10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2006

OR

oTRANSITION 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 ý

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 ý

On May 4, 2006, there were 76,008,737 shares of the registrant’s common stock outstanding.

Western Gas Resources, Inc.

Form 10-Q

Table of Contents

PART I - Financial Information
Item 1.	Financial Statements
	Consolidated Balance Sheet - March 31, 2006 and December 31, 2005
	Consolidated Statement of Cash Flows - Three Months Ended March 31, 2006 and 2005
	Consolidated Statement of Operations - Three Months Ended March 31, 2006 and 2005
	Consolidated Statement of Changes in Stockholders’ Equity - Three Months Ended March 31, 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 6.	Exhibits
Signatures

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PART I - FINANCIAL INFORMATION

ITEM 1.FINANCIAL STATEMENTS

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Unaudited)

(Dollars in thousands, except share data)

	March 31,			December 31,
	2006			2005
ASSETS
Current assets:
Cash and cash equivalents	$	7,580		$	27,198
Trade accounts receivable, net	313,784			413,004
Margin deposits	5,486			31,217
Inventory	93,690			136,968
Assets from price risk management activities	46,508			48,988
Deferred tax asset	—			4,808
Other	14,264			14,010
Total current assets	481,312			676,193
Property and equipment:
Gas gathering, processing and transportation	1,320,588			1,290,278
Oil and gas properties and equipment (successful efforts method)	798,724			666,306
Construction in progress	395,440			286,641
	2,514,752			2,243,225
Less: Accumulated depreciation, depletion and amortization	(716,879		)	(684,904		)
Total property and equipment, net	1,797,873			1,558,321
Other assets:
Gas purchase contracts (net of accumulated amortization of $42,988 and $42,583, respectively)	30,920			32,071
Assets from price risk management activities	8,437			5,495
Investments in joint ventures	39,249			36,791
Other	27,627			25,763
Total other assets	106,233			100,120
TOTAL ASSETS	$	2,385,418		$	2,334,634
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	378,068		$	463,113
Accrued expenses	73,363			106,542
Income tax payable	11,032			—
Liabilities from price risk management activities	4,592			34,343
Deferred tax liability	6,509			—
Dividends payable	5,698			5,660
Total current liabilities	479,262			609,658
Long-term debt	515,000			430,000
Liabilities from price risk management activities	155			—
Other long-term liabilities	65,970			66,427
Deferred income taxes, net	337,916			325,090
Total liabilities	1,398,303			1,431,175
Stockholders’ equity:
Common stock, par value $0.10; 100,000,000 shares authorized; 75,906,185 and 75,375,134 shares issued, respectively	7,594			7,565
Treasury stock, at cost; 50,032 common shares in treasury	(788		)	(788		)
Deferred compensation	—			(9,244		)
Additional paid-in capital	431,521			429,007
Retained earnings	528,023			471,860
Accumulated other comprehensive income	20,765			5,059
Total stockholders’ equity	987,115			903,459
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,385,418		$	2,334,634

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

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WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Three Months Ended
	March 31,
	2006			2005
Reconciliation of net income to net cash provided by operating activities:
Net income	$	61,862		$	19,706
Add income items that do not affect operating cash flows:
Depreciation, depletion and amortization	35,362			29,078
Loss on sale of assets	1,044			28
Deferred income taxes	22,045			4,078
Excess tax benefits from share-based payment awards	(1,484		)	—
Non-cash change in fair value of derivatives	(4,182		)	28,677
Compensation expense from restricted stock and stock options	4,651			273
Other non-cash items, net	(3,630		)	(1,220		)
Adjustments to working capital to arrive at net cash provided by operating activities:
Decrease in trade accounts receivable	99,176			21,557
(Increase) decrease in margin deposits	15,841			(7,649		)
Decrease in product inventory	43,818			29,654
(Increase) in other current assets	(6,122		)	(994		)
(Increase) decrease in other assets and liabilities, net	719			(674		)
(Decrease) in accounts payable	(70,087		)	(10,603		)
Increase (decrease) in accrued expenses	(11,003		)	5,485
Net cash provided by operating activities	188,010			117,396
Cash flows from investing activities:
Purchases of property and equipment, including acquisitions	(265,051		)	(115,332		)
Distributions from equity investees	—			324
Proceeds from the disposition of property and equipment	1,152			767
Net cash used in investing activities	(263,899		)	(114,241		)
Cash flows from financing activities:
Net proceeds from exercise of common stock options	4,806			2,307
Excess tax benefits from share-based payment awards	1,484			—
Change in outstanding checks	(29,344		)	(4,283		)
Borrowings on revolving credit facility	957,100			807,065
Payments on revolving credit facility	(872,100		)	(803,165		)
Borrowings on long-term debt	—			25,000
Payments on long-term debt	—			(25,000		)
Debt issue costs paid	(14		)	(40		)
Dividends paid	(5,661		)	(3,704		)
Net cash provided by (used in) financing activities	56,271			(1,820		)
Net increase (decrease) in cash and cash equivalents	(19,618		)	1,335
Cash and cash equivalents at beginning of period	27,198			390
Cash and cash equivalents at end of period	$	7,580		$	1,725

