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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED JUNE 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 ý No o

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

On August 5, 2005, there were 74,617,902 shares of the registrant’s Common Stock outstanding.

Explanatory Note

Our Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, initially filed with the Securities and Exchange Commission, or the SEC, on August 9, 2005, or the Original Filing, is being amended by this Form 10-Q/A to reflect restatements of our Consolidated balance sheet at June 30, 2005 and December 31, 2004; and our Consolidated Statement of Operations, Consolidated Statement of Cash Flows and Consolidated Statement of Changes in Stockholders’ Equity for each of the quarters and six months ended June 30, 2005 and 2004, and the notes thereto.

Upon adoption of FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“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.

For a more detailed description of these restatements, see the footnote “Restatement of Consolidated Financial Statements” to the accompanying Consolidated Financial Statements and the section entitled “Restatement” in Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in this Form 10-Q/A.

Except for the foregoing amended information, this Form 10-Q/A continues to describe conditions as of the date of the Original Filing, including our expectations with respect to our 2005 capital budget and other forward-looking information, and we have not updated the disclosures contained herein to reflect events that occurred at a later date. Other events occurring after the filing of the Original Filing or other disclosures necessary to reflect subsequent events have been or will be addressed in either our restated Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005, which is being filed concurrently with the filing of this Form 10-Q/A, or in other reports filed with the SEC subsequent to the date of this filing.

Western Gas Resources, Inc.

Form 10-Q/A

Table of Contents

PART I - Financial Information

	Explanatory Note

Item 1.	Financial Statements

	Consolidated Balance Sheet - June 30, 2005 and December 31, 2004

	Consolidated Statement of Cash Flows - Six Months Ended June 30, 2005 and 2004

	Consolidated Statement of Operations – Three and Six Months Ended June 30, 2005 and 2004

	Consolidated Statement of Changes in Stockholders’ Equity - Six Months Ended June 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 4.	Submission of Matters to a Vote of Security Holders

Item 6.	Exhibits

Signatures

PART I - - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Unaudited)

(Dollars in thousands, except share data)

	June 30,			December 31,
	2005			2004
	Restated			Restated
ASSETS

Current assets:
Cash and cash equivalents	$	6,038		$	390
Trade accounts receivable, net	314,415			385,811
Margin deposits	16,885			7,939
Product inventory	92,096			94,604
Assets from price risk management activities	5,970			19,893
Deferred income tax	3,399			—
Other	11,766			12,494
Total current assets	450,569			521,131
Property and equipment:
Gas gathering, processing and transportation	1,215,286			1,150,904
Oil and gas properties and equipment (successful efforts method)	549,715			495,314
Construction in progress	219,866			150,273
	1,984,867			1,796,491
Less: Accumulated depreciation, depletion and amortization	(620,606		)	(570,582		)

Total property and equipment, net	1,364,261			1,225,909
Other assets:
Gas purchase contracts (net of accumulated amortization of $41,606 and $40,652, respectively)	33,044			27,704
Assets from price risk management activities	540			249
Equity investments	36,084			35,729
Other	25,796			26,676

Total other assets	95,464			90,358

TOTAL ASSETS	$	1,910,294		$	1,837,398

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	357,560		$	400,672
Accrued expenses	57,541			60,472
Liabilities from price risk management activities	15,391			4,321
Deferred income tax	—			5,618
Dividends payable	3,733			3,704
Total current liabilities	434,225			474,787
Long-term debt	417,000			382,000
Liabilities from price risk management activities	1,436			180
Other long-term liabilities	59,325			51,827
Deferred income taxes payable, net	265,947			243,835

Total liabilities	1,177,933			1,152,629

Stockholders’ equity:
Common stock, par value $.10; 100,000,000 shares authorized; 74,612,053 and 74,078,733 shares issued, respectively	7,483			7,430
Treasury stock, at cost; 50,032 common shares in treasury	(788		)	(788		)
Unearned compensation	(10,741		)	—
Additional paid-in capital	407,693			392,437
Retained earnings	331,339			281,428
Accumulated other comprehensive income	(2,625		)	4,262

Total stockholders’ equity	732,361			684,769

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,910,294		$	1,837,398

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

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Six Months Ended
	June 30,
	2005			2004

Reconciliation of net income to net cash provided by operating activities:
Net income	$	57,335		$	48,083
Add income items that do not affect cash:
Depreciation, depletion and amortization	59,877			44,974
Loss on sale of assets	27			1,639
Deferred income taxes	19,775			27,068
Non-cash change in fair value of derivatives	17,614			(3,303		)
Cumulative effect of a change in accounting principle	—			(4,714		)
Compensation expense from common stock options and restricted stock	926			476
Other non-cash items, net	(1,532		)	1,815

Adjustments to working capital to arrive at net cash provided by operating activities:
(Increase) decrease in trade accounts receivable	71,601			(23,972		)
(Increase) decrease in margin deposits	(8,946		)	1,956
(Increase) decrease in product inventory	1,933			(3,008		)
Increase in other current assets	(11,379		)	(3,856		)
(Increase) decrease in other assets and liabilities, net	(565		)	322
Increase (decrease) in accounts payable	(57,156		)	2,975
Increase (decrease) in accrued expenses	10,592			(2,323		)

Net cash provided by operating activities	160,102			88,132

Cash flows from investing activities:

Purchases of property and equipment, including acquisitions	(193,112		)	(79,548		)
Distributions from equity investees	613			1,196
Proceeds from the dispositions of property and equipment	1,411			697

Net cash used in investing activities	(191,088		)	(77,655		)

Cash flows from financing activities:

Proceeds from exercise of common stock options	2,735			3,492
Change in outstanding checks	6,335			26,168
Borrowings under revolving credit facility	1,789,015			810,630
Payments on revolving credit facility	(1,754,015		)	(809,630		)
Borrowings of long-term debt	25,000			100,000
Payments on long-term debt	(25,000		)	(155,000		)
Debt issue costs paid	(40		)	(1,827		)
Payments for the redemption of preferred stock	—			(1,930		)
Dividends paid	(7,396		)	(5,610		)

Net cash provided by (used in) financing activities	36,634			(33,707		)

Net increase (decrease) in cash and cash equivalents	5,648			(23,230		)

Cash and cash equivalents at beginning of period	390			26,116

Cash and cash equivalents at end of period	$	6,038		$	2,886

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

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	Restated			Restated			Restated			Restated
Revenues:
Sale of gas	$	678,087		$	595,881		$	1,374,306		$	1,261,191
Sale of natural gas liquids	149,481			102,021			282,450			194,936
Gathering, processing and transportation revenue	27,823			24,410			51,703			41,239
Price risk management activities	11,205			2,995			(9,043		)	5,979
Other	1,430			531			2,717			2,173
Total revenues	868,026			725,838			1,702,133			1,505,518

Costs and expenses:
Product purchases	707,516			602,166			1,414,870			1,259,508
Plant and transportation operating expense	26,831			22,255			54,530			44,189
Oil and gas exploration and production expense	24,059			19,812			48,955			36,922
Depreciation, depletion and amortization	30,799			22,348			59,877			44,974
(Gain) loss on sale of assets	(1		)	1,639			27			1,639
Selling and administrative expense	17,537			17,255			30,069			27,201
(Earnings) from equity investments	(2,246		)	(1,776		)	(4,380		)	(3,702		)
Loss from early extinguishment of debt	—			10,662			—			10,662
Interest expense	4,033			5,351			7,553			11,153
Total costs and expenses	808,528			699,712			1,611,501			1,432,546

Income before taxes	59,498			26,126			90,632			72,972
Provision for income taxes:
Current	6,172			(1,008		)	13,522			2,535
Deferred	15,697			13,485			19,775			27,068
Total provision for income taxes	21,869			12,477			33,297			29,603

