10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2006
	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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer x Accelerated Filer o Non-Accelerated Filer o

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

On August 4, 2006, there were 76,179,795 shares of the registrant’s common stock outstanding.

Western Gas Resources, Inc.

Form 10-Q

Table of Contents

PART I – Financial Information
Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheet – June 30, 2006 and December 31, 2005
	Consolidated Statement of Cash Flows - Six Months Ended June 30, 2006 and 2005
	Consolidated Statement of Operations - Three and Six Months Ended June 30, 2006 and 2005
	Consolidated Statement of Changes in Stockholders’ Equity - Six Months Ended June 30, 2006
	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

2

PART I - FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Unaudited)

(Dollars in thousands, except share data)

	June 30,			December 31,
	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	3,892		$	27,198
Trade accounts receivable, net	286,206			413,004
Margin deposits	16,744			31,217
Inventory	115,779			136,968
Assets from price risk management activities	50,253			48,988
Deferred tax asset	—			4,808
Other	20,081			14,010
Total current assets	492,955			676,193
Property and equipment:
Gas gathering, processing and transportation	1,365,944			1,290,278
Oil and gas properties and equipment (successful efforts method)	825,305			666,306
Construction in progress	450,189			286,641
	2,641,438			2,243,225
Less: Accumulated depreciation, depletion and amortization	(751,235		)	(684,904		)
Total property and equipment, net	1,890,203			1,558,321
Other assets:
Gas purchase contracts (net of accumulated amortization of $43,458 and $42,583, respectively)	30,450			32,071
Assets from price risk management activities	6,787			5,495
Investments in joint ventures	38,478			36,791
Other	28,730			25,763
Total other assets	104,445			100,120
TOTAL ASSETS	$	2,487,603		$	2,334,634
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	350,064		$	463,113
Accrued expenses	75,502			106,542
Liabilities from price risk management activities	24,111			34,343
Deferred tax liability	6,509			—
Dividends payable	5,699			5,660
Total current liabilities	461,885			609,658
Long-term debt	572,000			430,000
Liabilities from price risk management activities	3,080			—
Other long-term liabilities	67,682			66,427
Deferred income taxes, net	356,602			325,090
Total liabilities	1,461,249			1,431,175
Stockholders’ equity:
Common stock, par value $0.10; 100,000,000 shares authorized; 76,297,417 and 75,375,134 shares issued, respectively	7,628			7,565
Treasury stock, at cost; 50,032 common shares in treasury	(788		)	(788		)
Deferred compensation	—			(9,244		)
Additional paid-in capital	445,589			429,007
Retained earnings	564,699			471,860
Accumulated other comprehensive income	9,226			5,059
Total stockholders’ equity	1,026,354			903,459
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,487,603		$	2,334,634

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

3

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Six Months Ended June 30,
	2006			2005
Reconciliation of net income to net cash provided by operating activities:
Net income	$	104,231		$	57,335
Add income items that do not affect operating cash flows:
Depreciation, depletion and amortization	71,286			59,877
Loss on sale of assets	1,024			27
Deferred income taxes	44,900			19,775
Excess tax benefits from share-based payment awards	(2,379		)	—
Non-cash change in fair value of derivatives	(5,465		)	17,614
Compensation expense from restricted stock and stock options	11,637			926
Other non-cash items, net	(587		)	(1,532		)
Adjustments to working capital to arrive at net cash provided by operating activities:
Decrease in trade accounts receivable	123,555			71,601
(Increase) decrease in margin deposits	3,957			(8,946		)
Decrease in product inventory	22,457			1,933
(Increase) in other current assets	(18,267		)	(11,379		)
(Increase) in other assets and liabilities, net	(962		)	(565		)
(Decrease) in accounts payable	(84,504		)	(57,156		)
Increase (decrease) in accrued expenses	(5,219		)	10,592
Net cash provided by operating activities	265,664			160,102
Cash flows from investing activities:
Purchases of property and equipment, including acquisitions	(399,351		)	(193,112		)
Distributions from equity investees	—			613
Proceeds from the disposition of property and equipment	1,255			1,411
Net cash used in investing activities	(398,096		)	(191,088		)
Cash flows from financing activities:
Net proceeds from exercise of common stock options	10,321			2,735
Excess tax benefits from share-based payment awards	2,379			—
Change in outstanding checks	(34,207		)	6,335
Borrowings on revolving credit facility	2,415,700			1,789,015
Payments on revolving credit facility	(2,273,700		)	(1,754,015		)
Borrowings on long-term debt	—			25,000
Payments on long-term debt	—			(25,000		)
Debt issue costs paid	(14		)	(40		)
Dividends paid	(11,353		)	(7,396		)
Net cash provided by financing activities	109,126			36,634
Net increase (decrease) in cash and cash equivalents	(23,306		)	5,648
Cash and cash equivalents at beginning of period	27,198			390
Cash and cash equivalents at end of period	$	3,892		$	6,038

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

4

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Revenues:
Sale of gas	$	576,716		$	678,087		$	1,348,377		$	1,374,306
Sale of natural gas liquids	171,986			149,481			339,402			282,450
Gathering, processing and transportation revenue	27,573			27,823			54,273			51,703
Price risk management activities	9,233			11,205			30,213			(9,043		)
Other	1,666			1,430			3,990			2,717
Total revenues	787,174			868,026			1,776,255			1,702,133
Costs and expenses:
Product purchases	592,861			707,516			1,368,993			1,414,870
Plant and transportation operating expense	29,963			26,831			62,179			54,530
Oil and gas exploration and production expense	35,909			24,059			64,427			48,955
Depreciation, depletion and amortization	35,924			30,799			71,286			59,877
Selling and administrative expense	21,296			17,536			41,144			30,096
(Earnings) from equity investments	(2,440		)	(2,246		)	(4,814		)	(4,380		)
Interest expense	5,419			4,033			8,604			7,553
Total costs and expenses	718,932			808,528			1,611,819			1,611,501
Income before taxes	68,242			59,498			164,436			90,632
Provision for income taxes:
Current	3,018			6,172			15,305			13,522
Deferred	22,855			15,697			44,900			19,775
Total provision for income taxes	25,873			21,869			60,205			33,297
Net income	$	42,369		$	37,629		$	104,231		$	57,335
Earnings per share of common stock	$	.56		$	.51		$	1.38		$	.77
Weighted average shares of common stock outstanding	75,459,422			74,234,424			75,269,376			74,191,346
Income attributable to common stock – assuming dilution	$	42,369		$	37,629		$	104,231		$	57,335
Earnings per share of common stock – assuming dilution	$	.55		$	.50		$	1.36		$	.76
Weighted average shares of common stock outstanding - assuming dilution	76,718,838			75,678,389			76,509,330			75,603,310

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

5

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(Dollars in thousands, except share amounts)

																	Accumulated
		Shares															Other			Total
	Shares	of Common									Additional						Comprehensive			Stock-
	of Common	Stock	Common		Treasury			Deferred			Paid-In			Retained			Income			holders’
	Stock	in Treasury	Stock		Stock			Compensation			Capital			Earnings			Net of Tax			Equity
Balance at December 31, 2005	75,375,134	50,032	$	7,565	$	(788	)	$	(9,244	)	$	429,007		$	471,860		$	5,059		$		903,459
Comprehensive income:
Net income, first six months of 2006	—	—	—		—			—			—			104,231			—			104,231
Translation adjustments	—	—	—		—			—			—			—			848			848
Other comprehensive income
From equity investees	—	—	—		—			—			—			—			84			84
Reclassification adjustment for settled contracts	—	—	—		—			—			—			—			(4,822		)	(4,822			)
Changes in fair value of outstanding hedge positions	—	—	—		—			—			—			—			14,518			14,518
Change in estimated ineffectiveness	—	—	—		—			—			—			—			320			320
Fair value of new hedge positions	—	—	—		—			—			—			—			(6,781		)	(6,781			)
Change in accumulated derivative comprehensive income	—	—	—		—			—			—			—			3,235			3,235
Total comprehensive income, net of tax	—	—	—		—			—			—			—			—			108,398
Stock options exercised	625,600	—	63		—			—			10,258			—			—			10,321
Compensation expense from common stock options	296,683	—	—		—			—			7,853			—			—			7,853
Excess tax benefit related to stock options exercised	—	—	—		—			—			3,931			—			—			3,931
Effect of change in accounting principle	—	—	—		—			9,244			(9,244		)	—			—			—
Compensation expense from restricted stock	—	—	—		—						3,784			—			—			3,784
Dividends declared on common stock	—	—	—		—			—			—			(11,392		)	—			(11,392			)
Balance at June 30, 2006	76,297,417	50,032	$	7,628	$	(788	)	$	—		$	445,589		$	564,699		$	9,226		$	1,026,354

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

6

WESTERN GAS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 – GENERAL

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

The interim consolidated financial statements presented herein should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2005. Reference is also made to our 2005 Form 10-K for definitions of terms used in this quarterly report on Form 10-Q. The interim Consolidated Financial Statements as of June 30, 2006 and for the three-month and six month periods ended June 30, 2006 and 2005 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, 2006 are not necessarily indicative of the results of operations expected for the year ended December 31, 2006.

Proposed Merger of our Company. On June 23, 2006, we announced that we had entered into a merger agreement with Anadarko Petroleum Corporation, or Anadarko, whereby it is proposed that we will be merged with a wholly owned subsidiary of Anadarko. Our stockholders will receive $61.00 per common share in cash in the merger. The merger agreement has been approved by each company’s Board of Directors and was filed with the SEC on Form 8-K. We have scheduled a special meeting of our stockholders for August 23, 2006 to vote on, adopt the merger agreement and approve the merger. The merger is also subject to the satisfaction of customary closing conditions, including the receipt of necessary regulatory and governmental approvals. The merger will be completed as soon as practicable following satisfaction of these conditions, which could be as early as the end of August 2006. Should the merger be completed, our common stock will be de-listed with the New York Stock Exchange, or NYSE, and we will file a Form 15 with the SEC to deregister our common stock. Certain of our directors, officers and other stockholders, who collectively hold approximately 17.3 percent of Western’s outstanding shares, have entered into agreements to vote in favor of the merger.

The closing of our proposed merger would be an event of default under our revolving credit facility, which would entitle the lenders to terminate their commitments and demand payment of all outstanding and unpaid amounts there under.  Further, our master shelf agreement contains cross default provisions, which would be triggered by the default under the revolving credit facility.  Therefore, upon the closing of the merger, the acquirer must renegotiate these agreements or repay all amounts due under them.  Also, the closing of our proposed merger is also an event of default under some of our operating leases, which will entitle our counterparties to terminate their commitments and require a return of the related equipment.  Therefore, on or prior to the closing of the merger, the acquirer must renegotiate these agreements.