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

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WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)
(Dollars in thousands, except share and per share amounts)

	Three Months Ended
	March 31,
	2006			2005
Revenues:
Sale of gas	$	771,661		$	696,219
Sale of natural gas liquids	167,416			132,969
Gathering, processing and transportation	26,700			23,880
Price risk management activities	20,980			(20,248		)
Other	2,324			1,287
Total revenues	989,081			834,107
Costs and expenses:
Product purchases	776,132			707,354
Plant and transportation operating expense	32,216			27,699
Oil and gas exploration and production expense	28,518			24,896
Depreciation, depletion and amortization	35,362			29,078
Selling and administrative expense	18,804			12,532
Loss on sale of assets	1,044			28
Earnings from equity investments	(2,374		)	(2,134		)
Interest expense	3,185			3,520
Total costs and expenses	892,887			802,973
Income before income taxes	96,194			31,134
Provision for income taxes:
Current	12,287			7,350
Deferred	22,045			4,078
Total provision for income taxes	34,332			11,428
Net income	$	61,862		$	19,706
Earnings per share of common stock	$	0.82		$	0.27
Weighted average shares of common stock outstanding	75,079,330			74,148,269
Earnings per share of common stock - assuming dilution	$	0.81		$	0.26
Weighted average shares of common stock outstanding - assuming dilution	76,063,490			75,559,318

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

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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 (Loss)			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 quarter of 2006	—	—	—		—			—			—			61,862			—			61,862
Translation adjustments	—	—	—		—			—			—			—			(1,274		)	(1,274		)
Other comprehensive income
From equity investees	—	—	—		—			—			—			—			84			84
Reclassification adjustment for settled contracts	—	—	—		—			—			—			—			(3,811		)	(3,811		)
Changes in fair value of outstanding hedge positions	—	—	—		—			—			—			—			18,063			18,063
Fair value of new hedge positions	—	—	—		—			—			—			—			2,644			2,644
Change in accumulated derivative comprehensive income	—	—	—		—			—			—			—			16,896			16,896
Total comprehensive income, net of tax	—	—	—		—			—			—			—			—			77,568
Stock options exercised	251,108	—	29		—			—			4,777			—			—			4,806
Compensation expense from common stock options	—	—	—		—			—			3,258			—			—			3,258
Excess tax benefit related to stock options exercised	—	—	—		—			—			2,330			—			—			2,330
Effect of change in accounting principle	—	—	—		—			9,244			(9,244		)	—			—			—
Compensation expense from restricted stock	279,943	—	—		—						1,393			—			—			1,393
Dividends declared on common stock	—	—	—		—			—			—			(5,699		)	—			(5,699		)
Balance at March 31, 2006	75,906,185	50,032	$	7,594	$	(788	)	$	—		$	431,521		$	528,023		$	20,765		$	987,115

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

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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 March 31, 2006 and for the three-month periods ended March 31, 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 months ended March 31, 2006 are not necessarily indicative of the results of operations expected for the year ended December 31, 2006.

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 March 31,
	2006		2005
Total dividends declared	$	5,699	$	3,710
Dividends declared per share of common stock	$	0.075	$	0.05

Common stock options granted are potential common shares with the exception of the grants in the quarter ended March 31, 2006, which are anti-dilutive.  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 March 31,
	2006	2005
Weighted average shares of common stock outstanding	75,079,330	74,148,269
Potential common shares from common stock options	984,161	1,411,049
Weighted average shares of common stock outstanding - assuming dilution	76,063,490	75,559,318

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 March 31, 2006 were unrealized gains of $19.5 million, which is net of $11.2 million of deferred taxes, from the fair value of derivatives designated as cash flow hedges and unrealized losses of $1.3 million, which is net of $0.8 million 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 March 31, 2006, approximately $19.5 million of gains in Accumulated other comprehensive income will be reclassified to earnings, of which $16.3 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”,

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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 March 31, 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.  

Supplementary Cash Flow Information.  Interest paid was $6.0 million and $6.1 million for the quarters ended March 31, 2006 and 2005, respectively.  A total of $472,000 was paid in income taxes in the quarter ended March 31, 2006.  No income taxes were paid in the quarter ending March 31, 2005.  Asset retirement obligation assets and liabilities of $1.9 million and $1.6 million were recorded for the quarters ended March 31, 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 from an undisclosed seller for approximately $136.7 million before adjustments.  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.  These properties had no production in March 2006 as approximately 70 of the drilled wells are currently dewatering and the remaining 40 wells are awaiting hookup.  The adjusted purchase price of $138.6 million at closing is included in the Consolidated Balance Sheet at March 31, 2006 and is summarized as follows (amounts in thousands):

Gas gathering, processing and transportation	$	1,770
Oil and gas properties and equipment	$	136,778
Other long-term liabilities	$

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 months ended March 31, 2006 from hedging activities of $8.5 million.  A net gain was recognized in earnings through Sale of gas and Sale of natural gas liquids during the three months ended March 31, 2005 from hedging activities of $487,000. 