Income before cumulative effect of change in accounting principle	37,629			13,649			57,335			43,369

Cumulative effect of change in accounting principle, net of tax of $2,710	—			—			—			4,714

Net income	37,629			13,649			57,335			48,083

Preferred stock requirements	—			(19		)	—			(835		)

Income attributable to common stock	$	37,629		$	13,630		$	57,335		$	47,248

Net income per share of common stock before cumulative effect of change in accounting principle	$	.51		$	.19		$	.77		$	.60

Cumulative effect of change in accounting principle	$	—		$	—		$	—		$	.07

Earnings per share of common stock	$	.51		$	.19		$	.77		$	.67

Weighted average shares of common stock outstanding	74,234,424			73,158,240			74,191,346			70,942,578

Income attributable to common stock – assuming dilution	$	37,629		$	13,649		$	57,335		$	47,248

Earnings per share of common stock – assuming dilution	$	.50		$	.18		$	.76		$	.65

Weighted average shares of common stock outstanding assuming dilution	75,678,389			75,329,143			75,603,310			72,820,040

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

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 (restated)	—	—	—		—			—			—		57,335			—			57,335
Translation adjustments	—	—	—		—			—			—		—			(2,510		)	(2,510		)
Other comprehensive income
From equity investees	—	—	—		—			—			—		—			77			77
Reclassification adjustment for settled contracts	—	—	—		—			—			—		—			(623		)	(623		)
Changes in fair value of outstanding hedge positions	—	—	—		—			—			—		—			(2,339		)	(2,339		)
Change in estimated ineffectiveness	—	—	—		—			—			—		—			79			79
Fair value of new hedge positions	—	—	—		—			—			—		—			(1,571		)	(1,571		)
Change in accumulated derivative comprehensive income	—	—	—		—			—			—		—			(4,454		)	(4,454		)
Total comprehensive income, net of tax	—	—	—		—			—			—		—			—			50,448
Stock options exercised	171,060	—	17		—			—			2,718		—			—			2,735
Compensation expense from common stock options	—	—	—		—			—			463		—			—			463
Unearned compensation on restricted stock	362,260	—	36		—			(10,741		)	11,168		—			—			463
Tax benefit related to stock options exercised	—	—	—		—			—			907		—			—			907
Dividends declared on common stock	—	—	—		—			—			—		(7,424		)	—			(7,424		)

Balance at June 30, 2005 (restated)	74,612,053	50,032	$	7,483	$	(788	)	$	(10,741	)	$	407,693	$	331,339		$	(2,625	)	$	732,361

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

WESTERN GAS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

GENERAL

We have prepared the accompanying unaudited interim consolidated financial statements under the rules and regulations of the 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/A for the year ended December 31, 2004. The interim Consolidated Financial Statements as of June 30, 2005 and for the three and six-month periods ended June 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 six-months ended June 30, 2005 are not necessarily indicative of the results of operations expected for the year ended December 31, 2005.

In June 2005, we revised our classification in the Statement of Cash Flows for the six months ended June 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 $26.2 million for the six months ended June 30, 2004, with a corresponding decrease in cash flows used in financing activities.

RESTATEMENT OF CONSOLIDATED FINANCIAL STATEMENTS

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 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 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. 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 for the period ended June 30, 2005 as filed on August 9, 2005 (000s):

	Three months ending						Six months ending
	June 30, 2005			June 30, 2004			June 30, 2005			June 30, 2004
Net income as previously reported	$	33,318		$	13,976		$	65,946		$	43,063
Accounting correction for derivatives (pre-tax)	6,830			(465		)	(13,377		)	7,998
Tax impact of above	(2,519		)	138			4,766			(2,978		)
Net income as restated	$	37,629		$	13,649		$	57,335		$	48,083

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 as filed on August 9, 2005. 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

	For the period ending
	June 30, 2005				December 31, 2004
	As		As		As		As
(000s)	Reported		Restated		Reported		Restated
Assets:
Current assets from price risk management activities	17,131		5,970		22,238		19,893
Deferred income tax	—		3,399		—		—
Long-term assets from price risk management activities	539		540		618		249
Total Assets	$	1,918,055	$	1,910,294	$	1,840,112	$	1,837,398

Liabilities and Stockholders’ equity
Current liabilities from price risk management activities	17,474		15,391		11,099		4,321
Deferred income tax	—		—		—		5,618
Long-term liabilities from price risk management activities	1,437		1,436		417		180
Deferred income taxes payable, net	265,755		265,947		247,893		243,835
Total liabilities	1,179,825		1,177,933		1,158,084		1,152,629

Stockholders’ equity
Retained earnings	337,208		331,339		278,687		281,428
Total stockholders’ equity	738,230		732,361		682,028		684,769
Total liabilities and stockholders’ equity	$	1,918,055	$	1,910,294	$	1,840,112	$	1,837,398

Consolidated Statement of Operations

	Three Months Ending,								Six Months Ending,
	June 30, 2005				June 30, 2004				June 30, 2005					June 30, 2004
	As		As		As		As		As		As			As			As
(000s)	Reported		Restated		Reported		Restated		Reported		Restated			Reported			Restated
Revenues:
Price risk management activities	4,375		11,205		3,460		2,995		4,335		(9,043		)	(2,020		)	5,979
Total revenues	$	861,196	$	868,026	$	726,303	$	725,838	$	1,715,511	$	1,702,133		$	1,497,519		$	1,505,518

Income before income taxes	52,668		59,498		26,591		26,126		104,010		90,632			64,973			72,972
Provision for income taxes:
Deferred	13,178		15,697		13,624		13,485		24,542		19,775			24,089			27,068
Total provision for income taxes	19,350		21,869		12,616		12,477		38,064		33,297			26,624			29,603
Income before cumulative effect of change in accounting principle	33,318		37,629		13,975		13,649		65,946		57,335			38,349			43,369
Net income	33,318		37,629		13,975		13,649		65,946		57,335			43,063			48,083
Income attributable to common stock	33,318		37,629		13,956		13,630		65,946		57,335			42,228			47,248
Earnings per share of common stock before cumulative effect of change in accounting principle	0.45		0.51		0.19		0.19		0.89		0.77			0.53			0.60
Earnings per share of common stock	0.45		0.51		0.19		0.19		0.89		0.77			0.60			0.67
Income attributable to common stock - assuming dilution	33,318		37,629		13,975		13,649		65,946		57,335			42,228			47,248
Earnings per share of common stock - assuming dilution	$	0.44	$	0.50	$	0.19	$	0.18	$	0.87	$	0.76		$	0.58		$	0.65

The net impact of this restatement was to adjust Net income by $4.3 million and ($326,000) for the three months ended June 30, 2005 and 2004, respectively, and ($8.6) million and $5.0 million for each of the six months ended June 30, 2005 and 2004, respectively. The net impact of this restatement was to adjust Earnings per share of common stock – assuming dilution by $0.06 and ($0.01) for the three months ended June 30, 2005 and 2004, respectively, and ($0.11) and $0.7 for each of the six months ended June 30, 2005 and 2004, respectively.

EQUITY TRANSACTIONS

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. After these redemptions, the $2.625 cumulative convertible preferred stock was delisted from trading on the New York Stock Exchange and was deregistered by the SEC.

In the second quarter of 2005, we granted approximately 362,000 shares of restricted common stock to our employees. In conjunction with the grant of restricted stock, we will record as compensation expense over the three-year vesting period, the value of the restricted stock on the date of grant. Accordingly, we recorded unearned compensation of $10.7 million in Stockholders’ equity and compensation expense of $463,000 in the second quarter of 2005.