This Form 10-Q includes discussion regarding events that will or may trigger or occur upon completion of the merger. If the merger is not completed these events will not occur. In addition, the timing of the completion of the merger will affect the timing of these events. See also the first paragraph under Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the effect of the proposed merger on certain forward-looking statements included in this Form 10-Q.

Earnings Per Share of Common Stock. Earnings per share of common stock are computed by dividing net income by the weighted average shares of common stock outstanding. Earnings per share of common stock - - assuming dilution is computed by dividing net income by the weighted average shares of common stock outstanding as adjusted for potential common shares.

The following table presents the dividends declared by us on our common stock (dollars in thousands, except per share amounts):

	Quarter Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Total dividends declared	$	5,750	$	3,732	$	11,392	$	7,425
Dividends declared per share of common stock	$	0.075	$	0.05	$	0.15	$	0.10

Common stock options granted 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,
	2006	2005	2006	2005
Weighted average shares of common stock outstanding	75,459,422	74,234,424	75,269,376	74,191,346
Potential common shares from common stock options	1,259,416	1,443,965	1,239,954	1,411,964
Weighted average shares of common stock outstanding - assuming dilution	76,718,838	75,678,389	76,509,330	75,603,310

7

The calculation of fully diluted earnings per share reflects potential common shares, if dilutive.

Accumulated Other Comprehensive Income. Included in Accumulated other comprehensive income at June 30, 2006 were unrealized gains of $5.9 million, which is net of $3.4 million of deferred taxes, from the fair value of derivatives designated as cash flow hedges and unrealized gains of $848,000, which is net of $486,000 of deferred taxes, as a result of cumulative foreign currency translation adjustments.

The gains currently reflected in Accumulated other comprehensive income from the fair value of derivatives designated as cash flow hedges will be reclassified to earnings as the hedged gas or NGLs are sold. Based on the prices for our products on June 30, 2006, approximately $5.9 million of gains in Accumulated other comprehensive income will be reclassified to earnings, of which $1.4 million will be reclassified in the remainder of 2006.

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 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, 2006 and 2005 were immaterial. For our marketing activities we utilize mark-to-market accounting for our derivatives. In the 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 received into the pipeline.

At its September 2005 meeting, the Emerging Issues Task Force, or EITF, of the FASB approved Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.”  This Issue addresses the question of when it is appropriate to measure non-monetary purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. EITF 04-13 requires that two or more exchange transactions involving inventory with the same counterparty that are entered into in contemplation of one another should be combined for the purposes of evaluating the effect of APB Opinion No. 29, “Accounting for Nonmonetary Transactions”. This EITF is effective for transactions entered into or modified in the first interim or annual period beginning after March 15, 2006, which for us was the quarter ended June 30, 2006. To the extent transactions are required to be netted, this results in a reduction of revenues and costs by an equal amount, but the netting has no impact on net income 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 04-13, these transactions are required to be reported on a sales net of purchases basis. For the quarter and six months ended June 30, 2006, we reduced revenues and product purchases by $31.2 million 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.

Supplementary Cash Flow Information. Interest paid was $14.6 million and $11.7 million for the six months ended June 30, 2006 and 2005, respectively. A total of $16.5 million and $11.0 million was paid in income taxes in the six months ended June 30, 2006 and 2005, respectively. Asset retirement obligation assets and liabilities of $3.4 million and $7.7 million were recorded for the six months ended June 30, 2006 and 2005, respectively. The asset retirement and associated obligations are non-cash transactions for presentation on the Consolidated Statement of Cash Flows.

Property Acquisition. In March 2006, we acquired certain coal bed methane, or CBM, properties and related gathering assets in the Big George fairway of the Powder River Basin of Wyoming for an adjusted purchase price of $138.6 million. This acquisition was funded with amounts available under our revolving credit facility. The purchase price included the drilling rights on approximately 40,000 gross and net acres and 110 drilled wells. These properties had no production in the six months ended June 30, 2006 as approximately 70 of the drilled wells are currently dewatering and the remaining 40 wells are awaiting hookup.

8

NOTE 2 - DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

A net gain was recognized in earnings through Sale of gas and Sale of natural gas liquids during the three and six months ended June 30, 2006 from hedging activities of $12.3 million and $20.8 million, respectively. 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.

In the second quarter of 2006, in order to properly align our hedged volumes of natural gas to our forecasted equity production, we discontinued hedge treatment on financial instruments for 30 MMcf per day of natural gas as the anticipated transaction is no longer probable. As a result, a pre-tax gain of $2.8 million was reclassified into earnings from Accumulated other comprehensive income.

NOTE 3 – ADOPTION OF SFAS 123(R)

On January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment”, or SFAS 123(R), which requires the measurement and recognition of compensation expense for all share-based payment awards (including stock options) made to employees and directors based on estimated fair values. SFAS 123(R) supersedes our previous accounting under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”, or APB 25, for periods beginning in fiscal 2006. In March 2005, the SEC issued Staff Accounting Bulletin No. 107, or SAB 107, relating to SFAS 123(R). We considered the guidance of SAB 107 in our adoption of SFAS 123(R).

We adopted SFAS 123(R) using the modified prospective transition method, which requires the application of the accounting standard as of January 1, 2006. In accordance with the modified prospective transition method, our Consolidated Financial Statements for prior periods are not restated to reflect, and do not include, any impact of SFAS 123(R). We did not modify any outstanding stock options in anticipation of the adoption of SFAS 123(R). The effect of the change in accounting principle resulting from the adoption of SFAS 123(R) was recognized in our financial statements through the elimination of previously recognized deferred compensation costs, with offsetting amounts recorded in the Additional paid-in capital account within Stockholders’ equity.

Stock-based compensation expense recognized under SFAS 123(R) for the three and six months ended June 30, 2006 related to employee stock options, including compensation from our 2006 grants, is as presented in the following table.

(Amounts in thousands, except per share amounts)	Quarter ended June 30, 2006			Six Months ended June 30, 2006
Incremental stock-based compensation expense recognized through earnings	$	4,058		$	6,900
Related deferred income tax benefit	(419		)	(958		)
Decrease in net income	3,639			6,538
Decrease in earnings per share of common stock	0.05			0.08
Decrease in earnings per share of common stock – assuming dilution	0.05			0.08
Stock-based compensation expense capitalized	$	536		$	953

SFAS 123(R) requires us to estimate the fair value of stock options on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods in our Consolidated Statement of Operations. Prior to the adoption of SFAS 123(R), we accounted for stock-based awards to employees and directors using the intrinsic value method in accordance with APB 25 as then allowed under Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation”, or SFAS 123. Under the intrinsic value method, with the exception of the options granted under the Chief Executive Officer and President’s Plan and our restricted stock, no stock-based compensation expense had been recognized in our Consolidated Statement of Operations, because the exercise price of our stock options granted to employees and directors equaled the fair market value of the underlying stock at the date of grant.

Stock-based compensation expense to be recognized is based on the fair value of those share-based payment awards that are ultimately expected to vest during the period. Stock-based compensation expense recognized in our Consolidated Statement of Operations for the three and six months ended June 30, 2006 includes compensation expense for share-based payment awards granted in 2006 and granted prior to, but not yet vested, as of January 1, 2006. Compensation expense for the awards granted prior to January 1, 2006 is based on the grant date fair value estimated in accordance with the pro forma provisions of SFAS 123. Compensation expense for the share-based payment awards granted subsequent to December 31, 2005 was based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R). In conjunction with the adoption of SFAS 123(R), we continued

9

our method of attributing the value of stock-based compensation using the straight-line single option method. As stock-based compensation expense recognized in the Consolidated Statement of Operations for the three and six months ended June 30, 2006 is based on awards ultimately expected to vest, it is reduced for estimated forfeitures. SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. At June 30, 2006, the compensation expense related to non-vested awards to be recognized in future periods totaled $23.0 million. The weighted average period over which this expense is expected to be recognized is 2.1 years; however, in connection with the proposed merger of Western with Anadarko, all outstanding options will fully vest and convert to the right to receive a cash payment from the acquirer at the closing of the transaction.

In accordance with the adoption of SFAS 123(R), we continue to use the Black-Scholes option pricing model for the valuation of share-based awards. Our determination of fair value of share-based payment awards on the date of grant using the Black-Scholes model is affected by our stock price as well as assumptions regarding variables, including, but not limited to, our expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise behaviors. In our estimate of the fair value of the share-based payment awards, we utilize historical volatility of our common stock over 250 weeks. In our opinion, the historical volatility and the Black-Scholes model provide an appropriate measure of the fair value of our employee stock options.

On November 10, 2005, the Financial Accounting Standards Board, issued FASB Staff Position, or FSP, No. 123(R)-3, “Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards.”  This FSP allows us to take up to one year from the later of our initial adoption of SFAS 123(R) or the effective date of the FSP to evaluate the available transition alternative related to the accounting for the tax effects of share-based payment awards that are partially or fully-vested as of the adoption date. We have not yet elected which transition method we will utilize.

NOTE 4 – SHARE BASED COMPENSATION

In the first six months of 2006, we granted our employees and directors options to purchase approximately 733,000 shares of our common stock at the market (as defined in the plans) based on the average closing price for the ten days prior to grant, and approximately 297,000 shares of restricted common stock. In the first six months of 2005, we granted options to purchase 916,000 shares of our common stock at the market 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 and directors. In all cases, the grant date was the date on which the grants were approved by our board of directors, or the date on which an employee commenced employment. 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 and on disqualifying dispositions of qualified stock options. For the six months ended June 30, 2006 and 2005, we recognized a tax benefit from our stock options of $3.9 million and $900,000, respectively.

The following is a summary of the options granted to purchase our common stock and the weighted average fair value per share of the options granted during the three and six months ended June 30, 2006 and 2005, respectively.