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 months ended March 31, 2006 related to employee stock options, including compensation from our February 2006 grants is as presented in the following table. 

8

(Amounts in thousands, except per share amounts)	Quarter ended March 31, 2006
Incremental stock-based compensation expense recognized through earnings	$	2,842
Related deferred income tax benefit	(539		)
Decrease in net income	2,303
Decrease in earnings per share of common stock	0.03
Decrease in earnings per share of common stock – assuming dilution	0.03
Stock-based compensation expense capitalized	$	574

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 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 first quarter of 2006 includes compensation expense for share-based payment awards granted prior to, but not yet vested, as of January 1, 2006. This expense 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 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 quarter of 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 March 31, 2006, the compensation expense related to non-vested awards to be recognized in future periods totals $26.2 million. The weighted average period over which this expense is expected to be recognized is 2.2 years.

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 adopted the alternative method during the first quarter of 2006 and may adopt it in a subsequent quarter.

NOTE 4 – SHARE BASED COMPENSATION

A description of our share based compensation plans in effect at March 31, 2006 is as follows:

1999 Non-Employee Directors Stock Option Plan. Effective March 1999, the board of directors adopted a 1999 Non-Employee Directors’ Stock Option Plan, or 1999 Directors Plan, that authorized the granting of options to purchase 30,000 shares of our common stock. During 1999, the board approved options grants covering 30,000 shares to several board members. Under this plan, each of these options becomes exercisable as to 33 1/3% of the shares covered by it on each anniversary from the date of grant. This plan terminates on the earlier of March 12, 2009 or the date on which all options granted under the plan have been exercised in full.

1997 and 1999 Stock Option Plans. The 1997 Stock Option Plan, or 1997 Plan, and the 1999 Stock Option Plan, or 1999 Plan, became effective on May 21, 1997, and May 21, 1999, respectively, after approvals by our stockholders. Each plan is intended to be an incentive stock option plan in accordance with the provisions of Section

9

422 of the Internal Revenue Code of 1986, as amended. We reserved 2,000,000 shares of common stock for issuance upon exercise of options under the 1997 Plan and 1,500,000 shares of common stock for issuance upon exercise of options under the 1999 Plan. The 1997 Plan and the 1999 Plan will terminate on the later of May 21, 2007 and May 21, 2009, respectively, or the date on which all the respective options granted under each of the plans have expired or been exercised in full. Although options covering 745,204 shares are available to be granted under the 1997 Plan, no further options will be granted under this plan.

Chief Executive Officer and President’s Plan (“CEO Plan”). Pursuant to the Employment Agreement, dated October 15, 2001, and the Stock Option Agreement, dated as of November 1, 2001, between us and Peter A. Dea, our Chief Executive Officer and President, non-qualified stock options were granted for the purchase of 600,000 shares of our common stock. The exercise price of the options was equal to $2.50 below the closing price per share on the effective date of the Employment Agreement. The stock options are subject to the conditions of the Agreements and vested equally over four years. The difference between the closing price on the effective date and the exercise price was amortized over four years as compensation expense. This option plan will terminate on the earlier of October 15, 2010 or the date on which all options granted under the plan have been exercised in full. On August 1, 2005, we entered into a new employment agreement with Mr. Dea, which due to recent changes in the tax laws required that he exercise, on or before March 15, 2006, options to purchase 150,000 shares of our common stock, which vested on November 15, 2005.

2002 Non-Employee Directors Stock Option Plan. Effective May 2002, our stockholders approved the 2002 Non-Employee Directors’ Stock Option Plan, or 2002 Directors Plan, that authorized the granting of options to purchase 220,000 shares of our common stock. The 2002 Directors Plan provides for a three-year vesting schedule while the non-employee director serves on our board. Under this plan, a newly elected non-employee director will be granted options to acquire 10,000 shares of common stock as of the date of election. The 2002 Directors Plan also provides for an annual grant on the date of our annual meeting to each non-employee director options to acquire 4,000 shares of common stock. The purchase price of the stock under each option shall be the fair market value of the stock at the time such option is granted. The 2002 Directors Plan requires the non-employee director to exercise the option at the earlier of ten years from the date of the plan or within five years of the date each portion vests, or such options expire. The non-employee director’s right to exercise options under the 2002 Directors Plan is subject to continuous service since the grant was made. If the non-employee director dies or becomes disabled (within the meaning of the 2002 Directors Plan) or a change of control occurs, then all the options granted to the non-employee director shall become 100% exercisable. The 2002 Directors Plan will terminate on the later of May 17, 2012 or the date on which all options granted under the plan have expired or been exercised in full.