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 June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
Common Stock	$	3,732	$	3,684	$	7,425	$	5,449
Preferred Stock	—		19		—		835
Total Dividends Declared	$	3,732	$	3,703	$	7,425	$	6,284

Dividends Declared Per Share:
Common Stock	$	0.05	$	0.05	$	0.10	$	0.08
Preferred Stock	—		$	0.66	—		$	1.31

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 June 30,		Six Months Ended June 30,
	2005	2004	2005	2004
Weighted average shares of common stock outstanding	74,234,424	73,158,240	74,191,346	70,942,578
Potential common shares from:
Common stock options and restricted stock	1,443,965	1,921,653	1,411,964	1,877,462
$2.625 Cumulative Convertible Preferred Stock	—	249,250	—	—
Weighted average shares of common stock outstanding - assuming dilution	75,678,389	75,329,143	75,603,310	72,820,040

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 income at June 30, 2005 were unrealized losses of $4.0 million from the fair value of derivatives designated as cash flow hedges and unrealized gains of $2.5 million of cumulative foreign currency translation adjustments.

Included in Accumulated other comprehensive income at June 30, 2004 were unrealized losses of $3.5 million from the fair value of derivatives designated as cash flow hedges and unrealized gains of $1.7 million of cumulative foreign currency translation adjustments.

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 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, 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 June 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 from the pipeline.

OTHER MATTERS

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 six months ended June 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 second quarter and six months ended June 30, 2004 were reduced by $0.09 and $0.10, respectively. 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 both the three and six months ended June 30, 2005. For additional information, 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 36.8% and 36.7%, respectively, during the quarter and six months ended June 30, 2005 as compared to 47.8% and 40.6%, respectively, in the same periods of 2004. This decrease is due to the civil penalty paid to the CFTC in 2004, which was non-deductible for tax purposes.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

A net loss was recognized in earnings through Sale of residue gas and Sale of natural gas liquids during the three and six months ended June 30, 2005 from hedging activities of $657,000 and $170,000, respectively. Also during these periods we recognized a loss from hedge ineffectiveness of $37,000 and $125,000, respectively, through Price risk management activities.

The gains and losses currently reflected in Accumulated other comprehensive income will be reclassified to earnings as the hedged gas or NGLs is sold. Based on the prices for our products on June 30, 2005, approximately $4.0 million of losses in Accumulated other comprehensive income will be reclassified to earnings, of which $2.5 million will be reclassified in the remainder of 2005.

SUPPLEMENTARY CASH FLOW INFORMATION

Interest paid was $11.7 million and $13.3 million for the six months ended June 30, 2005 and 2004, respectively. A total of $11.0 million and $7.7 million was paid in income taxes in the six months ended June 30, 2005 and 2004, respectively. Asset retirement obligations of $7.7 million were recorded for capitalized assets for the six months ended June 30, 2005. The asset retirement and associated obligations are non-cash transactions for presentation on the Consolidated Statement of Cash Flows.

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 second quarter of 2005, we granted approximately 747,000 options to purchase our common stock at the market price based on the average closing price for the ten days prior to grant and approximately 362,000 shares of restricted common stock to our employees. In conjunction with the grant of restricted stock, we will record as compensation expense over the three-year vesting period, the value of the restricted stock on the date of grant. Accordingly, we recorded unearned compensation expense of $463,000 in the second quarter of 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 six months ended June 30, 2005 and 2004, respectively.

	Quarter Ended June 30,		Six Months Ended June 30,
	2005	2004	2005	2004
2002 Plan	54,000	40,000	137,000	75,000
2002 Directors’ Plan	32,000	32,000	32,000	32,000
2005 Plan	747,000	—	747,000	—
Total options granted	833,000	72,000	916,000	107,000

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

	Quarter Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
2002 Plan	$	14.04	$	14.89	$	15.01	$	13.20
2002 Directors’ Plan	$	14.79	$	12.13	$	14.79	$	12.13
2005 Plan	$	13.25	—		$	13.25	—

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

	Quarter Ended June 30, 2005									Six Months Ended June 30, 2005
	2002 Plan			2002 Directors’ Plan			2005 Plan			2002 Plan			2002 Directors’ Plan			2005 Plan
Risk-free interest rate	4.30		%	4.38		%	4.27		%	4.35		%	4.38		%	4.27		%
Expected life (in years)	7			7			7			7			7			7
Expected volatility	37		%	37		%	37		%	37		%	37		%	37		%
Expected dividends (quarterly)	$	0.05		$	0.05		$	0.05		$	0.05		$	0.05		$	0.05

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 June 30,
	2005		2005		2004		2004
	As Reported Restated		Pro Forma Restated		As Reported Restated		Pro Forma Restated
Net income	$	37,629	$	35,062	$	13,649	$	12,523
Net income attributable to common stock	37,629		35,062		13,630		12,504
Earnings per share of common stock	0.51		0.47		0.19		0.17
Earnings per share of common stock - assuming dilution	0.50		0.46		0.18		0.17
Stock-based employee compensation cost, net of related tax effects, included in net income	412		—		188		—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	2,979	$	—	$	1,314

	Six Months Ended June 30,
	2005		2005		2004		2004
	As Reported Restated		Pro Forma Restated		As Reported Restated		Pro Forma Restated
Net income	$	57,335	$	53,089	$	48,083	$	45,816
Net income attributable to common stock	57,335		53,089		47,248		44,981
Earnings per share of common stock	0.77		0.71		0.67		0.63
Earnings per share of common stock -assuming dilution	0.76		0.70		0.65		0.63
Stock-based employee compensation cost, net of related tax effects, included in net income	585		—		300		—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	4,831	$	—	$	2,567

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, collectively with the Marketing and Transportation segments referred to as the midstream operations, 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 68% of our plant facilities’ gross margin, or revenues at the plant less product purchases, for the month of June 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 21% of our plant facilities’ gross margin for the month of June 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 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 11% of our plant facilities’ gross margin for the month of June 2005 was pursuant to contracts with “keepwhole” arrangements or wellhead purchase contracts. Under these 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.

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

Segment Information. The following tables set forth our segment information as of and for the quarter and six months ended June 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. In the interim segment information, prior period Corporate Plant operating and transportation expense of $(484,000) and $451,000 for the quarter and six months ended June 30, 2004, respectively, has been reclassified to the Gas Gathering and Processing segment to conform to the presentation used in 2005.

Quarter ended June 30, 2005

Restated

	Gas Gathering and Processing			Exploration and Production		Marketing		Transportation			Other			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	956		$	3,040	$	673,235	$	409		$	—		$	—		$	677,640
Sale of natural gas liquids	3			—		150,581		—			—			—			150,584
Equity hedges:
Residue	68			378		—		—			—			—			446
Liquids	(1,103		)	—		—		—			—			—			(1,103		)
Gathering, processing and transportation revenue	26,154			—		—		1,669			—			—			27,823
Total revenues from unaffiliated customers:	26,078			3,418		823,816		2,078			—			—			855,390

Inter-segment sales	300,326			78,376		24,940		3,353			10			(407,005		)	—
Price risk management activities	(37		)	—		11,242		—			—			—			11,205
Interest Income	—			4		18		—			12,435			(12,457		)	—
Other, net	1,089			118		3		—			221			—			1,431
Total revenues	327,456			81,916		860,019		5,431			12,666			(419,462		)	868,026

Product purchases	252,906			1,084		849,636		776			—			(396,886		)	707,516
Plant and transportation operating expense	25,852			164		144		1,653			—			(982		)	26,831
Oil and gas exploration and production expense	—			33,155		—		—			—			(9,096		)	24,059
(Earnings) from equity investments	(2,246		)	—		—		—			—			—			(2,246		)
Segment operating profit	50,944			47,513		10,239		3,002			12,666			(12,498		)	111,866

