 2004 (previously filed as Exhibit 99.1 to our Current Report on Form 8-K filed on May 11, 2004 and incorporated herein by reference).
10.1	Remuneration of Directors (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on July 21, 2005 and incorporated herein by reference).*
10.2	Employment Agreement, dated August 1, 2005, by and between Western Gas Resources, Inc. and Peter A. Dea (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on August 2, 2005 and incorporated herein by reference).*
31.1	Section 302 Certification of the Chief Executive Officer.
31.2	Section 302 Certification of the Chief Financial Officer.
32.1	Section 906 Certification of the Chief Executive Officer and Chief Financial Officer.

* Management contract or compensating plan or arrangement.

40

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.

	WESTERN GAS RESOURCES, INC.
	(Registrant)
Date: December 19, 2005	By:	/s/ PETER A. DEA
		Peter A. Dea
		Chief Executive Officer and President
Date: December 19, 2005	By:	/s/WILLIAM J. KRYSIAK
		William J. Krysiak
		Executive Vice President - Chief Financial Officer
		(Principal Financial and Accounting Officer)

41

INDEX TO EXHIBITS

Exhibit
Number	Description
3.1	Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.1 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.2	Certificate of Amendment to the Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.2 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.3	Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock (previously filed as part of Exhibit 1 to our Form 8-A filed on March 30, 2001 and incorporated herein by reference).
3.4	Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on May 7, 2004 (previously filed as Exhibit 99.1 to our Current Report on Form 8-K filed on May 11, 2004 and incorporated herein by reference).
10.1	Remuneration of Directors (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on July 21, 2005 and incorporated herein by reference).*
10.2	Employment Agreement, dated August 1, 2005, by and between Western Gas Resources, Inc. and Peter A. Dea (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on August 2, 2005 and incorporated herein by reference).*
31.1	Section 302 Certification of the Chief Executive Officer.
31.2	Section 302 Certification of the Chief Financial Officer.
32.1	Section 906 Certification of the Chief Executive Officer and Chief Financial Officer.

* Management contract or compensating plan or arrangement.