2002 Stock Option Plan. Effective May 2002, our stockholders approved the 2002 Stock Incentive Plan, or 2002 Plan, that authorized the granting of options to purchase 2,500,000 shares of our common stock. No employee may be granted options to acquire more than 250,000 shares of common stock in any fiscal year. The 2002 Plan requires the employee to exercise the option at the earlier of ten years from the date of the 2002 Plan or within five years of the date each portion vests, or such options expire. The employee’s right to exercise options under the 2002 Plan is subject to continuous employment since the grant was made. If the employee dies, becomes disabled (within the meaning of the 2002 Plan) or a change of control occurs, then all the options granted to the employee shall become 100% exercisable. The 2002 Plan will terminate on the later of May 17, 2012 or the date on which all options granted under the plan have expired or been exercised in full.

2005 Stock Option Plan. Effective May 2005, our stockholders approved the 2005 Stock Incentive Plan, or 2005 Plan, that authorized the granting of options to purchase 2,500,000 shares of our common stock and the granting of 1,500,000 shares of restricted common stock. No employee may be granted options to acquire more than 250,000 shares of common stock or 150,000 shares of restricted common stock in any fiscal year. The 2005 Plan requires the employee to exercise the options at the earlier of five years of the date each portion vests or seven years from the date the options are granted, or such options expire. The employee’s right to exercise options under the 2005 Plan is subject to continuous employment since the grant was made. If a change of control occurs, then all of the options granted to the employee shall become 100% exercisable and all restricted shares become vested. The 2005 Plan will terminate on the later of May 6, 2015 or the date on which all options granted under the plan have expired or been exercised in full.

Under each of the 1997, 1999, 2002 and 2005 plans (including the non-employee director plans), our board of directors determines and designates from time to time our employees to whom options or restricted shares are to be granted. If any option terminates or expires prior to being exercised, the shares relating to such option are released and may be subject to re-issuance pursuant to a new option. The purchase price of the stock under each option shall be the average closing price for the ten days prior to the grant. Under the 1997, 1999, 2002 and 2005 Plans, our

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board of directors has the authority to set the vesting schedule based on service from 20% per year to 33 1/3% per year. Under each of the plans, the employee must exercise the option within five years of the date each portion vests.

In the first quarter of 2006, we granted to our employees options to purchase approximately 686,000 shares of our common stock at the market based on the average closing price for the ten days prior to grant, and approximately 280,000 shares of restricted common stock to our employees. In the first quarter of 2005, we granted options to purchase 83,000 shares of our common stock at the market based on the average closing price for the ten days prior to grant. We did not grant any restricted common stock during the first quarter of 2005. 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 quarters ended March 31, 2006 and 2005, we recognized a tax benefit from our stock options of $2.3 million.

The following is a summary of the options to purchase our common stock granted and the weighted average fair value per share of the options granted during the quarters ended March 31, 2006 and 2005, respectively.

	Quarter Ended March 31,
	2006		2005
2002 Plan
Options granted	6,200		83,000
Weighted average fair value per share	$	15.06	$	15.65
2005 Plan
Options granted	660,026		—
Weighted average fair value per share	$	19.17	—
2002 Directors Plan
Options granted	20,000		—
Weighted average fair value per share	$	19.45	—

During the quarter ended March 31, 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	4.90		%	5.11		%	5.11		%
Expected life (in years)	4.5			4.33			4.5
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 March 31, 2006:

	Per Share Price Range		1997 Plan	1999 Plan	1999 Directors Plan	CEO Plan	2002 Plan	2002 Directors Plan	2005 Plan
Exercisable:
March 31, 2006	$	0.01–5.00	1,202	—	2,600	—	—	—	—
	$	5.01–10.00	2,800	—	—	—	—	—	—
	$	10.01–15.00	—	11,002	—	450,000	—	—	—
	$	15.01–20.00	—	345,232	—	—	299,010	46,667	—
	$	20.01–25.00	—	—	—	—	1,112	—	—
	$	25.01–30.00	—	34,115	—	—	230,550	9,333	—
	$	30.01–35.00	—	—	—	—	25,556	—	—
	$	35.01–40.00	—	—	—	—	1,668	—	—
	TOTAL		4,002	390,349	2,600	450,000	557,896	56,000	—
Available for Grant:
March 31, 2006	—		745,204	18,089	—	—	40,438	72,000	1,104,234