Depreciation, depletion and amortization	11,594			16,899		35		436			1,835			—			30,799
Selling and administrative expense	—			—		—		—			17,546			(9		)	17,537
(Gain) loss from sale of assets	(213		)	61		—		151			—			—			(1		)
Interest expense	—			3		587		(194		)	16,094			(12,457		)	4,033
Income before tax	$	39,563		$	30,550	$	9,617	$	2,609		$	(22,809	)	$	(32	)	$	59,498

Identifiable assets:
Equity investments	$	32,675		$	—	$	—	$	1,150		$	857,160		$	(854,901	)	$	36,084
Property and equipment	725,336			539,888		13		39,154			60,438			(568		)	1,364,261
Other allocated assets	38,465			13,960		150,709		35,804			339,206			(68,195		)	509,949
Total identifiable assets	$	796,476		$	553,848	$	150,722	$	76,108		$	1,256,804		$	(923,664	)	$	1,910,294

Quarter ended June 30, 2004

Restated

	Gas Gathering and Processing			Exploration and Production			Marketing		Transportation			Other			Eliminating Entries			Total

Revenues from unaffiliated customers:
Sale of gas	$	965		$	1,544		$	591,336	$	303		$	—		$	—		$	594,148
Sale of natural gas liquids	2			—			104,605		—			—			—			104,607
Equity hedges:
Residue	116			1,617			—		—			—			—			1,733
Liquids	(2,586		)	—			—		—			—			—			(2,586		)
Gathering, processing and transportation revenue	22,756			—			—		1,654			—			—			24,410
Total revenues from unaffiliated customers:	21,253			3,161			695,941		1,957			—			—			722,312

Inter-segment sales	251,772			60,425			14,796		3,711			—			(330,704		)	—
Price risk management activities	(5		)	—			3,000		—			—			—			2,995
Interest Income	—			3			—		—			4,333			(4,336		)	—
Other, net	471			—			7		47			6			—			531
Total revenues	273,491			63,589			713,744		5,715			4,339			(335,040		)	725,838

Product purchases	212,543			304			710,825		1,374			—			(322,880		)	602,166
Plant and transportation operating expense	21,189			(178		)	70		1,812			—			(638		)	22,255
Oil and gas exploration and production expense	—			26,904			—		—			—			(7,092		)	19,812
(Earnings) from equity investments	(1,776		)	—			—		—			—			—			(1,776		)
Segment operating profit	41,535			36,559			2,849		2,529			4,339			(4,430		)	83,381

Depreciation, depletion and amortization	9,211			10,875			35		408			1,819			—			22,348
Selling and administrative expense	—			—			—		—			17,266			(11		)	17,255
(Gain) loss from sale of assets	244			(196		)	—		—			292			1,299			1,639
Loss from early extinguishment of debt	—			—			—		—			10,662						10,662
Interest expense	—			8			82		(71		)	9,668			(4,336		)	5,351

Income before tax	$	32,080		$	25,872		$	2,732	$	2,192		$	(35,368	)	$	(1,382	)	$	26,126

Identifiable assets:
Equity investments	$	2,469		$	—		$	—	$	—		$	697,196		$	(662,882	)	$	36,783
Property and equipment	623,982			321,009			1,253		38,225			56,240			(569		)	1,040,140
Other allocated assets	2,739			7,004			122,284		44,951			281,912			(38,451		)	420,439
Total identifiable assets	$	629,190		$	328,013		$	123,537	$	83,176		$	1,035,348		$	(701,902	)	$	1,497,362

Six months ended June 30, 2005

Restated

	Gas Gathering and Processing			Exploration and Production			Marketing			Transportation			Other			Eliminating Entries			Total

Revenues from unaffiliated customers:
Sale of gas	$	730		$	7,075		$	1,363,568		$	1,154		$	—		$	—		$	1,372,527
Sale of natural gas liquids	51			—			284,347			—									284,398
Equity hedges:
Residue	175			1,604			—			—			—			—			1,779
Liquids	(1,949		)	—			—			—			—			—			(1,949		)
Gathering, processing and transportation revenue	48,446			(162		)	—			3,419			—			—			51,703
Total revenues from unaffiliated customers:	47,453			8,517			1,647,915			4,573			—			—			1,708,458

Inter-segment sales	576,179			147,643			42,644			6,795			20			(773,281		)	—
Price risk management activities	(125		)	—			(8,918		)	—			—			—			(9,043		)
Interest Income	—			8			18			—			21,937			(21,963		)	—
Other, net	2,194			120			3			—			401			—			2,718
Total revenues	625,701			156,288			1,681,662			11,368			22,358			(795,244		)	1,702,133

Product purchases	474,358			2,364			1,689,680			1,634			—			(753,166		)	1,414,870
Plant and transportation operating expense	52,491			168			146			3,464			—			(1,739		)	54,530
Oil and gas exploration and production expense	—			67,294			—			—			—			(18,339		)	48,955
(Earnings) from equity investments	(4,380		)	—			—			—			—			—			(4,380		)
Segment operating profit (loss)	103,232			86,462			(8,164		)	6,270			22,358			(22,000		)	188,158

Depreciation, depletion and amortization	22,872			32,528			71			839			3,567			—			59,877
Selling and administrative expense	—			—			—			—			30,089			(20		)	30,069
(Gain) loss from sale of assets	(182		)	61			—			148			—			—			27
Interest expense	5			4			589			(348		)	29,266			(21,963		)	7,553

Income before tax	$	80,537		$	53,869		$	(8,824	)	$	5,631		$	(40,564	)	$	(17	)	$	90,632

Identifiable assets:
Equity investments	$	32,675		$	—		$	—		$	1,150		$	857,160		$	(854,901	)	$	36,084
Property and equipment	725,336			539,888			13			39,154			60,438			(568		)	1,364,261
Other allocated assets	38,465			13,960			150,709			35,804			339,206			(68,195		)	509,949
Total identifiable assets	$	796,476		$	553,848		$	150,722		$	76,108		$	1,256,804		$	(923,664	)	$	1,910,294

Six months ended June 30, 2004

Restated

	Gas Gathering and Processing			Exploration and Production			Marketing			Transportation			Other			Eliminating Entries			Total

Revenues from unaffiliated customers:
Sale of gas	$	1,889		$	3,783		$	1,251,272		$	865		$	—		$	—		$	1,257,809
Sale of natural gas liquids	3			—			199,911			—									199,914
Equity hedges:
Residue	265			3,117			—			—			—			—			3,382
Liquids	(4,978		)	—			—			—			—			—			(4,978		)
Gathering, processing and transportation revenue	37,842			—			—			3,397			—			—			41,239
Total revenues from unaffiliated customers:	35,021			6,900			1,451,183			4,262			—			—			1,497,366

Inter-segment sales	509,424			116,356			27,601			7,145			—			(660,526		)	—
Price risk management activities	(26		)	—			6,005			—			—			—			5,979
Interest Income	—			3			—			—			8,342			(8,345		)	—
Other, net	812			1			5			47			1,308			—			2,173
Total revenues	545,231			123,260			1,484,794			11,454			9,650			(668,871		)	1,505,518

Product purchases	428,120			932			1,470,694			2,955			—			(643,193		)	1,259,508
Plant and transportation operating expense	42,288			70			(172		)	3,572			—			(1,569		)	44,189
Oil and gas exploration and production expense	—			52,585			—			—			—			(15,663		)	36,922
(Earnings) from equity investments	(3,702		)	—			—			—			—			—			(3,702		)
Segment operating profit	78,525			69,673			14,272			4,927			9,650			(8,446		)	168,601