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
2002 Plan
Options granted	10,465		54,200		16,665		137,200
Weighted average fair value per share	$	15.62	$	14.04	$	15.41	$	15.01
2005 Plan
Options granted	—		746,726		660,026		746,726
Weighted average fair value per share	—		$	13.25	$	19.17	$	13.25
2002 Directors Plan
Options granted	36,000		32,000		56,000		32,000
Weighted average fair value per share	$	19.80	$	14.79	$	19.68	$	14.79

During the six months ended June 30, 2006, the values for the options granted were estimated using the Black-Scholes option-pricing model with the following assumptions:

	2002 Plan			2005 Plan			2002 Directors Plan
Risk-free interest rate	5.26		%	5.11		%	5.34		%
Expected life (in years)	4.6			4.6			4.6
Expected volatility	32		%	32		%	32		%
Expected dividends (quarterly)	$	0.075		$	0.075		$	0.075

The following table summarizes the number of stock options exercisable and available for grant under our benefit plans at June 30, 2006:

10

	Per Share Price Range	1997 Plan	1999 Plan	1999 Directors Plan	CEO Plan	2002 Plan	2002 Directors Plan	2005 Plan
Exercisable:
June 30, 2006	$0.01-5.00	1,202	—	2,600	—	—	—	—
	$5.01-10.00	1,800	—	—	—	—	—	—
	$10.01-15.00	—	6,002	—	450,000	—	—	—
	$15.01-20.00	—	286,384	—	—	441,008	56,000	—
	$20.01-25.00	—	—	—	—	1,112	—	—
	$25.01-30.00	—	30,366	—	—	175,587	18,667	—
	$30.01-35.00	—	—	—	—	44,445	9,333	199,730
	$35.01-40.00	—	—	—	—	291	—	834
	TOTAL	3,002	322,752	2,600	450,000	662,443	84,000	200,564
Available for Grant:
June 30, 2006		745,204	22,056	—	—	65,262	36,000	1,135,608

The following table summarizes the stock option activity related to options outstanding under our benefit plans during the six months ended June 30, 2006:

	Per Share Price Range	1997 Plan		1999 Plan		1999 Directors Plan		CEO Plan		2002 Plan		2002 Directors Plan	2005 Plan
Balance at 12/31/05		6,002		550,815		6,600		495,000		1,817,154		112,000	744,726
Granted	$43.43-48.51	—		—		—		—		16,665		56,000	660,026
Exercised	$2.76-35.71	(3,000	)	(138,868	)	(4,000	)	(45,000	)	(280,614	)	—	(39,765	)
Forfeited or expired	$16.48-50.05	—		(4,968	)	—		—		(51,426	)	—	(40,360	)
Balance at 6/30/06		3,002		406,979		2,600		450,000		1,501,779		168,000	1,324,627
Weighted-average remaining contractual life (years)		1.6		4.8		0.8		3.3		5.0		5.2	6.0

The following table summarizes the weighted average option exercise price information under our benefit plans during the six months ended June 30, 2006:

	1997 Plan			1999 Plan			1999 Directors Plan			CEO Plan			2002 Plan			2002 Directors Plan		2005 Plan
Balance at December 31, 2005	$	5.11		$	19.32		$	2.76		$	12.51		$	24.31		$	24.99	$	31.86
Granted	—			—			—			—			48.38			49.44		43.43
Exercised	(5.82		)	(17.19		)	(2.76		)	(12.51		)	(21.44		)	—		(31.85		)
Forfeited or expired	—			(28.35		)	—			—			(26.30		)	—		(36.62		)
Balance at June 30, 2006	$	4.41		$	18.13		$	2.76		$	12.51		$	25.05		$	33.14	$	37.48

The total aggregate intrinsic value of options exercised in the first six months of 2006 was approximately $15.1 million. The total aggregate intrinsic value of exercisable options at June 30, 2006 was approximately $68.8 million and the total aggregate intrinsic value of outstanding options at June 30, 2006 was approximately $124.2 million.

The following table summarizes the status of the shares of outstanding restricted stock as of June 30, 2006 and changes during the six months ended June 30, 2006:

	2005 Plan
Balance at 12/31/05	377,565
Granted	296,683
Vested	(114,353		)
Forfeited or expired	(28,773		)
Balance at 6/30/06	531,122
Weighted-average grant date fair value per share of restricted stock	$	41.74
Weighted-average remaining contractual life (years)	1.4

As discussed in Note 3 above, prior to January 1, 2006, we were not required to record compensation expense for share-based payment awards. If we had recorded compensation expense in the second quarter and first six months of 2005 for grants under our stock-based compensation plans consistent with SFAS 123 (R), our Net income, 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):

11

	Quarter Ended June 30,				Six Months Ended June 30,
	2005		2005		2005		2005
	As Reported		Pro Forma		As Reported		Pro Forma
Net income	$	37,629	$	35,062	$	57,335	$	53,089
Net income attributable to common stock	37,629		35,062		57,335		53,089
Earnings per share of common stock	0.51		0.47		0.77		0.71
Earnings per share of common stock - assuming dilution	0.50		0.46		0.76		0.70
Stock-based employee compensation cost, net of related tax effects, included in net income	412		—		585		—
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	$	—	$	4,831

NOTE 5 - SEGMENT REPORTING

We operate in four principal business segments, as follows: 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.

Gathering, Processing and Treating. In the Gathering, Processing and Treating segment, which collectively with the Marketing and Transportation segments are referred to as the midstream operations, we connect producers’ wells (including those of our Exploration and Production segment) to our gathering systems for delivery of natural gas 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 gas and NGLs extracted at most of our facilities. In this segment, we recognize revenue for our services at the time the service is performed.

Substantially all gas flowing through our gathering, processing and treating facilities is supplied under three types of contracts providing for the purchase, gathering, treating or processing of natural gas for periods ranging from one month to 20 years or in some cases for the life of the oil and gas lease. Approximately 64% of our plant facilities’ gross margin, or revenues at the plant less product purchases, or 31% of our plant facilities’ throughput volume for the month of June 2006, was under percentage-of-proceeds agreements where 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. Revenue is recognized under these contracts when the gas or NGLs are sold and the related product purchases are recorded as a percentage of the sale of the product.

Approximately 25% of our plant facilities’ gross margin, or 54% of our plant facilities’ throughput volume, for the month of June 2006 was under 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 or shut in production. Revenue is recognized under these contracts when the related services are rendered.

Approximately 11% of our plant facilities’ gross margin, or 15% of our plant facilities’ throughput volume, for the month of June 2006 was under contracts with keepwhole arrangements or wellhead purchase contracts. Under the keepwhole contracts, we retain the NGLs recovered by the processing facility and keep the producers whole by returning to the producers at the tailgate of the plant an amount of 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. Revenue is recognized under these contracts when the product is sold.

Exploration and Production. The activities of the Exploration and Production segment, also referred to as upstream operations, primarily consist of the exploration and development of gas properties in the Rocky Mountain area, including those where our gathering and/or processing facilities are located. The Marketing segment sells the

12

majority of the production from these properties and remits to the Exploration and Production segment all of the proceeds from the sales of gas and a proportional share of transportation charges. Also included in this segment are our Canadian exploration and development operations, which are conducted through our wholly owned subsidiary Western Gas Resources Canada Company and which are immaterial for separate presentation.

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. The determination of whether a well has found proved reserves 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, 2006 (dollars in thousands).

	Six Months Ended June 30, 2006
Beginning balance at December 31, 2005	$	101,796
Additions to capitalized exploratory well costs pending the determination of proved reserves	68,216
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves	(5,731		)
Capitalized exploratory well costs charged to expense	(342		)
Ending balance at June 30, 2006	$	163,938

Period end capitalized exploratory well costs (000s) and number of gross wells at June 30, 2006 are as follows:

	Exploratory Well Costs		Number of wells
Exploratory well costs capitalized for a period of one year or less	$	107,588	645
Exploratory well costs capitalized for a period of greater than one year	56,350		691
Total exploratory well costs capitalized at June 30, 2006	$	163,938	1,336

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. After these wells are completed, lease-operating costs are incurred. In order to produce gas from the coal seams, a period of dewatering lasting from a few to thirty-six 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 proved. In order to accelerate the dewatering time, we drill additional exploratory wells in these areas.

Marketing. Our Marketing segment markets gas and NGLs extracted at our gathering, processing and treating facilities and produced from our Exploration and Production segment and buys and sells gas and NGLs in the United States and Canada from and to a variety of customers. In this segment, revenues for sales of product are recognized at the time the gas or NGLs are delivered to the customer and title passes. 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 operating margins relative to the sales price. We sell our products under agreements with varying terms and conditions in order to match seasonal and other changes in demand. Also included in this segment are our Canadian marketing operations, which are conducted through our wholly owned subsidiary WGR Canada, Inc. and which are immaterial for separate presentation.

Transportation. The Transportation segment reflects the operations of our MIGC, Inc. and MGTC, Inc. pipelines. The revenue presented in this segment is derived from transportation of gas for our Marketing segment and third parties. In this 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

13

fee is charged based upon volumes received into the pipeline. The Transportation segment’s capacity contracts range in duration from one month to five years.

Segment Information. The following tables set forth our segment information as of and for the three and six months ended June 30, 2006 and 2005 (dollars in thousands). Due to our integrated operations, the use of allocations in the determination of business segment information is necessary. Inter-segment revenues are valued at prices comparable to those of unaffiliated customers.