The following table summarizes the stock option activity related to options outstanding under our benefit plans during the quarter ended March 31, 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	—		—		—		—		6,200		20,000	660,026
Exercised	$	2.76-35.71	(2,000	)	(38,773	)	(4,000	)	(45,000	)	(161,335	)	—	—
Forfeited or expired	$	16.48-50.05	—		(1,001	)	—		—		(16,137	)	—	(8,986	)
Balance at 3/31/06			4,002		511,041		2,600		450,000		1,645,882		132,000	1,395,766
Weighted-average remaining contractual life (years)			2.0		5.0		1.0		3.6		5.3		5.0	6.2

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The following table summarizes the weighted average option exercise price information under our benefit plans during the quarter ended March 31, 2006:

	1997 Plan			1999 Plan			1999 Directors Plan			CEO Plan			2002 Plan			2002 Directors Plan		2005 Plan
Balance at 12/31/05	$	5.11		$	19.32		$	2.76		$	12.51		$	24.31		$	24.99	$	31.86
Granted	—			—			—			—			47.35			43.43		43.43
Exercised	(5.82		)	(17.40		)	(2.76		)	(12.51		)	(20.28		)	—		—
Forfeited or expired	—			(28.35		)	—			—			(23.79		)	—		(34.67		)
Balance at 3/31/06	$	4.76		$	19.45		$	2.76		$	12.51		$	24.80		$	27.79	$	37.31

The total aggregate intrinsic value of options exercised in the quarter ended March 31, 2006 was approximately $7.2 million. The total aggregate intrinsic value of exercisable options at March 31, 2006 was approximately $45.5 million and the total aggregate intrinsic value of outstanding options at March 31, 2006 was approximately $87.7 million.

The following table summarizes the status of the shares of outstanding restricted stock as of March 31, 2006 and changes during the quarter ended March 31, 2006:

	2005 Plan
Balance at 12/31/05	377,565
Granted	279,943
Exercised	—
Forfeited or expired	(8,609		)
Balance at 3/31/06	648,899
Weighted-average grant date fair value per share of restricted stock	$	39.49
Weighted-average remaining contractual life (years)	1.5

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 first quarter 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):

	Quarter Ended March 31, 2005
	As Reported			Pro Forma
Net income	$	19,706		$	18,027
Earnings per share of common stock	0.27			0.24
Earnings per share of common stock – assuming dilution	0.26			0.24
Stock-based employee compensation cost, net of related tax effects, included in net income	178			—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$		—	$	1,857

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, collectively with the Marketing and Transportation segments referred to as the midstream operations, we connect producers’ wells (including those of our Exploration and Production segment) to our gathering systems for delivery of natural gas to

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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 77% of our plant facilities’ gross margin, or revenues at the plant less product purchases, or 38% of our plant facilities’ throughput volume for the month of March 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 21% of our plant facilities’ gross margin, or 54% of our plant facilities’ throughput volume, for the month of March 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 2% of our plant facilities’ gross margin, or 8% of our plant facilities’ throughput volume, for the month of March 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, include 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 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 three months ended March 31, 2006 (dollars in thousands).

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	Three Months Ended March 31, 2006
Beginning balance at December 31, 2005	$	101,796
Additions to capitalized exploratory well costs pending the determination of proved reserves	42,027
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves	(2,045		)
Capitalized exploratory well costs charged to expense	—
Ending balance at March 31, 2006	$	141,778

Period end capitalized exploratory well costs (000s) and number of gross wells at March 31, 2006 are as follows:

	Exploratory Well Costs		Number of wells
Exploratory well costs capitalized for a period of one year or less	$	93,556	582
Exploratory well costs capitalized for a period of greater than one year	48,222		618
Total exploratory well costs capitalized at March 31, 2006	$	141,778	1,200

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 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 quarters ended March 31, 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.

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Quarter Ended March 31, 2006:

	Gas Gathering and  Processing			Exploration and Production			Marketing		Transportation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas and NGLs	$	298		$	2,911		$	926,347	$	1,002		$	—		$	—		$	930,558
Equity hedges	1,101			7,419			—		—			—			—			8,520
Gathering, processing and transportation revenue	24,862			—			—		1,837			—			—			26,699
Total revenues from unaffiliated customers	26,261			10,330			926,347		2,839			—			—			965,777
Inter-segment revenues	332,699			101,525			26,818		3,341			115			(464,498		)	—
Price risk management activities	—			(3,582		)	24,562		—			—			—			20,980
Interest income and Other, net	1,642			95			3		—			17,658			(17,074		)	2,324
Total revenues	360,602			108,368			977,730		6,180			17,773			(481,572		)	989,081
Product purchases and operating expenses	306,620			40,355			952,473		2,135			117			(464,834		)	836,866
(Earnings) from equity investments	(2,374		)	—			—		—			—			—			(2,374		)
Segment operating profit	56,356			68,013			25,257		4,045			17,656			(16,738		)	154,589
Depreciation, depletion and Amortization	13,603			19,135			2		464			2,158			—			35,362
Selling and administrative expense	—			—			—		—			18,813			(9		)	18,804
(Gain) loss from sale of assets	(2		)	785			—		265			(4		)	—			1,044
Interest expense	—			—			430		(312		)	20,141			(17,074		)	3,185
Income before income taxes	$	42,755		$	48,093		$	24,825	$	3,628		$	(23,452	)	$	345		96,194
Identifiable assets:
Property and equipment and other allocated assets	$	895,916		$	850,573		$	193,826	$	84,249		$	405,423		$	(83,818	)	$	2,346,169
Equity investments	39,249			—			—		1,205			1,051,755			(1,052,960		)	39,249
Total identifiable assets	$	935,165		$	850,573		$	193,826	$	85,454		$	1,457,178		$	(1,136,778	)	$	2,385,418