Depreciation, depletion and amortization	18,212			21,866			52			824			4,020			—			44,974
Selling and administrative expense	—			—			—			—			27,227			(26		)	27,201
(Gain) loss from sale of assets	244			(196		)	—			—			292			1,299			1,639
Loss from early extinguishment of debt	—			—			—			—			10,662			—			10,662
Interest expense	—			42			177			(133		)	19,412			(8,345		)	11,153
Income before tax	$	60,069		$	47,961		$	14,043		$	4,236		$	(51,963	)	$	(1,374	)	$	72,972

Identifiable assets:
Equity investments	$	2,469		$	—		$	—		$	—		$	697,196		$	(662,882	)	$	36,783
Property and equipment	623,982			321,009			1,253			38,225			56,240			(569		)	1,040,140
Other allocated assets	2,739			7,004			122,284			44,951			281,912			(38,451		)	420,439
Total identifiable assets	$	629,190		$	328,013		$	123,537		$	83,176		$	1,035,348		$	(701,902	)	$	1,497,362

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. This settlement is subject to approval by the court and was accrued in the second quarter of 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 31 U. S. C. 3729 (a) (7) of the False 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.

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.

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. The following pronouncements have been issued but not yet adopted.

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.

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 beginning after June 15, 2005, and will be applied prospectively. 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.

EITF No. 04-13. At its November 2004 meeting, the Emerging Issues Task Force, or EITF, of the FASB began discussion of 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. This issue is currently on the agenda for the September 2005 meeting of the EITF. The implementation of this EITF, if approved, may reduce revenues and related costs but will not have a material impact on our results of operations, financial position or cash flows.

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 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 June 30, 2005 and 2004, we recorded revenues of $34.6 million and $24.2 million, respectively, and product purchases of $30.8 million and $20.6 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 six

months ended June 30, 2005 and 2004, we recorded revenues of $63.3 million and $49.4 million, respectively, and product purchases of $57.5 million and $44.5 million, respectively, for these types of transactions.

FSP FAS 19-1. In April 2005, the FASB Staff issued FASB Staff Position, or FSP, FAS 19-1, “Accounting for Suspended Well Costs.” This FSP amends SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” as it pertains to capitalizing the costs of drilling exploratory wells pending determination of whether the well has found proved reserves. FSP, FAS 19-1 states that exploratory well costs should continue to be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the entity is making progress assessing reserves and the economic and operational viability of the project. We adopted this FSP in the second quarter of 2005, as required, and it did not have a material impact on our results of operations, financial position or cash flows.

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 proved reserves. A determination of whether a well has found proved reserves is made shortly after drilling is completed. The determination is based on 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 proved 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) 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 six months ended June 30, 2005 (000s).

	Six Months Ended June 30, 2005
Beginning balance at December 31, 2004	$	48,546
Additions to capitalized exploratory well costs pending the determination of proved reserves	37,613
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves	(4,290		)
Capitalized exploratory well costs charged to expense	(1,599		)
Ending balance	$	80,270

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.

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 beginning after December 31, 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 on January 1, 2006 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.

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 six months ended June 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/A, 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 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. 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 six months ending June 30, 2005 and 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/A (amounts in thousands, except per share amounts):

	Three months ending										Six months ending
	June 30, 2005				June 30, 2004						June 30, 2005				June 30, 2004
	As		As		As			As			As		As		As		As
	Reported		Restated		Reported			Restated			Reported		Restated		Reported		Restated
Total revenues	$	861,196	$	868,026	$	726,304		$	725,838		$	1,715,511	$	1,702,133	$	1,497,519	$	1,505,518
Income before taxes	52,668		59,498		26,592			26,126			104,010		90,632		64,973		72,972
Net income	33,318		37,629		13,976			13,649			65,946		57,335		43,063		48,083
Earnings per share-assuming dilution	0.44		0.50		0.19			0.18			0.87		0.76		0.58		0.65
Cash flow from operating activities	$	42,706	$	42,706	$	(36,364	)	$	(36,364	)	$	160,102	$	160,102	$	88,132	$	88,132

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, 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 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 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 second quarter of 2005, our average production sold was 167 MMcfe per day, which is a 13% increase over the daily average production volume sold in the second quarter of 2004.

We continue to seek to add additional upstream core projects that are focused on Rocky Mountain natural gas. 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 with operations primarily focused in the Rockies. 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 in the Western Canadian Sedimentary Basin. Overall, at June 30, 2005, we have acquired the drilling rights on approximately 1.6 million net acres in various Rocky Mountain 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 second quarter of 2005 remained relatively constant as compared to the same period in 2004 and averaged a total of 1.4 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 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 six months ended June 30, 2005 compared to the three and six months ended June 30, 2004

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

	Restated								Restated
	Three Months Ended								Six Months Ended
	June 30,						Percent		June 30,						Percent
	2005			2004			Change		2005			2004			Change
Financial results:
Revenues	$	868,026		$	725,838		20		$	1,702,133		$	1,505,518		13
Net income	37,629			13,649			176		57,335			48,083			19
Earnings per share of common stock	0.51			0.19			168		0.77			0.67			15
Earnings per share of common stock - diluted	0.50			0.18			178		0.76			0.65			17
Net cash (used in) provided by operating activities	42,706			(36,364		)	217		160,102			88,132			82
Net cash (used in) investing activities	(76,847		)	(42,529		)	81		(191,088		)	(77,655		)	146
Net cash (used in) provided by financing activities	$	38,454		$	50,012		(23	)	$	36,634		$	(33,707	)	209

Operating data:
Average gas sales (MMcf/D)	1,162			1,190			(2	)	1,231			1,279			(4	)
Average NGL sales (MGal/D)	1,876			1,643			14		1,819			1,627			12
Average gas prices ($/Mcf)	$	6.38		$	5.49		16		$	6.13		$	5.40		14
Average NGL prices ($/Gal)	$	0.88		$	0.68		29		$	0.86		$	0.66		30

Net income increased $24.0 million for the three months ended June 30, 2005, compared to the same period in 2004. The increase in net income was primarily attributable to higher production of equity gas volumes, higher commodity prices in the second quarter of 2005, and mark-to-market non-cash gains from our price risk management activities related to our future sales of gas utilizing our gas storage and gas transportation capacity. In addition, the second quarter of 2004 was negatively impacted by 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. In the second quarter of 2005, we had an increase in operating costs and depreciation, depletion and amortization and an after-tax charge of $3.8 million recorded in connection with a settlement of litigation.

Net income increased $9.3 million for the six months ended June 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, offset in part by mark-to-market non-cash losses from our price risk management activities related to our future sales of gas utilizing our storage and transportation capacity. In addition, the first six months of 2004 were negatively impacted by the 2004 settlement with the CFTC, and the 2004 early extinguishment of long-term debt. 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 $82.2 million to $678.1 million for the three months ended June 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 June 30, 2005 compared to the same period in 2004. Average gas prices realized by us increased $0.89 per Mcf to $6.38 per Mcf for the quarter ended June

30, 2005 compared to the same period in 2004. Included in the realized gas price were approximately $446,000 of gains recognized in the three months ended June 30, 2005 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately 60% of our equity gas for the remainder of 2005 and to a lesser extent in 2006. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average gas sales volumes decreased slightly to 1,162 MMcf per day for the quarter ended June 30, 2005 compared to the same period in 2004.