Quarter Ended June 30, 2006:

	Gas Gathering and Processing			Exploration and Production			Marketing		Transportation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas and NGLs	$	710		$	3,232		$	731,995	$	460		$	—		$	—		$	736,397
Equity hedges	952			11,353			—		—			—			—			12,305
Gathering, processing and transportation revenue	25,654			—			—		1,919			—			—			27,573
Total revenues from unaffiliated customers	27,316			14,585			731,995		2,379			—			—			776,275
Inter-segment revenues	284,573			85,061			15,031		3,125			153			(387,943		)	—
Price risk management activities	(1,630		)	853			10,010		—			—			—			9,233
Interest income and Other, net	1,232			(13		)	10		1			20,112			(19,676		)	1,666
Total revenues	311,491			100,486			757,046		5,505			20,265			(407,619		)	787,174
Product purchases and operating expenses	243,231			48,680			752,794		1,794			155			(387,921		)	658,733
(Earnings) from joint ventures	(2,440		)	—			—		—			—			—			(2,440		)
Segment operating profit	70,700			51,806			4,252		3,711			20,110			(19,698		)	130,881
Depreciation, depletion and amortization	13,472			19,745			2		454			2,251			—			35,924
Selling and administrative expense	(1		)	(46		)	—		27			21,325			(9		)	21,296
Interest expense	—			—			299		(397		)	25,194			(19,677		)	5,419
Income before income taxes	$	57,229		$	32,107		$	3,951	$	3,627		$	(28,660	)	$	(12	)	$	68,242
Identifiable assets:
Property and equipment and other allocated assets	$	917,601		$	903,320		$	215,951	$	80,383		$	428,081		$	(96,211	)	$	2,449,125
Investment in joint ventures	32,073			—			—		1,221			1,128,509			(1,123,325		)	38,478
Total identifiable assets	$	949,674		$	903,320		$	215,951	$	81,604		$	1,556,590		$	(1,219,536	)	$	2,487,603

14

Quarter ended June 30, 2005

	Gas Gathering and Processing			Exploration and Production		Marketing		Transportation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers
Sale of gas and NGLs	$	959		$	3,040	$	823,816	$	409		$	—		$	—		$	828,224
Equity hedges	(1,035		)	378		—		—			—			—			(657		)
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 and Other, net	1,089			122		21		—			12,656			(12,457		)	1,431
Total revenues	327,456			81,916		860,019		5,431			12,666			(419,462		)	868,026
Product purchases and operating expenses	278,758			34,403		849,780		2,429			—			(406,964		)	758,406
(Earnings) from joint ventures	(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	(213		)	61		—		151			17,546			(9		)	17,536
Interest expense	—			3		587		(194		)	16,094			(12,457		)	4,033
Income before income taxes	$	39,563		$	30,550	$	9,617	$	2,609		$	(22,809	)	$	(32	)	$	59,498
Identifiable assets:
Property and equipment and other allocated assets	$	763,801		$	553,848	$	150,722	$	74,958		$	399,644		$	(68,763	)	$	1,874,210
Investment in Joint Ventures	32,675			—		—		1,150			857,160			(854,901		)	36,084
Total identifiable assets	$	796,476		$	553,848	$	150,722	$	76,108		$	1,256,804		$	(923,664	)	$	1,910,294

Six months ended June 30, 2006

	Gas Gathering and Processing			Exploration and Production			Marketing		Transportation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas and NGLs	$	1,009		$	6,143		$	1,658,341	$	1,462		$	—		$	—		$	1,666,955
Equity hedges	2,053			18,771			—		—									20,824
Gathering, processing and transportation revenue	50,516			—			—		3,757			—			—			54,273
Total revenues from unaffiliated customers	53,578			24,914			1,658,341		5,219			—			—			1,742,052
Inter-segment sales	617,272			186,587			41,849		6,467			268			(852,443		)	—
Price risk management activities	(1,755		)	(2,604		)	34,572		—			—			—			30,213
Interest income and Other, net	2,874			82			13		1			37,770			(36,750		)	3,990
Total revenues	671,969			208,979			1,734,775		11,687			38,038			(889,193		)	1,776,255
Product purchases and operating expense	549,850			89,036			1,705,265		3,930			273			(852,755		)	1,495,599
(Earnings) from joint ventures	(4,814		)	—			—		—			—			—			(4,814		)
Segment operating profit (loss)	126,933			119,943			29,510		7,757			37,765			(36,438		)	285,470
Depreciation, depletion and amortization	27,076			38,881			3		917			4,409			—			71,286
Selling and administrative expense	(4		)	740			—		292			40,133			(17		)	41,144
Interest expense	—			—			729		(709		)	45,333			(36,749		)	8,604
Income before income taxes	$	99,861		$	80,322		$	28,778	$	7,257		$	(52,110	)	$	328		$	164,436
Identifiable assets:
Property and equipment and other allocated assets	$	917,601		$	903,320		$	215,951	$	80,383		$	428,081		$	(96,211	)	$	2,449,125
Investment in Joint Ventures	32,073			—			—		1,221			1,128,509			(1,123,325		)	38,478
Total identifiable assets	$	949,674		$	903,320		$	215,951	$	81,604		$	1,556,590		$	(1,219,536	)	$	2,487,603

15

Six months ended June 30, 2005

	Gas Gathering and Processing			Exploration and Production			Marketing			Transportation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas and NGLs	$	781		$	7,075		$	1,647,915		$	1,154		$	—		$	—		$	1,656,925
Equity hedges	(1,774		)	1,604			—			—			—			—			(170		)
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 and Other, net	2,194			128			21			—			22,338			(21,963		)	2,718
Total revenues	625,701			156,288			1,681,662			11,368			22,358			(795,244		)	1,702,133
Product purchases and operating expenses	526,849			69,826			1,689,826			5,098			—			(773,244		)	1,518,355
(Earnings) from joint ventures	(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	(182		)	61			—			148			30,089			(20		)	30,096
Interest expense	5			4			589			(348		)	29,266			(21,963		)	7,553
Income before income taxes	$	80,537		$	53,869		$	(8,824	)	$	5,631		$	(40,564	)	$	(17	)	$	90,632
Identifiable assets:
Property and equipment and other allocated assets	$	763,801		$	553,848		$	150,722		$	74,958		$	399,644		$	(68,763	)	$	1,874,210
Investment in Joint Ventures	32,675			—			—			1,150			857,160			(854,901		)	36,084
Total identifiable assets	$	796,476		$	553,848		$	150,722		$	76,108		$	1,256,804		$	(923,664	)	$	1,910,294

NOTE 6 - LEGAL PROCEEDINGS

Doyle and Margaret M. Hartman, et al. v. Questar Exploration and Production Company et al. In the District Court of Sublette County, Wyoming, Civil Action No. 2006-6843. On March 31, 2006, the plaintiffs filed a complaint against a group of ten defendants, including our subsidiary Lance Oil & Gas Company, Inc. The plaintiffs claim that they hold a five percent net profits interest which they allege was created in 1954 and burdened certain oil and gas leases in the original federal Pinedale Unit in the Pinedale Anticline. The relief sought by the plaintiffs includes a declaration that they hold a valid, continuing net profits interest applicable to certain identified leases, enforcement of the net profits interest, compensatory damages, an accounting of the status of the net profits interest, and interest and penalties under the Wyoming Royalty Payment Act.

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

Price, et al. v. Gas Pipelines, Western Gas Resources, Inc., et al., District Court, Stevens County, Kansas, Case No. 99-C-30. We are a defendant in litigation filed on September 23, 1999, along with numerous other natural gas companies, in which Mr. Price is claiming an under measurement of gas and Btu volumes throughout the country. We, along with other natural gas companies, filed a motion to dismiss for failure to state a claim. The court denied these motions to dismiss. The court denied plaintiff’s motion for certification as a class and, in the third

16

quarter of 2003, the plaintiff amended and refiled for certification as a class. On May 12, 2003, Mr. Price filed a further claim, Will Price et al v. Western Gas Resources, Inc. et al., District Court, Stevens County, Kansas, Case No. 03C23, relating to certain matters previously removed from the foregoing action.

In re: Western States Wholesale Natural Gas Antitrust Litigation, J.P. Morgan Trust Company, National Association, in its Capacity as Trustee of FLI Liquidating Trust v. The Williams Companies, Inc., et al., United States District Court, District of Nevada, MDL 1566 CV-S-03-1431-PMP. On October 17, 2005, the plaintiff, in its capacity as the liquidating trustee of the successor in interest to Farmland Industries, Inc., filed an amended complaint, joining us and other defendants to this action, originally filed in the District Court of Wyandotte County, Kansas. The defendants removed the case to the U.S. District Court for the District of Kansas, following which the Judicial Panel on Multi District Litigation entered a transfer order centralizing the action in the U.S. District Court for the District of Nevada for coordinated and consolidated pretrial proceedings. On April 21, 2006, the plaintiff’s motion to remand to Kansas state court was denied. The complaint claims that the defendants violated the Kansas Restraint of Trade Act by reporting allegedly “misleading or knowingly inaccurate reports concerning trade information” to trade publications that compile and publish indices of natural gas prices for natural gas trading hubs throughout the United States. The complaint asserts that these alleged activities had the effect of increasing prices charged by the defendants for natural gas and preventing full and free competition. The plaintiff seeks to recover damages in the amount of the full consideration of its purchases of natural gas during the time period from January 1, 2000 through December 31, 2001, together with its costs of litigation including attorney’s fees.

Learjet, Inc., Cross Oil Refining & Marketing, Inc. Topeka Unified School District 501, on Behalf of Themselves and All Other Similarly Situated Direct Purchasers of Natural Gas in the State of Kansas v. Oneok, Inc. et al, In the District Court of Wyandotte County, Kansas, Civil Action No. 05-CV-1500. On November 4, 2005, the plaintiffs, on behalf of themselves and all others similarly situated, filed an amended Petition for Damages, joining us and other defendants to this action. The Petition claims that the defendants violated the Kansas Restraint of Trade Act by reporting allegedly “misleading or knowingly inaccurate reports concerning trade information” to trade publications that compile and publish indices of natural gas prices for natural gas trading hubs throughout the United States. The complaint asserts that the allegedly anticompetitive effect of the defendant’s actions was to artificially inflate the prices paid by the plaintiffs for natural gas. The plaintiffs are bringing the action as a class action on behalf of all persons and entities in Kansas who made direct purchases of natural gas, for their own use and or consumption, during the time period from January 1, 2000 through October 31, 2002. The plaintiffs are seeking judgment for the full consideration of their purchases of natural gas purchased during such time period, together with costs of litigation including attorney’s fees.

In the Matter of the Notice of Violation, Docket Number 3852-06, Issued to Lance Oil & Gas Company, Inc., Department of Environmental Quality, Water Quality Division, State of Wyoming. On January 26, 2006, we received a Notice of Violation issued by the State of Wyoming Department of Environmental Quality, Water Quality Division, for the un-permitted discharge of coal bed methane produced water at our Spotted Horse Facility in Campbell County. We have undertaken remedial steps to address the items contained in the Notice of Violation and, in May 2006, we paid a settlement in the amount of $100,000.

In the Matter of the Notice of Violation, WES-1252-0501, Environment Department, Air Quality Bureau, State of New Mexico. On March 6, 2006, we received a Notice of Violation pertaining to operations at our San Juan River Gas Plant located west of Farmington, New Mexico, containing two alleged violations. On April 4, 2006, we met with the Environment Department to discuss the notices and any potential monetary penalties. This matter is still pending.

In addition to the above claims, we are involved in various other litigation and administrative proceedings arising in the normal course of business. While the outcome of claims in litigation is inherently uncertain, and it is not possible to predict the ultimate outcome, we intend to vigorously contest the allegations in the previously described matters. 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 results of operations, financial position, or cash flows.

NOTE 7 - 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.