Quarter Ended March 31, 2005:

	Gas Gathering and Processing			Exploration and Production			Marketing			Transportation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas and NGLs	$	(178	)	$	4,035		$	824,099		$	745		$	—		$	—		$	828,701
Equity hedges	(739		)	1,226			—			—			—			—			487
Gathering, processing and transportation revenue	22,292			(162		)	—			1,750			—			—			23,880
Total revenues from unaffiliated customers	21,375			5,099			824,099			2,495			—			—			853,068
Inter-segment revenues	275,854			69,268			17,704			3,442			10			(366,278		)	—
Price risk management activities	(87		)	—			(20,161		)	—			—			—			(20,248		)
Interest income and Other, net	1,105			6			—			—			9,682			(9,506		)	1,287
Total revenues	298,247			74,373			821,642			5,937			9,692			(375,784		)	834,107
Product purchases and operating expenses	248,092			35,421			840,045			2,670			—			(366,279		)	759,949
(Earnings) from equity investments	(2,134		)	—			—			—			—			—			(2,134		)
Segment operating profit	52,289			38,952			(18,403		)	3,267			9,692			(9,505		)	76,292
Depreciation, depletion and amortization	11,279			15,629			35			403			1,732			—			29,078
Selling and administrative expense	—			—			—			—			12,542			(10		)	12,532
(Gain) loss from sale of assets	31			—			—			(3		)	—			—			28
Interest expense	5			1			2			(154		)	13,172			(9,506		)	3,520
Income before income taxes	$	40,974		$	23,322		$	(18,440	)	$	3,021		$	(17,754	)	$	11		$	31,134
Identifiable assets:
Property and equipment and other allocated assets	$	717,521		$	522,394		$	116,164		$	44,822		$	488,061		$	(98,095	)	$	1,830,867
Equity investments	36,108			—			—			1,071			757,071			(758,142		)	36,108
Total identifiable assets	$	753,629		$	522,394		$	116,164		$	85,893		$	1,245,132		$	(856,237	)	$	1,866,975

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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 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

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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 certain remedial steps to address the items contained in the Notice of Violation.

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 NOVs and any potential monetary penalties, which have not been determined.

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 financial position, results of operations or cash flow.

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.

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

In order to minimize transportation costs or make product available at a location of our customer’s preference, from time to time, we will enter into arrangements to buy product from a party at one location and arrange to sell a like quantity of product to this same party at another location.  In accordance with EITF 04-13, these transactions will be required to be reported on a sales net of purchases basis.  This EITF is effective for transactions entered into or modified in the first interim or annual period beginning after March 15, 2006.  For us this EITF will be effective in the quarter ended June 30, 2006.  To the extent transactions are required to be netted, this will result in a reduction of revenues and costs by an equal amount, but the netting will have no impact on net income or cash flows. 

In accordance with EITF 03-11, we record revenue on these transactions on a gross basis versus sales net of purchases basis because we obtain title to the product that we buy, bear the risk of loss, credit and performance exposure on these transactions, and take physical delivery of the product.  For the quarters ended March 31, 2006

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and 2005, we recorded revenues of $30.7 million and $28.7 million, respectively, and product purchases of $28.6 million and $26.7 million, respectively, for transactions which were entered into concurrently and with the intent to buy and sell like quantities with the same counterparty at different locations and at market prices at those locations. 

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

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.

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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 months ended March 31, 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.

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.

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:

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 first quarter of 2006, our average production sold was 188 MMcfe per day, which was a 14.6% increase over the average production volume sold in the first 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, 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 March 31, 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 approximately $136.7 million before adjustments. 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.