Revenues from the sale of gas increased $113.1 million to $1,374.3 million for the six months ended June 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 six months ended June 30, 2005, compared to the same period in 2004. Average gas prices realized by us increased $0.73 per Mcf to $6.13 per Mcf for the six months ended June 30, 2005 compared to the same period in 2004. Included in the realized gas price were approximately $1.8 million of gains recognized in the six months ended June 30, 2005 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately 60% of our equity gas for the remainder of 2005 and to a lesser extent in 2006. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average gas sales volumes decreased slightly to 1,231 MMcf per day for the six months ended June 30, 2005 compared to the same period in 2004.

Revenues from the sale of NGLs increased $47.5 million to $149.5 million for the three months ended June 30, 2005 compared to the same period in 2004. This is primarily due to a significant increase in product prices and an increase in sales volumes. Average NGL prices realized by us increased $0.20 per gallon to $0.88 per gallon for the three months ended June 30, 2005 compared to the same period in 2004. Included in the realized NGL price were approximately $1.1 million of losses recognized in the three months ended June 30, 2005 related to futures positions on equity NGL volumes. We have entered into additional futures positions for approximately 30% of our equity NGL production for the remainder of 2005 and to a lesser extent in 2006. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average NGL sales volumes increased 233 MGal per day to 1,876 MGal per day for the three months ended June 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 $87.5 million to $282.5 million for the six months ended June 30, 2005 compared to the same period in 2004. This is primarily due to a significant increase in product prices and an increase in sales volumes. Average NGL prices realized by us increased $0.20 per gallon to $0.86 per gallon for the six months ended June 30, 2005 compared to the same period in 2004. Included in the realized NGL price were approximately $1.9 million of losses recognized in the six months ended June 30, 2005 related to futures positions on equity NGL volumes. We have entered into additional futures positions for approximately 30% of our equity NGL production for the remainder of 2005 and to a lesser extent in 2006. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average NGL sales volumes increased 192 MGal per day to 1,819 MGal per day for the six months ended June 30, 2005 compared to the same period in 2004. This increase is due to the acquisition of several facilities in February 2005.

The effect of Price risk management activities changed from $3.0 million for the quarter ended June 30, 2004 to $11.2 million for the quarter ended June 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 2004 quarter and the impact of those price changes on the fair value of the forward sale derivatives for our gas in storage.

The effect of Price risk management activities changed from $6.0 million for the six months ended June 30, 2004 to ($9.0) million for the six months ended June 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 $105.4 million and $155.4 million for the quarter and six months ended June 30, 2005, respectively, compared to the same periods in 2004. These increases in product purchases were the result of higher product prices. Overall, combined product purchases as a percentage of sales of all products was 86% in both the quarter ended June 30, 2005 and 2004. Combined product purchases as a percentage of sales of all products decreased to 85% for the six months ended June 30, 2005 from 86% in 2004. The reduction in this percentage is primarily the result of a decrease in the sale of third party product and an increase in the sale of equity production.

Plant and transportation operating expense increased by $4.6 million and $10.3 million, respectively, for the three and six months ended June 30, 2005 compared to the same periods in 2004. The increase for the quarter ended June 30, 2005 as

compared to the same period in 2004 was substantially due to increased property tax, labor and repairs and maintenance expenses and the October 2004 and February 2005 asset acquisitions. The increase for the six months ended June 30, 2005 as compared to the same period in 2004 was substantially due to increased property tax, labor and third-party gathering expenses and the October 2004 and February 2005 asset acquisitions.

Oil and gas exploration and production expense increased by $4.2 million and $12.0 million, respectively, for the three and six months ended June 30, 2005 compared to the same periods in 2004. The increase for the quarter ended June 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 six months ended June 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 $0.80 per Mcf and $0.83 per Mcf for the quarter and six months ended June 30, 2005 and LOE in the Powder River Basin coal bed development averaged $0.92 per Mcf and $0.89 per Mcf in the quarter and six months ended June 30, 2005, respectively. In the Powder River Basin, these represent increases of $0.14 and $0.10 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.

Depreciation, depletion and amortization increased by $8.5 million and $14.9 million, respectively, for the three and six months ended June 30, 2005 as compared to the same periods in 2004. For the quarter ended June 30, 2005 as compared to the same period in 2004, we had a $2.4 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 $6.0 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 six months ended June 30, 2005 as compared to the same period in 2004, we had a $4.7 million increase in DD&A in our midstream operations and a $10.6 million increase in our upstream operations primarily due to those items mentioned above.

Selling and administrative expenses increased by $282,000 and $2.9 million for the three and six months ended June 30, 2005 as compared to the same period in 2004. The increase in selling and administrative expenses for the six months ended June 30, 2005 as compared to 2004 was primarily the result of increased administrative salaries, insurance, audit expenses, and compensation expense related to our restricted stock plan. Additionally, a charge of $5.9 million was recorded in the second quarter of 2005 in connection with a settlement of litigation and a charge associated with a settlement with the CFTC of $7.0 million was recorded in the second quarter of 2004.

The Total provision for income taxes, as a percentage of Income before taxes was approximately 36.7% and 36.6%, respectively, during the quarter and six months ended June 30, 2005 as compared to 47.4% and 41.0%, respectively, in same periods of 2004. This decrease is 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 $72.0 million in the first six months of 2005 compared to the same period in 2004. This increase was primarily due to the increase in net income and the timing of cash receipts and payables.

Cash flows used in investing activities increased by $113.4 million in the first six 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 used in financing activities decreased by $70.3 million in the first six months of 2005 compared to the same period in 2004. This decrease was due to a significant reduction in our outstanding debt in the first six months of 2004, as compared to the utilization of funds provided by financing activities to fund our capital investments in 2005.

Segment Information

Gas Gathering, Processing and Treating. The Gas Gathering, Processing and Treating segment realized segment-operating profit of $103.2 million for the six months ended June 30, 2005 compared to $78.5 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 June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
Gross Margin ($/Mcf)(1)	$	0.60	$	0.53	$	0.62	$	0.51
Segment Plant operating and transportation expense ($/Mcf)	0.20		0.18		0.21		0.18
Net Margin ($/Mcf)	0.40		0.35		0.41		0.33
Average gas volumes gathered (MMcf/D)	1,394		1,314		1,375		1,313

(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 $86.5 million for the six months ended June 30, 2005 compared to $69.7 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 six months of 2005, our production of natural gas as compared to the same period in 2004 increased by 13% to 29.9 Bcfe. The following table sets forth the average sales price received for our oil and gas products in the quarter and six months ended June 30, 2005 and 2004.

	Quarter Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
Average sales price: (1)
Oil ($/Bbl)	$	47.88	$	33.89	$	45.58	$	33.68
Gas ($/Mcf), excluding the effect of hedging positions	5.34		4.59		5.11		4.49
Gas ($/Mcf), including the effect of hedging positions	5.36		4.71		5.17		4.61

Production and other costs:
Lease operating expense ($/Mcfe)	0.80		0.66		0.83		0.65
Production tax expense ($/Mcfe)	0.59		0.48		0.53		0.50
Gathering and transportation expense ($/Mcfe)
Inter-segment charges	0.60		0.53		0.61		0.59
Third-party charges	0.16		0.20		0.18		0.13
Other expenses ($/Mcfe)	0.04		0.02		0.02		0.01
Total costs ($/Mcfe)	$	2.19	$	1.89	$	2.17	$	1.88

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

Marketing. The Marketing segment realized segment-operating loss of $8.2 million for the six months ended June 30, 2005 compared to a segment-operating profit of $14.3 million in the same period of 2004. The decrease was due to lower price differentials between the Rocky Mountain and Mid Continent market centers, which reduced the Marketing segment’s ability to capitalize on our transportation contracts, and by non-cash mark-to-market losses from our price risk management activities related to our 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 $6.3 million for the six months ended June 30, 2005 compared to $4.9 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 Notes to Consolidated Financial Statements (Unaudited) in Item 1 of this Form 10-Q/A 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 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 are all expected to have significant influences on our future net cash provided by operating activities. Additionally, our future growth will be dependent upon 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, and the availability of foreign oil and gas, 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.