17

SFAS No. 155. In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments, an Amendment of SFAS No. 133 and No. 140”. This statement resolves issues addressed in SFAS Implementation Issue D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.”  This statement is effective in the annual period commencing after September 15, 2006. We do not believe that the adoption of this statement will have a material impact on our results of operation, financial position or cash flows.

EITF No. 06-3. At its May 2006 meeting, the Emerging Issues Task Force, or EITF, of the FASB approved Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation).”  The scope of this issue includes any tax assessed by a governmental authority that is imposed on a revenue producing transaction between a seller and a customer. This EITF is effective for periods beginning after December 15, 2006 and requires that the presentation of taxes on either a gross or net basis is an accounting policy decision that should be disclosed in the footnotes along with the amount of such taxes. The adoption of this EITF will not have a material impact on our results of operations, financial position or cash flows.

FIN No. 48. In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109.”  This Interpretation provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding derecognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not expect that this Interpretation will have a material impact on our financial position, results of operations or cash flows.

18

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, 2006 and 2005. You should also refer to our interim consolidated financial statements and notes thereto included elsewhere in this document. This section, as well as other sections in this Form 10-Q, contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by the use of forward-looking terminology, such as “may,” “intend,” “will,” “expect,” “anticipate,” “estimate,” or “continue” or the negative thereof or other variations thereon or comparable terminology. In addition to the important factors referred to herein, numerous factors affecting the gas processing industry generally and in the specific markets for gas and NGLs in which we operate, could cause actual results to differ materially from those in such forward-looking statements. In the event that the proposed merger is completed, on and from the date of such merger, these type of forward-looking statements concerning proposed future activities or plans referred to in these forward-looking statements may not occur.

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, the Sand Wash Basin in Colorado and our midstream operations in West Texas and Oklahoma. Our long-term business plan is to increase stockholder value by: (i) doubling proved natural gas reserves and equity production of natural gas from the levels achieved in 2001 by the end of 2006; (ii) meeting or exceeding throughput projections in our midstream operations; and (iii) optimizing annual returns.

Proposed Merger of our Company. On June 23, 2006, we announced that we had entered into a merger agreement with Anadarko Petroleum Corporation, or Anadarko, whereby it is proposed that we will be merged with a wholly owned subsidiary of Anadarko. Our stockholders will receive $61.00 per common share in cash in the merger. The merger agreement has been approved by each company’s Board of Directors and was filed with the SEC on Form 8-K. We have scheduled a special meeting of our stockholders for August 23, 2006 to vote on, adopt the merger agreement and approve the merger. The merger is also subject to the satisfaction of customary closing conditions, including the receipt of necessary regulatory and governmental approvals. The merger will be completed as soon as practicable following satisfaction of these conditions, which could be as early as the end of August 2006. Should the merger be completed, our common stock will be de-listed with the New York Stock Exchange, or NYSE, and we will file a Form 15 with the SEC to deregister our common stock. Certain of our directors, officers and other stockholders, who collectively hold approximately 17.3 percent of Western’s outstanding shares, have entered into agreements to vote in favor of the merger.

This Form 10-Q includes discussion regarding events that will or may trigger or occur upon completion of the merger. If the merger is not completed these events will not occur. In addition, the timing of the completion of the merger will affect the timing of these events. See also the first paragraph under Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the effect of the proposed merger on certain forward-looking statements included in this Form 10-Q.

Industry and Company Overview. In North America, our industry has experienced several consecutive years of declining natural gas production. Most of the major gas producing areas, such as the Gulf of Mexico, are mature and are in production decline. We are concentrating our efforts in the Rocky Mountain gas producing basins where there are estimated to be large quantities of undeveloped gas. The U.S. government largely retains the mineral rights to these undeveloped reserves; accordingly, the development and production of these reserves require permits from several governmental agencies including the Bureau of Land Management, or BLM. 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 experience and technical expertise position us to acquire new opportunities to develop natural gas in the Rocky Mountain region. Our challenges will be to accomplish these goals with the difficulties encountered by the industry in obtaining the necessary permits from the BLM, and state agencies such as the Wyoming Department of Environmental Quality, or DEQ. 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 these challenges.

Our operations are conducted through the following four business segments:

19

Exploration and Production. We explore for, develop and produce natural gas reserves independently which also may 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 the Sand Wash Basins. These plays are relatively low-risk, 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 2006, our average production sold was 197 MMcfe per day, which was a 18.1% increase over the average production volume sold in the second quarter of 2005.

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, or CBM, biogenic, and shale gas plays to evaluate acquisitions of additional leaseholds, proved and undeveloped reserves or companies with operations primarily focused on unconventional gas developments. In 2005, we opened an exploration and production office in Calgary, Alberta, Canada to evaluate opportunities in the Western Canadian Sedimentary Basin. In total, through June 30, 2006, we have acquired leases on approximately 1.0 million net acres in areas outside our primary producing areas and continue to actively acquire additional leasehold positions.

In March 2006, we acquired certain CBM, properties and related gathering assets in the Big George fairway of the Powder River Basin of Wyoming for an adjusted purchase price of approximately $138.6 million. This acquisition was funded with amounts available under our revolving credit facility. The purchase price includes the drilling rights on approximately 40,000 gross and net acres and 110 drilled wells. Approximately 70 of the drilled wells are currently dewatering, and the remaining 40 wells are awaiting hookup.

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 long-term contracts. At our plants we process natural gas to extract NGLs and may 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 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 2006 increased 4.5 MMcf per day as compared to the same period in 2005 and averaged a total of 1.44 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 produced by us, natural gas for producers and energy marketers under fee schedules regulated by state or federal agencies.

Marketing. Our gas marketing segment is an outgrowth of our gas processing and upstream activities and ensures continual flow of our produced products. One of the primary goals of our gas marketing operations is 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 NGLs and through the use of firm transportation capacity. Historically, the gas produced in the Rocky Mountain region has traded at a substantial discount as compared to the Mid-Continent and West Coast areas, as a result of limited pipeline capacity from the region. We have historically used our firm pipeline transportation capacity to access higher priced Mid-Continent markets and markets further east for both our equity production and for gas purchased from third-parties in the Rocky Mountain region.

We also buy and sell natural gas and NGLs in the wholesale market in the United States and 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, 2006 compared to the three and six months ended June 30, 2005

20

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

	Three Months Ended June 30,						Percent		Six Months Ended June 30,						Percent
	2006			2005			Change		2006			2005			Change
Financial results:
Revenues	$	787,174		$	868,026		(9	)	$	1,776,255		$	1,702,133		4
Net income	42,369			37,629			13		104,231			57,335			82
Earnings per share of common stock	0.56			0.51			10		1.38			0.77			79
Earnings per share of common stock - diluted	0.55			0.50			10		1.36			0.76			79
Net cash provided by operating activities	78,549			42,706			84		265,664			160,102			66
Net cash used in investing activities	(134,197		)	(76,847		)	75		(398,096		)	(191,088		)	108
Net cash provided by financing activities	$	51,960		$	38,454		35		$	109,126		$	36,634		198
Operating data:
Average gas sales (MMcf/D)	1,082			1,162			(7	)	1,094			1,231			(11	)
Average NGL sales (MGal/D)	1,790			1,876			(5	)	1,813			1,819			—
Average gas prices ($/Mcf)	$	5.99		$	6.38		(6	)	$	6.86		$	6.13		12
Average NGL prices ($/Gal)	$	1.14		$	0.88		30		$	1.07		$	0.86		24

Net income increased $4.7 million for the three months ended June 30, 2006, compared to the same period in 2005. The increase in net income was primarily attributable to higher production of equity gas volumes, and higher NGL commodity prices in the second quarter of 2006.

Net income increased $46.9 million for the six months ended June 30, 2006, compared to the same period in 2005. This increase was primarily attributable to higher production of equity gas volumes, higher commodity prices, and gains from our price risk management activities related to our future sales of gas utilizing our storage and transportation capacity.

Revenues from the sale of gas decreased $101.4 million to $576.7 million for the three months ended June 30, 2006 compared to the same period in 2005. This decrease was primarily due to a significant decrease in gas prices and a decrease in sales volume of third-party product in the three months ended June 30, 2006 compared to the same period in 2005 and the implementation of EITF 04-13. EITF 04-13 requires that transactions with the same counterparty that are entered into in contemplation of one another should be reported on a sales net of purchases basis. For the quarter ended June 30, 2006, we reduced revenues and product purchases by $18.3 million for transactions which were entered into concurrently and with the intent to buy and sell like quantities with the same counterparty. Average gas prices realized by us decreased $0.39 per Mcf to $5.99 per Mcf for the quarter ended June 30, 2006 compared to the same period in 2005. Included in the realized gas price were approximately $13.0 million of gains recognized in the three months ended June 30, 2006 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately 75% of our equity gas for the remainder of 2006 and to a lesser extent in 2007. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”  Average gas sales volumes decreased by 80 MMcf per day to 1,082 MMcf per day for the quarter ended June 30, 2006 compared to the same period in 2005.

Revenues from the sale of gas decreased $25.9 million to $1,348.4 million for the six months ended June 30, 2006 compared to the same period in 2005. This decrease was primarily due to the implementation of EITF 04-13 in the six months ended June 30, 2006 as discussed above. For the six months ended June 30, 2006, we reduced revenues and product purchases by $18.3 million for transactions which were entered into concurrently and with the intent to buy and sell like quantities with the same counterparty. Average gas prices realized by us increased $0.73 per Mcf to $6.86 per Mcf for the six months ended June 30, 2006 compared to the same period in 2005. Included in the realized gas price were approximately $21.5 million of gains recognized in the six months ended June 30, 2006 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately 75% of our equity gas for the remainder of 2006 and to a lesser extent in 2007. Average gas sales volumes decreased 137 MMcf per day to 1,094 MMcf per day for the six months ended June 30, 2006 compared to the same period in 2005.

Revenues from the sale of NGLs increased $22.5 million to $172.0 million for the three months ended June 30, 2006 compared to the same period in 2005. This is primarily due to a significant increase in product prices, which more than offset a slight decrease in sales volumes. Average NGL prices realized by us increased $0.26 per gallon to $1.14 per gallon for the three months ended June 30, 2006 compared to the same period in 2005. Included in the realized NGL price were approximately $700,000 of losses recognized in the three months ended June 30, 2006

21

related to futures positions on equity NGL volumes. We have entered into additional futures positions for approximately 55% of our equity NGL production for the remainder of 2006. Average NGL sales volumes decreased 86 MGal per day to 1,790 MGal per day for the three months ended June 30, 2006 compared to the same period in 2005.