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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 first quarter of 2006 increased slightly as compared to the same period in 2005 and averaged a total of 1.38 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 months ended March 31, 2006 compared to the three months ended March 31, 2005

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

	Quarter Ended March 31,
	2006			2005			Percent Change
Financial results:
Revenues	$	989,081		$	834,107		19
Net income	61,862			19,706			214
Earnings per share of common stock	0.82			0.27			204
Earnings per share of common stock – assuming dilution	0.81			0.26			208
Net cash provided by operating activities	188,010			117,396			60
Net cash used in investing activities	(263,899		)	(114,241		)	(131	)
Net cash provided by (used in) financing activities	56,271			(1,820		)	3,238
Operating data:
Average gas sales (MMcf/D)	1,107			1,302			(15	)
Average NGL sales (MGal/D)	1,836			1,763			4
Average gas prices ($/Mcf)	$	7.72		$	5.91		31
Average NGL prices ($/Gal)	$	1.01		$	0.84		20

Net income increased $42.2 million for the three months ended March 31, 2006 compared to the same period in 2005. In this quarter, we had higher production of equity gas volumes and higher product prices as compared to the first quarter of 2005. In addition to the benefit of higher production and prices, net income also increased due to an increase in the non-cash mark-to-market valuation of our derivatives. Partially offsetting these items was an increase in depreciation, depletion and amortization and selling and administrative expenses in the first quarter of 2006.

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Revenues from the sale of gas increased $75.4 million to $771.7 million for the three months ended March 31, 2006 compared to the same period in 2005. This increase was primarily due to an increase in product prices in the three months ended March 31, 2006. Average gas prices realized by us increased $1.81 per Mcf to $7.72 per Mcf for the quarter ended March 31, 2006 compared to the same period in 2005. Included in the realized gas price were approximately $8.5 million of gains recognized in the three months ended March 31, 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 for 2007. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk”. Average gas sales volumes decreased by 15% to 1,107 MMcf per day for the quarter ended March 31, 2006 compared to the same period in 2005.

Revenues from the sale of NGLs increased $34.4 million to $167.4 million for the three months ended March 31, 2006 compared to the same period in 2005. This increase is primarily due to an increase in product prices. Average NGL prices realized by us increased $0.17 per gallon to $1.01 per gallon for the three months ended March 31, 2006 compared to the same period in 2005. We have entered into futures positions for approximately 55% of our equity NGL production for the remainder of 2006. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk”. Average NGL sales volumes increased 4% to 1,836 MGal per day for the three months ended March 31, 2006 compared to the same period in 2005.

The effect of Price risk management activities changed from $(20.2) million for the quarter ended March 31, 2005 to $21.0 million for the quarter ending March 31, 2006. This change was due to the non-cash mark-to-market adjustments of our risk management activities. This account was primarily affected by changes in the forward price of natural gas in the 2006 quarter as compared to 2005 quarter and the impact of those price changes on the fair value of the forward sale derivatives for our gas in storage.

Product purchases increased by $68.8 million for the quarter ended March 31, 2006 compared to the same period in 2005 as a result of the increase in product prices. Overall, combined product purchases as a percentage of sales of all products decreased to 83% in the first quarter of 2006 as compared to 85% in the first quarter of 2005. This decrease is due to the reduction in third party sales volumes of natural gas and an increase in our equity production.

Plant and transportation operating expense increased by $4.5 million for the quarter ended March 31, 2006 compared to the same period in 2005. The increase was primarily due to increases in labor costs, and costs for chemicals, lubricants and other supplies.

Oil and gas exploration and production expenses increased by $3.6 million for the quarter ended March 31, 2006 compared to the same period in 2005. The increase was substantially due to higher production taxes resulting from increased product prices. Overall, lease operating expenses, or LOE, averaged $0.77 per Mcf for the quarter ended March 31, 2006, and LOE in the Powder River Basin coal bed development averaged $0.78 per Mcf. In the Powder River Basin, this represents a decrease of $0.09 per Mcf as compared to the quarter ended March 31, 2005. The decrease in LOE per Mcf in the Powder River Basin is substantially due to higher production volumes without corresponding increases in costs.

Depreciation, depletion and amortization, or DD&A, increased by $6.3 million in the quarter ended March 31, 2006 compared to the same period in 2005. In total, we had a $2.3 million increase in DD&A in our midstream operations primarily due to our expanding CBM gathering system in the Powder River Basin and a $3.5 million increase in DD&A in our upstream operations primarily due to our continued development in the Powder River Basin.

Selling and administrative expenses increased by $6.3 million for the quarter ended March 31, 2006 as compared to the same period in 2005. This increase was primarily the result of increased administrative salaries and benefits, insurance, and compensation expense related to our restricted stock plan and the January 1, 2006 implementation of SFAS 123(R), which requires the expensing of compensation related to options on our common stock in addition to compensation related to our restricted stock.