We believe that the amounts available to be borrowed under our financing facilities, together with 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 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 July 2005, we utilized amounts available under our revolving credit facility to fund a scheduled principal repayment of $10.0 million under our master shelf agreement.

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

Sources of funds:
Borrowings under our revolving credit facility	$	1,789,015
Borrowings under our master shelf agreement	25,000
Proceeds from the dispositions of property and equipment	1,411
Net cash provided by operating activities	160,102
Distributions from equity investments	613
Change in outstanding checks	6,335
Proceeds from exercise of common stock options	2,735
Total sources of funds	$	1,985,211
Uses of funds:
Payments related to long-term debt (including debt issue costs)	$	1,754,055
Capital expenditures	193,112
Payments made under our master shelf agreement	25,000
Common dividends paid	7,396
Total uses of funds	$	1,979,563

Capital Investment Program. We currently anticipate capital expenditures in 2005 of approximately $376.4 million. Overall, capital expenditures in the Powder River Basin CBM development and in the Greater Green River Basin operations represent 34% and 29%, 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 six months ended June 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)	$	132.8	$	61.5
Exploration and production and lease acquisition activities	204.3		102.8
Acquisition of Greater Green River Basin midstream assets	28.0		28.0
Information technology and other items	3.0		2.4
Capitalized interest and overhead	8.3		6.0
Total Capital Expenditures	$	376.4	$	200.7

(1) Includes $13.7 million budgeted in 2005 and $3.0 million expended in the six months ended June 30, 2005 for maintaining existing facilities.

Contractual Commitments and Obligations

Contractual Cash Obligations. A summary of our contractual cash obligations as of June 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	$	4,316	$	439	$	1,931	$	1,946	$	—
Operating Leases	78,616		8,900		32,871		25,037		11,808
Firm Transportation Capacity Agreements	232,468		19,547		72,325		59,440		81,156
Firm Storage Capacity Agreements	30,198		4,621		11,605		5,045		8,927
Long-term Debt	417,000		10,000		20,000		262,000		125,000
Interest on Long-term Debt (1)	98,780		10,495		39,995		32,399		15,891
Total Contractual Cash Obligations	$	861,378	$	54,002	$	178,727	$	385,867	$	242,782

(1) The interest rate assumed on the revolving credit facility at June 30, 2005 is 4.5% per annum.

Guarantee of Fort Union Project Financing. We own a 13% 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 $44.9 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 June 30, 2005, the fixed fees associated with our existing contracts for firm transportation capacity during 2005 will average approximately $0.16 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 June 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 June 30, 2005 had an average term of 34 months. At June 30, 2005, we held gas in our contracted storage facilities and in imbalances of approximately 18.8 Bcf at an average cost of $6.05 per Mcf compared to 14.5 Bcf at an average cost of $5.33 per Mcf at June 30, 2004. These positions are for storage withdrawals within the next 12 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. These agreements for storage capacity are not reflected on our Consolidated Balance Sheet.

From time to time, we lease NGL storage space at major trading locations to facilitate the distribution of products. At June 30, 2005, we held NGLs in storage at various third-party facilities of 2,917 MGal, consisting primarily of propane and ethane, at an average cost of $0.32 per gallon compared to 2,755 MGal at an average cost of $0.28 per gallon at June 30, 2004.

Long-term Debt

Revolving Credit Facility. The commitment under the revolving credit facility totals $500 million and matures in June 2009. At June 30, 2005, $262.0 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.

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 pay a quarterly commitment fee ranging between 0.20% and 0.375%, depending on our debt to capitalization ratio. This fee is paid on unused amounts of the commitment. At June 30, 2005, the interest rate payable on borrowings under this facility was approximately 4.5% 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.

Master Shelf Agreement. Amounts outstanding under our master shelf agreement at July 31, 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.

In July 2005, we funded a scheduled payment of $10.0 million on these notes with a borrowing under our revolving credit facility.

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 June 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	1,041,000	531,000	4,603	2,179	113
Jonah/Pinedale Field	178,000	45,000	254	29	36
San Juan Basin	27,000	26,000	147	127	10
Sand Wash Basin	141,000	134,000	19	19	5
Denver-Julesburg Basin	393,000	339,000	9	9	—
Other	592,000	516,000	13	3	1
Total	2,372,000	1,591,000	5,045	2,366	165

* Average for the six months ended June 30, 2005.

Drilling Results. The following table sets forth the number of wells we drilled during the six months ended June 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.

		Six Months Ended June 30,
		2005		2004
Productive Area	Type of Well Drilled	Gross	Net	Gross	Net
Powder River Basin CBM	Productive	365	181	309	159

Jonah/Pinedale Field	Productive	44	4	22	2
	Dry exploratory	1	0	0	0

San Juan Basin	Productive	27	25	0	0

Sand Wash Basin	Productive	0	0	4	4
	Dry exploratory	1	1	1	1

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 113 MMcf per day in the first six months of 2005.

Our production from the Big George coal continues to increase and was 108 MMcf per day gross at June 30, 2005, or 45 MMcf per day net, from the All Night Creek Unit, Pleasantville, SG Palo, Bullwhacker, Schoonover and Kingsbury Unit areas. In the Big George coal, as of July 2005, we had 878 gross wells dewatering and producing gas, 473 gross wells dewatering and 653 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 final requirements of the DEQ, we have installed and tested various types of water treatment facilities and 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.

Our 2005 capital budget for the Powder River Basin coal bed project is estimated at $81.2 million for the drilling of 850 gross wells, of which $56.0 million was spent in the first six 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. An estimated 640 wells of the 850 well program will be on federal leaseholds and require drilling permits from the BLM. The remaining 210 well locations are on fee or state leaseholds. Together with our co-developer, as of July 31, 2005, we have drilling permits approved for 557, or 87% of the federal wells planned for 2005. Federal drilling permit applications for another 389 locations have been submitted to the BLM. Timely receipt of these permits would allow us to complete our planned 2005 drilling program, and a portion of our 2006 drilling program, on federal leaseholds.

Approximately 300 gross wells in our 2005-drilling program will require permits to treat produced water. The remainder of the wells to be drilled in 2005 will require more conventional types of water discharge permits, such as reservoir containment or surface discharge. To date, we, together with our co-developer in this area, have received water discharge permits from the DEQ for approximately 71% of the wells we plan to drill in 2005. An additional 293 permit applications have been submitted to the DEQ which, when combined with permits received, is more than enough necessary to complete our 2005 drilling program. Historically, the DEQ permit process has required approximately 120 to 150 days from initial submittal to final approval. There is, however, no assurance as to the future timing of the receipt of drilling and water discharge permits, 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 National Environmental Policy Act, or NEPA. This Order has been 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.

On August 10, 2004, the Tenth Circuit Court of Appeals issued its decision in Pennaco Energy, Inc. v. United States Department of the Interior. The court upheld a decision by the Interior Board of Land Appeals, or IBLA, that the BLM had not complied with the NEPA in issuing three federal leases to Pennaco Energy, Inc. in the Powder River Basin for coalbed methane development. We are not a party to the case, and the IBLA and Tenth Circuit decisions do not directly address any federal leases held by us. In order to resolve the issues raised in the Pennaco decision and related issues, the BLM filed for and received public comment on two proposed environmental assessments. After completion of the environmental assessments, we were advised that the BLM believes the issues raised in the Pennaco decision will be resolved. We cannot predict what other actions the Department of Interior or third parties might take in response to this matter, or how the decision and actions taken by the BLM in response to the decision may affect the pace of federal leasing or permitting and development in the Powder River Basin.