Revenues from the sale of NGLs increased approximately $56.9 million to $339.4 million for the six months ended June 30, 2006 compared to the same period in 2005. This is primarily due to a significant increase in product prices. Average NGL prices realized by us increased $0.21 per gallon to $1.07 per gallon for the six months ended June 30, 2006 compared to the same period in 2005. Included in the realized NGL price was approximately $700,000 of losses recognized in the six months ended June 30, 2006 related to futures positions on equity NGL volumes. We have entered into additional futures positions for approximately 55% of our equity NGL production for the remainder of 2006. Average NGL sales volumes decreased slightly to 1,813 MGal per day for the six months ended June 30, 2006 compared to the same period in 2005.

The effect of Price risk management activities changed from $11.2 million for the quarter ended June 30, 2005 to $9.2 million for the quarter ended June 30, 2006. This change was due to the mark-to-market of our risk management activities. This account is primarily impacted by changes in the forward price of natural gas in the second quarter of 2006 as compared to the same period in 2005 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 ($9.0) million for the six months ended June 30, 2005 to $30.2 million for the six months ended June 30, 2006. This change was due to the mark-to-market of our risk management activities. This account is primarily impacted by changes in the forward price of natural gas in the 2006 period as compared to 2005 period and the impact of those price changes on the fair value of the forward sale derivatives for our gas in storage.

Product purchases decreased by $114.7 million and $45.9 million for the quarter and six months ended June 30, 2006, respectively, compared to the same periods in 2005. These decreases in product purchases were the result of lower third-party product sales volumes and lower product purchases on our keepwhole contracts. Keepwhole contracts are more beneficial when NGL prices are high relative to gas prices. In addition, the implementation of EITF 04-13, as discussed above, also reduced product purchases by $31.2 million. Overall, combined product purchases as a percentage of sales of all products were 79% in the quarter ended June 30, 2006 compared to 85% in the quarter ended June 30, 2005. Combined product purchases as a percentage of sales of all products decreased to 81% for the six months ended June 30, 2006 from 85% in the 2005 period. The reductions in these percentages are primarily the result of a decrease in the sale of third party product, an increase in the sale of equity production, and lower product purchases on our keepwhole contracts.

Plant and transportation operating expense increased by $3.1 million and $7.6 million, respectively, for the three and six months ended June 30, 2006 compared to the same periods in 2005. The increase for the quarter ended June 30, 2006 as compared to the same period in 2005 was substantially due to increased labor and repair and maintenance expenses. The increase for the six months ended June 30, 2006 as compared to the same period in 2005 was substantially due to increased, labor, repair and maintenance expenses, and third-party gathering expenses.

Oil and gas exploration and production expense increased by $11.9 million and $15.5 million, respectively, for the three and six months ended June 30, 2006 compared to the same periods in 2005. The increases for the quarter and six months ended June 30, 2006 as compared to the same periods in 2005 were substantially due to increased production taxes and increased operations throughout our operating areas. Overall, LOE averaged $0.93 per Mcf and $0.85 per Mcf for the quarter and six months ended June 30, 2006, respectively, and LOE in the Powder River Basin coal bed development averaged $1.05 per Mcf and $0.92 per Mcf in the quarter and six months ended June 30, 2006, respectively. In the Powder River Basin, these represent increases of $0.13 and $0.03 per Mcf from the same periods in 2005. The increase in LOE per Mcf 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.

Depreciation, depletion and amortization increased by $5.1 million and $11.4 million, respectively, for the three and six months ended June 30, 2006 as compared to the same periods in 2005. For the quarter ended June 30, 2006 as compared to the same period in 2005, 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 a $2.5 million increase in DD&A in our upstream operations primarily due to our continued development in the Powder River Basin. For the six months ended June 30, 2006 as compared to the same period in 2005, we had an $5.2 million increase in DD&A

22

in our midstream operations and a $5.6 million increase in our upstream operations primarily due to those items mentioned above.

Selling and administrative expenses increased by $3.8 million and $11.0 million for the three and six months ended June 30, 2006 as compared to the same period in 2005. The increase in selling and administrative expenses for the three months ended June 30, 2006 as compared to 2005 was primarily the result of increased administrative salaries, expenses related to our proposed merger, and compensation expense related to our stock option and restricted stock plans. Additionally, a charge of $5.9 million was recorded in the second quarter of 2005 in connection with a settlement of litigation. The increase in the six months ended June 30, 2006 compared to 2005 is due to those items mentioned above.

The Total provision for income taxes, as a percentage of Income before taxes was approximately 37.9% and 36.6%, respectively, during the quarter and six months ended June 30, 2006 as compared to 36.8% and 36.7%, respectively, in same periods of 2005. This increase is due to a change in the calculation of the franchise tax in Texas, which, effective January 1, 2007, will include an associated income tax.

Cash Flow Information

Cash flows from operating activities increased by $105.6 million in the first six months of 2006 compared to the same period in 2005. 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 $207.0 million in the first six months of 2006 compared to the same period in 2005. This increase was primarily due to an increased level of capital expenditures, including the March 2006 acquisition of properties in the Powder River Basin.

Cash flows provided by financing activities increased by $72.5 million in the first six months of 2006 compared to the same period in 2005. This increase was due to the utilization of our revolving credit facility to fund our capital investments in 2006, including the acquisition of properties in the Powder River Basin in the first quarter.

Adoption of FAS 123(R)

On January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment”, or SFAS 123(R), which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors including employee stock options based on estimated fair values. SFAS 123(R) supersedes our previous accounting under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”, or APB 25, for periods beginning in fiscal 2006. In March 2005, the SEC issued Staff Accounting Bulletin No. 107, or SAB 107, relating to SFAS 123(R). We considered the guidance of SAB 107 in our adoption of SFAS 123(R).

We adopted SFAS 123(R) using the modified prospective transition method, which requires the application of the accounting standard as of January 1, 2006. In accordance with the modified prospective transition method, our Consolidated Financial Statements for prior periods are not restated to reflect, and do not include, any impact of SFAS 123(R). We did not modify any outstanding stock options in anticipation of the adoption of SFAS 123(R). The effect of the change in accounting principle resulting from the adoption of SFAS 123(R) was recognized in our financial statements through the elimination of previously recognized deferred compensation costs, with offsetting amounts recorded in the additional paid-in capital account within Stockholders’ equity.

Stock-based compensation expense to be recognized under SFAS 123(R) for the three and six months ended June 30, 2006 related to employee stock options, including compensation from our 2006 grants is as presented in the following table. There was no additional stock-based compensation expense related to employee stock options during the three months ended March 31, 2005 resulting from the adoption of SFAS 123(R).

(Amounts in thousands, except per share amounts)	Quarter ended June 30, 2006			Six Months ended June 30, 2006
Incremental stock-based compensation expense recognized through earnings	$	4,058		$	6,900
Related deferred income tax benefit	(419		)	(958		)
Decrease in net income	3,639			6,538
Decrease in earnings per share of common stock	0.05			0.08
Decrease in earnings per share of common stock – assuming dilution	0.05			0.08
Stock-based compensation expense capitalized	$	536		$	953

23

SFAS 123(R) requires us to estimate the fair value of share-based payment awards on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods in our Consolidated Statement of Operations. Prior to the adoption of SFAS 123(R), we accounted for stock-based awards to employees and directors using the intrinsic value method in accordance with APB 25 as then allowed under Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation”, or SFAS 123. Under the intrinsic value method, with the exception of the options granted under the Chief Executive Officer and President’s Plan and our restricted stock, no stock-based compensation expense had been recognized in our Consolidated Statement of Operations, because the exercise price of our stock options granted to employees and directors equaled the fair market value of the underlying stock at the date of grant.

Stock-based compensation expense to be recognized is based on the fair value of the portion of share-based payment awards that is ultimately expected to vest during the period. Stock-based compensation expense recognized in our Consolidated Statement of Operations for the first six months of 2006 includes compensation expense for share-based payment awards granted in 2006 and granted prior to, but not yet vested, as of January 1, 2006. Compensation expense for the awards granted prior to January 1, 2006 was based on the grant date fair value estimated in accordance with the pro forma provisions of SFAS 123. Compensation expense for the share-based payment awards granted subsequent to December 31, 2005 was based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R). In conjunction with the adoption of SFAS 123(R), we continued our method of attributing the value of stock-based compensation using the straight-line single option method. As stock-based compensation expense recognized in the Consolidated Statement of Operations for the first six months of 2006 is based on awards ultimately expected to vest, it was reduced for estimated forfeitures. SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. At June 30, 2006, the compensation expense related to non-vested awards to be recognized in future periods totals $23.0 million. The weighted average period over which this expense is expected to be recognized is 2.1 years; however, in connection with the proposed merger of Western with Anadarko, all outstanding options will fully vest and convert to the right to receive a cash payment from the acquirer.

Segment Information

Gas Gathering, Processing and Treating. The Gas Gathering, Processing and Treating segment realized segment-operating profit of $126.9 million for the six months ended June 30, 2006 compared to $103.2 million in the same period in 2005. The increase in operating profit in this segment in the first six months of 2006 was primarily due to higher realized prices and a 3% increase in throughput volume.

Exploration and Production. The Exploration and Production segment realized segment-operating profit of $119.9 million in the first six months of 2006 compared to $86.5 million in 2005. The increase was due to increased equity production and higher product prices. During the first six months of 2006, our production of natural gas as compared to the same period in 2005 increased by 18% to 34.6 Bcfe. The following table sets forth the average sales price received for our oil and gas products along with cost information in the three and six months ended June 30, 2006 and 2005.