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 have asked the court for a “review of the issuance” of these leases. We cannot predict what actions, if any, the Department of the Interior, third parties, or the court might take in response to this case, or how these actions may affect the pace of federal drilling or permitting and development of the Powder River Basin.

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 80 gross wells, or approximately nine net wells, on the Pinedale Anticline. Our capital budget for 2005 in the Pinedale Anticline area provides for expenditures of approximately $47.9 million for drilling costs and production equipment, of which $23.9 million was spent in the first six months of 2005. Due to drilling and regulatory uncertainties, which are beyond our control, 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, 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. We currently plan to integrate portions of the acquired systems into our Red Desert plant and our Table Rock, Wamsutter and Desert Springs gathering systems during the remainder of 2005.

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. We currently expect that this facility will be operational in the second quarter of 2006.

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

	Year	Gas	Gas	Average for the Six Months Ended June 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	79	—
Midkiff/Benedum	1949	2,344	165	145	93	858
Mitchell Puckett Treating (5)	1972	126	120	36	22	1
Wyoming
Coal Bed Methane Gathering	1990	1,369	548	391	354	—
Desert Springs Gathering	1979	65	10	6	5	21
Fort Union Gas Gathering(12)	1999	167	635	484	484	—
Granger Complex (6)(7)(8)	1987	714	325	287	248	389
Granger Straddle Plant	2004	—	200	138	—	10
Hilight Complex (6)	1969	658	124	17	12	61
Kitty/Amos Draw (6)	1969	321	17	5	3	24
Newcastle (6)	1981	146	5	3	2	21
Patrick Draw(6) (9)	1997	284	150	28	24	61
Red Desert (6)	1979	127	42	18	31	57
Rendezvous (10)	2001	238	325	331	331	—
Reno Junction (7)	1991	—	—	—	—	116
Table Rock Gathering	1979	100	20	12	12	—
Wamsutter Gathering (11)	1979	243	50	48	43	26
Wind River Gathering	1979	137	80	48	47	—
Oklahoma
Chaney Dell/Westana	1966	3,359	175	197	175	308
New Mexico
San Juan River (5)	1955	277	60	26	21	37
Utah
Four Corners Gathering	1988	104	15	3	2	15
Yellow Creek (9) (13)	1985	—	—	—	—	73
Total		11,168	3,346	2,310	1,988	2,078

(1)	Our interest in all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%); Fort Union (13%) 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 June 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.
(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)	The Granger Complex includes the Lincoln Road facility. The volume information for this facility is reported with the volume information for Granger.
(9)	This facility was acquired in a transaction, which was completed on February 1, 2005.
(10)	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.
(11)	A portion of the gas gathered by the Wamsutter gas gathering system is delivered to our Red Desert facility and is included with the volume information reported for Red Desert.
(12)	A portion of the gas gathered by Fort Union is also reported under Coal Bed Methane Gathering.
(13)	NGL fractionation facility that receives product from third parties via liquids pipeline and truck.

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 six 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 June 30, 2005.

			Average for the Six Months Ended June 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	138
MGTC	1963	251	18	10
Total		514	148	148

(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.

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. At June 30, 2005, we had $15.1 million of margin deposits outstanding.

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. 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, terminated several long-term marketing obligations, negotiated accelerated payment terms with several customers, 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.

We enter into derivatives for the future sale or purchase of natural gas to use our storage and transportation capacity. These transactions utilizing our capacity are economic hedges, but are not afforded hedge accounting treatment. Therefore, the non-cash mark-to-market of these economic hedges will fluctuate through earnings with changes in market prices. 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.

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 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 six months of 2005, we recognized a loss of $125,000 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 June 30, 2005, we held gas in our contracted storage facilities and in imbalances of approximately 18.8 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 $18.8 million and a $1.00 decrease in the forward price of gas in the anticipated month of withdrawal will increase pre-tax earnings by $18.8 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.

Outstanding Equity Hedge Positions and the Associated Basis for 2005 and 2006. The following table details our hedge positions as of June 30, 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 $312,000 as of June 30, 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.	Mid-Continent – 40,000 MMBtu per day with an average basis price of $0.55 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

Account balances related to hedging transactions (designated as cash flow hedges under SFAS 133) at June 30, 2005 were $2.9 million in Current assets from price risk management activities, $8.4 million in Current liabilities from price risk management activities, $1.0 million in Liabilities from price risk management activities, ($2.3) million in Deferred income taxes payable, net, and a $4.0 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Stockholders’ equity. Approximately $2.5 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 change in our derivative position from December 31, 2004 to June 30, 2005 is as follows (dollars in thousands):

Fair value of contracts outstanding at December 31, 2004 (restated)	$	15,640
Decrease in value due to change in price	(7,767		)
Decrease in value due to new contracts entered into during the period	(9,552		)
Gains realized during the period from existing and new contracts	(8,640		)
Changes in fair value attributable to changes in valuation techniques	—
Fair value of contracts outstanding at June 30, 2005 (restated)	$	(10,319	)

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

	Fair Value of Contracts at June 30, 2005 (restated)
Source of Fair Value	Total Fair Value			Maturing In 2005			Maturing In 2006-2007			Maturing In 2008-2009		Maturing Thereafter
Exchange published prices	$	(4,867	)	$	(810	)	$	(4,057	)	—		—
Other actively quoted prices (1)	3,619			3,348			247			$	24	—
Other valuation methods (2)	(9,071		)	(6,411		)	(2,660		)	—		—
Total fair value	$	(10,319	)	$	(3,873	)	$	(6,470	)	$	24	—

(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 June 30, 2005, we had sold forward contracts for $33.0 million in Canadian dollars in exchange for $27.0 million in United States dollars, and the fair market value of these contracts was a gain of $36,000 in United States dollars.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of 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 June 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/A.

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 June 30, 2005, that have materially affected, 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.

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/A and incorporated by reference in this Item 1.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The following matters were voted on at our Annual Meeting of Stockholders held on May 6, 2005:

Brion G. Wise, Richard B. Robinson and Peter A. Dea were elected as class one directors to serve until their terms expire in 2008 and until their successors have been elected. The results of the election were as follows.

	Votes For	Votes Withheld
Peter A. Dea	67,569,057	2,753,169
Richard B. Robinson	66,497,342	3,824,884
Brion G. Wise	66,682,697	3,639,529

Our other directors whose terms did not expire on the date of the Annual Meeting, James A. Senty, Walter L. Stonehocker, Joseph E. Reid, Bill M. Sanderson, Ward Sauvage, and, Dean Phillips continued in office. Mr. Sauvage subsequently resigned as a member of our board of directors on July 15, 2005 due to health reasons.

Our 2005 Stock Incentive Plan, which provides for the issuance of options to purchase 2.5 million shares of common stock and 1.5 million shares of restricted common stock, was approved as follows:

		Votes For		Votes Against		Abstentions		Broker Non-votes
2005 Stock Incentive Plan		54,960,656		6,358,752		116,102		8,886,716

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		Western Gas Resources, Inc. 2005 Stock Incentive Plan (previously filed as Exhibit 4.7 to our Registration Statement on Form S-8 filed on May 31, 2005 and incorporated herein by reference).*

10.2		Amendment to Employment Agreement of Peter A. Dea (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on May 23, 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.

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)

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		Western Gas Resources, Inc. 2005 Stock Incentive Plan (previously filed as Exhibit 4.7 to our Registration Statement on Form S-8 filed on May 31, 2005 and incorporated herein by reference).*

10.2		Amendment to Employment Agreement of Peter A. Dea (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on May 23, 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.