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Average sales price: (1)
Oil ($/Bbl)	$	62.62	$	47.88	$	60.35	$	45.58
Gas ($/Mcf), excluding the effect of hedging positions	4.86		5.34		5.47		5.11
Gas ($/Mcf), including the effect of hedging positions	5.50		5.36		6.02		5.17
Production and other costs:
Lease operating expense ($/Mcfe)	0.93		0.80		0.85		0.83
Production tax expense ($/Mcfe)	0.78		0.59		0.72		0.53
Gathering and transportation expense ($/Mcfe)
Inter-segment charges	0.67		0.60		0.65		0.61
Third-party charges	0.16		0.16		0.19		0.18
Other expenses ($/Mcfe)	0.04		0.04		0.03		0.02
Total costs ($/Mcfe)	$	2.58	$	2.19	$	2.44	$	2.17

24

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

Our principal upstream operations are summarized in the following table:

Production Area	Gross Acres Under Lease at June 30, 2006	Net Acres Under Lease at June 30, 2006	Average Net Production Sold for the Six Months Ended June 30, 2006	Gross Productive Gas Wells at June 30, 2006	Net Productive Gas Wells at June 30, 2006
			(MMcfe/day)
Powder River Basin CBM	1,060,000	559,000	131	5,514	2,633
Pinedale Anticline/Jonah	130,000	23,000	43	402	45
San Juan/Delaware Basin	45,000	39,000	12	187	166
Sand Wash Basin	106,000	97,000	5	23	23
Red Desert/Washakie/Uinta	80,000	40,000	1	8	3
Denver-Julesburg Basin	383,000	328,000	—	9	9
Canada	46,000	44,000	—	22	21
Central Montana	666,000	588,000	—	3	3
Other	27,000	26,000	—	10	2
Total	2,543,000	1,744,000	192	6,178	2,905

Drilling Results. The following table sets forth the number of wells we completed during the six month periods ended June 30, 2006 and 2005 in each of our major producing areas. This information should not be considered to be 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. Productive wells are producing wells and wells capable of production.

	Six Months Ended June 30,
	2006		2005
Productive Area	Gross	Net	Gross	Net
Powder River Basin CBM
Productive wells completed	362	178	340	171
Dry development wells drilled	42	20	0	0
Pinedale Anticline and Jonah Fields
Development productive wells completed	19	2	30	3
Exploratory productive wells completed	9	1	5	0
Dry exploratory wells drilled	0	0	1	0
San Juan Basin
Development productive wells completed	9	9	20	18
Exploratory productive wells completed	6	6	7	7
Sand Wash Basin
Dry exploratory wells completed	1	0	1	1
Canada (1)
Exploratory productive wells completed	4	4	0	0
Other (1)
Exploratory productive wells completed	6	4	3	3

(1)Some exploratory wells while classified as productive are still in the process of an extended production test.

Marketing. The Marketing segment realized a segment-operating profit of $29.5 million for the six months ended June 30, 2006 compared to a segment-operating loss of ($8.2) million in the same period of 2005. The increase in segment-operating profit was primarily due to non-cash mark-to-market gains from economic hedges of future sales of gas utilizing our storage and transportation capacity for the six months ended June 30, 2006 compared to a loss for the six months ended June 30, 2005.

25

Transportation. The Transportation segment realized segment-operating profit of $7.8 million for the six months ended June 30, 2006 compared to $6.3 million in the same period of 2005. The Transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin.

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 and the availability and cost of oil field services and supplies such as concrete, steel pipe and compression equipment are all expected to have significant influences on our future net cash provided by operating activities. Additionally, our future growth will be dependent upon the success and timing of our exploration and production activities, obtaining additions to dedicated plant reserves, acquisitions, new project development, marketing results, efficient operation of our facilities and our ability to obtain financing at favorable terms.

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

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

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

Our dividends will total approximately $5.7 million in the third quarter of 2006. These dividends will be funded with amounts available under the revolving credit facility.

Sources and Uses of Funds. Our sources and uses of funds for the six months ended June 30, 2006 are summarized as follows (dollars in thousands):

26

Sources of funds:
Borrowings under our revolving credit facility	$	2,415,700
Proceeds from the dispositions of property and equipment	1,255
Net cash provided by operating activities	265,664
Excess tax benefits from share-based payment awards	2,379
Proceeds from exercise of common stock options	10,321
Total sources of funds	$	2,695,319
Uses of funds:
Payments under our revolving credit facility (including debt issue costs)	$	2,273,714
Capital expenditures	399,351
Change in outstanding checks	34,207
Common dividends paid	11,353
Total uses of funds	$	2,718,625

Capital Investment Program. Subject to the timing of the completion of the proposed merger, we currently anticipate capital expenditures in 2006 of approximately $675.8 million. The 2006 capital budget is a 45% increase over the amount expended in 2005. This increase is the result of our March 2006 acquisition of additional CBM properties and an expected increase in drilling activity in each of our core upstream areas and additional drilling activity by third party producers whose acreage is dedicated to our midstream facilities. Overall, capital expenditures in the Powder River Basin CBM development and in the Greater Green River Basin operations represent 52% and 22%, respectively, of the total 2006 budget. This budget is subject to limitations provided for in the merger agreement.

The 2006 capital budget and our capital expenditures during the six months ended June 30, 2006 are presented in the following table (dollars in thousands).

Type of Capital Expenditure	2006 Capital Budget			Capital Expenditures During the Six Months Ended June 30, 2006
Gathering, processing, treating and pipeline assets	$	185.0	*	$	122.3	*
Exploration and production and lease acquisition activities	336.2			132.1
Acquisition of CBM properties	136.7			136.7
Information technology and other items	4.5			1.6
Capitalized interest and overhead	13.4			12.3
Total Capital Expenditures	$	675.8		$	405.0

*  Includes $22.2 million budgeted in 2006 and $8.0 million expended in the first six months of 2006 for maintaining existing facilities.

In March 2006, we acquired certain CBM properties and related gathering assets in the Big George fairway of the Powder River Basin of Wyoming for an adjusted purchase price of $138.6 million. This acquisition was funded with amounts available under our revolving credit facility. The purchase price includes the drilling rights on approximately 40,000 gross and net acres and 110 drilled wells. Approximately 70 of the drilled wells are currently dewatering, and the remaining 40 wells are awaiting hookup.

Long-term Debt

 Revolving Credit Facility. At June 30, 2006, the commitment under the revolving credit facility was $700 million with a maturity date in November 2010. At June 30, 2006, $427.0 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 on undrawn amounts ranging between 0.10% and 0.30%, depending on our debt to capitalization ratio. This fee is paid on unused amounts of the commitment. As of June 30, 2006, the interest rate payable on borrowings under this facility was approximately 6.0% 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 Standard and Poor’s.

27

Master Shelf Agreement. Amounts outstanding under our master shelf agreement at July 31, 2006 are as indicated in the following table (dollars in thousands):

Issue Date	Amount		Interest Rate		Final Maturity	Principal Repayment Schedule
July 28, 1995	$	10,000	7.61	%	July 28, 2007	$10,000 on July 28, 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	$	135,000

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.

The closing of our proposed merger would be an event of default under our revolving credit facility, which would entitle the lenders to terminate their commitments and demand payment of all outstanding and unpaid amounts there under. Further, our master shelf agreement contains cross default provisions, which would be triggered by the default under the revolving credit facility. Therefore, upon the closing of the merger, the acquirer must renegotiate these agreements or repay all amounts due under them. Also, the closing of our proposed merger is also an event of default under some of our operating leases, which will entitle our counterparties to terminate their commitments and require a return of the related equipment. Therefore, on or prior to the closing of the merger, the acquirer must renegotiate these agreements.

28

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. The closing of our proposed merger is an event of default under certain of our swap agreements, which will entitle our counterparties to terminate their commitments and require a settlement of all outstanding transactions. Therefore, upon the closing of the merger, the acquirer must renegotiate these agreements or settle all amounts due there under.

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

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

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

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

29

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. Our 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.

In the second quarter of 2006, in order to properly align our hedged volumes of natural gas to our forecasted equity production, we discontinued hedge treatment on financial instruments for 30 MMcf per day of natural gas as the anticipated transaction is no longer probable. As a result, a pre-tax gain of $2.8 million was reclassified into earnings from Accumulated other comprehensive income.

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.

Outstanding Equity Hedge Positions and the Associated Basis for 2006 and 2007. The following table details our hedge positions as of June 30, 2006. In order to determine the hedged price to the particular operating region, deduct the basis differential from the settle price. There is no associated cost for the hedges.

30

Product	Year	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	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 – 10,000 MMBtu per day with an average basis price of $0.55 per MMBtu.
		45,000 MMBtu per day with an average minimum price of $9.00 per MMBtu and an average maximum price of $17.25 per MMBtu. 30,000 MMBtu per day with an average minimum price of $7.00 per MMBtu and an average maximum price of $10.25 per MMBtu	Permian – 7,500 MMBtu per day with an average basis price of $0.97 per MMBtu. San Juan – 12,500 MMBtu per day with an average basis price of $1.51 per MMBtu. Rocky Mountain – 37,500 MMBtu per day with an average basis price of $1.48 per MMBtu. NGPL Texas Oklahoma – 30,000 MMBtu per day with an average basis price of $0.52 per MMBtu. Nigas Chicago – 17,500 MMBtu per day with an average basis price of $0.37 per MMBtu.
	2007	115,000 MMBtu per day with an average minimum price of $7.00 per MMBtu and an average maximum price of $14.90 per MMBtu.	Mid-Continent – 20,000 MMBtu per day with an average basis price of $0.98 per MMBtu. Permian – 10,000 MMBtu per day with an average basis price of $1.20 per MMBtu. San Juan – 10,000 MMBtu per day with an average basis price of $1.77 per MMBtu. Rocky Mountain – 45,000 MMBtu per day with an average basis price of $2.01 per MMBtu. NGPL Texas Oklahoma – 30,000 MMBtu per day with an average basis price of $0.55 per MMBtu.
Natural Gasoline	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
Ethane	2006	200,000 Barrels per month with an average minimum price of $0.51 per gallon and an average maximum price of $0.67 per gallon.	Not Applicable
Propane	2006	140,000 Barrels per month with an average minimum price of $0.83 per gallon and an average maximum price of $1.04 per gallon.	Not Applicable

Account balances related to hedging transactions (designated as cash flow hedges under SFAS 133) at June 30, 2006 were $26.9 million in Current assets from price risk management activities, $6.6 million in Long-term assets from price risk management activities, $22.0 million in Current liabilities from price risk management activities, $2.7 million in Liabilities from price risk management activities, $3.4 million in Deferred income tax payable, net, and a $5.9 million after-tax unrealized gain in Accumulated other comprehensive income, a component of Stockholders’

31

equity. Of the unrealized gain in Accumulated other comprehensive income at June 30, 2006, $1.4 million will be reclassified to earnings in 2006 and $4.5 million will be reclassified to earnings in 2007.

Earnings Sensitivities. At June 30, 2006, we held gas in our contracted storage facilities and in imbalances of approximately 20.0 Bcf at an average cost of $6.07 per Mcf. This inventoried gas was sold forward. 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 would decrease pre-tax earnings by $20.0 million and a $1.00 decrease in the forward price of gas in the anticipated month of withdrawal would increase pre-tax earnings by $20.0 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 and Net cash from operating activities.

As of June 30, 2006, we had sold basis swaps for 115,000 MMBtu per day at various sales points for 2008, at an average differential of $1.16. These positions will minimize our price risk as it relates to the change in the basis differential from NYMEX to our various sales points. Because we did not sell forward our equity natural gas in conjunction with these basis transactions, these positions are not eligible for hedge accounting treatment. Accordingly, these transactions will be marked-to-market through Price risk management activities. Based on a $0.10 increase in the forward basis differential in the anticipated month of sale, the change in the non-cash mark-to-market value of these derivatives would increase pre-tax earnings by $4.2 million and a $0.10 decrease in the forward basis differential in the anticipated month of sale would decrease pre-tax earnings by $4.2 million. As our equity gas is sold and the future basis derivatives are settled, we will realize the economic effect of these transactions through earnings and Net cash from operating activities.

Summary of Derivative Positions. A summary of the net change in our derivative position from December 31, 2005 to June 30, 2006 is as follows (dollars in thousands):

Fair value of contracts outstanding at December 31, 2005	$	20,140
Increase in value due to change in price	69,429
Increase in value due to new contracts entered into during the period	14,003
Contract settlements during the period	(73,724		)
Changes in fair value attributable to changes in valuation techniques	—
Fair value of contracts outstanding at June 30, 2006	$	29,848

A summary of the sources of fair value of our net outstanding derivative positions at June 30, 2006 is as follows (dollars in thousands):

Source of Fair Value	Total Fair Value			Maturing In 2006			Maturing In 2007-2008
Exchange published prices	$	(3,204	)	$	(6,985	)	$	3,781
Other actively quoted prices (1)	14,570			15,106			(536		)
Other valuation methods (2)	18,482			9,828			8,654
Total fair value	$	29,848		$	17,949		$	11,899

(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, 2006, we had sold forward contracts for $63.6 million in Canadian dollars in exchange for $56.0 million in United States dollars, and the fair market value of these contracts was a loss of $1.2 million in United States dollars.

32

ITEM 4.  CONTROLS AND PROCEDURES

Disclosure Controls and Procedures.

Our management evaluated, under the supervision of and with the participation of the Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) under the Securities Exchange Act of 1934, as of the end of the period covered by this Report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of June 30, 2006, to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Changes in Internal Controls over Financial Reporting.

There have not been any changes in our internal control over financial reporting during the quarter ended June 30, 2006, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

33

PART II - OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

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

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 5, 2006:

John E. Brewster, Jr., Thomas M. Hamilton, and Joseph E. Reid were elected as class two directors to serve until their terms expire in 2009 and until their successors have been elected. The results of the election were as follows.

	Votes For	Votes Withheld
John E. Brewster, Jr.	71,351,586	1,166,570
Thomas M. Hamilton	71,533,772	984,383
Joseph E. Reid	64,109,482	8,408,674

Our other directors whose terms did not expire on the date of the Annual Meeting, James A. Senty, Walter L. Stonehocker, Bill M. Sanderson, Richard B. Robinson, Brion G. Wise, Peter A. Dea and Dean Phillips continued in office.

An amendment to our Certificate of Incorporation to increase our authorized common stock to 200,000,000 shares was approved as follows:

	Votes For	Votes Against	Abstentions
Amendment to Certificate of Incorporation	68,893,628	3,591,590	32,938

The first amendment to our 2005 Stock Incentive Plan to enable the grant shares of restricted stock to non-employee members of the board of directors was approved as follows:

	Votes For	Votes Against	Abstentions	Broker Non-votes
Amendment to 2005 Stock Incentive Plan	47,338,067	16,703,390	588,933	8,417,806

ITEM 6.EXHIBITS

Exhibit
Number	Description
2.1	Agreement and Plan of Merger, dated as of June 22, 2006, by and among Anadarko Petroleum Corporation and APC Merger Sub, Inc. and Western Gas Resources, Inc. (previously filed as Exhibit 2.1 to our Current Report on Form 8-K filed on June 23, 2006 and incorporated herein by reference).
2.2	Amendment No. 1 to Agreement and Plan of Merger, dated July 7, 2006, by and among Anadarko Petroleum Corporation, APC Merger Sub, Inc. and Western Gas Resources, Inc. (previously filed as Exhibit 2.2 to our Current Report on Form 8-K filed on July 7, 2006 and incorporated herein by reference).
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 January 13, 2006 (previously filed as Exhibit 3.01 to our Current Report on Form 8-K filed on January 19, 2006 and incorporated herein by reference).

34

4.6	Amendment No. 1, dated as of June 22, 2006, to the Rights Agreement, dated as of March 22, 2001, between Western Gas Resources, Inc. and Computershare Trust Company, N.A. (successor-in-interest to Fleet National Bank (f/k/a Bank Boston, N.A.)), as rights agent (previously filed as Exhibit 4.6 to our Current Report on Form 8-K filed on June 23, 2006 and incorporated herein by reference).
10.1	Amendment No. 1 to the Western Gas Resources, Inc. Amended and Restated Directors’ Health Plan, dated June 13, 2006 (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on June 15, 2006 and incorporated herein by reference).
10.2	Employment Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and John F. Chandler (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.3	Indemnification Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and John F. Chandler (previously filed as Exhibit 10.2 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference)
10.4	Employment Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and William J. Krysiak (previously filed as Exhibit 10.3 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.5	Indemnification Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and William J. Krysiak (previously filed as Exhibit 10.4 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.6	Employment Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and John C. Walter (previously filed as Exhibit 10.5 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.7	Indemnification Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and John C. Walter (previously filed as Exhibit 10.6 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.8	Employment Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and Edward A. Aabak (previously filed as Exhibit 10.7 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.9	Indemnification Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and Edward A. Aabak (previously filed as Exhibit 10.8 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.10	Description of First Amendment to the 2005 Stock Incentive Plan from proxy statement for the 2006 annual meeting of stockholders (pages 4-8) (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on May 10, 2006 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.
99.1	Form of Voting Agreement, dated as of June 22, 2006, by and between Anadarko Petroleum Corporation and the stockholder signatory thereto (previously filed as Exhibit 99.1 to our Current Report on Form 8-K filed on June 23, 2006 and incorporated herein by reference).

35

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.

Date: August 8, 2006	WESTERN GAS RESOURCES, INC.
	(Registrant)
	By:	/s/ PETER A. DEA
		Peter A. Dea
		Chief Executive Officer and President
Date: August 8, 2006	By:	/s/WILLIAM J. KRYSIAK
		William J. Krysiak
		Executive Vice President - Chief Financial Officer
		(Principal Financial and Accounting Officer)

36

INDEX TO EXHIBITS

Exhibit
Number	Description
2.1	Agreement and Plan of Merger, dated as of June 22, 2006, by and among Anadarko Petroleum Corporation and APC Merger Sub, Inc. and Western Gas Resources, Inc. (previously filed as Exhibit 2.1 to our Current Report on Form 8-K filed on June 23, 2006 and incorporated herein by reference).
2.2	Amendment No. 1 to Agreement and Plan of Merger, dated July 7, 2006, by and among Anadarko Petroleum Corporation, APC Merger Sub, Inc. and Western Gas Resources, Inc. (previously filed as Exhibit 2.2 to our Current Report on Form 8-K filed on July 7, 2006 and incorporated herein by reference).
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 January 13, 2006 (previously filed as Exhibit 3.01 to our Current Report on Form 8-K filed on January 19, 2006 and incorporated herein by reference).
4.6	Amendment No. 1, dated as of June 22, 2006, to the Rights Agreement, dated as of March 22, 2001, between Western Gas Resources, Inc. and Computershare Trust Company, N.A. (successor-in-interest to Fleet National Bank (f/k/a Bank Boston, N.A.)), as rights agent (previously filed as Exhibit 4.6 to our Current Report on Form 8-K filed on June 23, 2006 and incorporated herein by reference).
10.1	Amendment No. 1 to the Western Gas Resources, Inc. Amended and Restated Directors’ Health Plan, dated June 13, 2006 (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on June 15, 2006 and incorporated herein by reference).
10.2	Employment Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and John F. Chandler (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.3	Indemnification Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and John F. Chandler (previously filed as Exhibit 10.2 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference)
10.4	Employment Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and William J. Krysiak (previously filed as Exhibit 10.3 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.5	Indemnification Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and William J. Krysiak (previously filed as Exhibit 10.4 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.6	Employment Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and John C. Walter (previously filed as Exhibit 10.5 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.7	Indemnification Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and John C. Walter (previously filed as Exhibit 10.6 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).

37

10.8	Employment Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and Edward A. Aabak (previously filed as Exhibit 10.7 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.9	Indemnification Agreement, dated July 6, 2006, by and between Western Gas Resources, Inc. and Edward A. Aabak (previously filed as Exhibit 10.8 to our Current Report on Form 8-K filed on July 11, 2006 and incorporated herein by reference).
10.10	Description of First Amendment to the 2005 Stock Incentive Plan from proxy statement for the 2006 annual meeting of stockholders (pages 4-8) (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on May 10, 2006 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.
99.1	Form of Voting Agreement, dated as of June 22, 2006, by and between Anadarko Petroleum Corporation and the stockholder signatory thereto (previously filed as Exhibit 99.1 to our Current Report on Form 8-K filed on June 23, 2006 and incorporated herein by reference).

38

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Peter A. Dea, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Western Gas Resources, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: August 8, 2006

  /s/ Peter A. Dea

Peter A. Dea

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, William J. Krysiak, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Western Gas Resources, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: August 8, 2006

  /s/ William J. Krysiak

William J. Krysiak

Executive Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION BY THE CHIEF EXECUTIVE OFFICER AND

CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

1.             The undersigned are the Chief Executive Officer and the Chief Financial Officer of Western Gas Resources, Inc. (“Western Gas Resources”).  This Certification is made pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.  This Certification accompanies the Quarterly Report on Form 10-Q of Western Gas Resources for the quarter ended June 30, 2006.

2.             We certify that such Quarterly Report on Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that the information contained in such Quarterly Report on Form 10-Q fairly represe nts, in all material respects, the financial condition and results of operations of Western Gas Resources.

This Certification is executed as of August 8, 2006.

/s/ Peter A. Dea

Peter A. Dea, Chief Executive Officer

and President

/s/ William J. Krysiak

William J. Krysiak, Executive Vice President

and Chief Financial Officer