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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 123R 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 months ended March 31, 2006 related to employee stock options, including compensation from our February 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 March 31, 2006
Incremental stock-based compensation expense recognized through earnings	$	2,842
Related deferred income tax benefit	(1,028		)
Decrease in net income	1,814
Decrease in earnings per share of common stock	0.02
Decrease in earnings per share of common stock – assuming dilution	0.02
Stock-based compensation expense capitalized	$	574

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, 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 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 quarter of 2006 includes compensation expense for share-based payment awards granted prior to, but not yet vested, as of January 1, 2006. This expense 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 will be 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 quarter of 2006 is based on awards ultimately expected to vest, it will be 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 March 31, 2006, the compensation expense related to non-vested awards to be recognized in future periods totals $26.2 million. The weighted average period over which this expense is expected to be recognized is 2.2 years.

Cash Flow Information

Cash flows from operating activities increased by $70.6 million in the first quarter of 2006 compared to the first quarter of 2005. This increase was primarily due to the increase in Net income and the timing of cash receipts and

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payables, and the change in our natural gas inventory positions.

Cash flows used in investing activities increased by $149.7 million in the first quarter of 2006 compared to the first quarter of 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 $58.1 million in the first quarter of 2006 compared to the first quarter of 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.

Segment Information

Gas Gathering, Processing and Treating. The Gas Gathering, Processing and Treating segment realized segment-operating profit of $56.4 million for the three months ended March 31, 2006 compared to $52.3 million in the same period in 2005. The increase in operating profit in this segment in the first quarter of 2006 was primarily due to higher realized prices and a 2% increase in throughput volume.

Exploration and Production. The Exploration and Production segment realized segment-operating profit of $68.0 million in the first quarter of 2006 compared to $39.0 million in 2005. The increase was due to increased equity production and higher product prices. During the first quarter of 2006, our production of natural gas as compared to the same period in 2005 increased by 18% to 16.9 Bcfe. The following table sets forth the average sales price received for our oil and gas products along with cost information in the three months ended March 31, 2006 and 2005.

	Quarter Ended March 31,
	2006		2005
Average sales price: (1)
Oil ($/Bbl), excluding the effect of hedging positions	$	58.46	$	43.83
Oil ($/Bbl), including the effect of hedging positions	58.46		43.83
Gas ($/Mcf), excluding the effect of hedging positions	6.12		4.89
Gas ($/Mcf), including the effect of hedging positions	6.57		4.97
Production and other costs:
Lease operating expense ($/Mcfe)	0.77		0.87
Production tax expense ($/Mcfe)	0.66		0.47
Gathering and transportation expense ($/Mcfe)
Inter-segment gathering and transportation charges	0.64		0.63
Third-party transportation charges	0.22		0.20
Other expenses ($/Mcfe)	0.02		0.01
Total costs ($/Mcfe)	$	2.31	$	2.18

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

Marketing. The Marketing segment realized a segment-operating profit of $25.3 million for the three months ended March 31, 2006 compared to a segment-operating loss of ($18.4) 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 quarter ended March 31, 2006 compared to a loss for the quarter ended March 31, 2005.

Transportation. The Transportation segment realized segment-operating profit of $4.0 million for the three months ended March 31, 2006 compared to $3.3 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

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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.

In the third quarter of 2005, the Gulf Coast of the United States was impacted by two major hurricanes. These storms resulted in the curtailment of natural gas and oil production from the Gulf of Mexico, and the operations of major refineries and gas processing facilities in Texas, Louisiana and Mississippi. Our operations did not sustain any physical damage from these hurricanes, and our liquidity was not materially impacted as our counterparties and customers continued to make timely payments. However, in September 2005, one of our customers, a utility serving the New Orleans area, filed for bankruptcy protection under Chapter 11 of the Bankruptcy Code. At the time of the bankruptcy filing, we had an outstanding account receivable from this utility of $4.1 million. In the third quarter of 2005, we reserved $800,000 against this amount, which represents our best estimate of the current market value of this receivable.

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.

We expect our dividends to total approximately $22.5 million in 2006. These dividends, and our $10.0 million of scheduled repayments of long-term debt in 2006, are expected to be funded with amounts available under the revolving credit facility.

Sources and Uses of Funds. Our sources and uses of funds for the quarter ended March 31, 2006 are summarized as follows (dollars in thousands):

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Sources of funds:
Borrowings under our revolving credit facility	$	957,100
Proceeds from the dispositions of property and equipment	1,152
Net cash provided by operating activities	188,010
Excess tax benefits from share-based payment awards	1,484
Proceeds from exercise of common stock options	4,806
Total sources of funds	$	1,152,552
Uses of funds:
Payments under our revolving credit facility (including debt issue costs)	$	872,114
Capital expenditures	265,051
Change in outstanding checks	29,344
Common dividends paid	5,661
Total uses of funds	$	1,172,170

Capital Investment Program. 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 certain 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 may be increased to provide for acquisitions if approved by our board of directors.

The 2006 capital budget and our capital expenditures during the quarter ended March 31, 2006 are presented in the following table (dollars in thousands).

Type of Capital Expenditure	2006 Capital Budget			Capital Expenditures During the Quarter Ended March 31, 2006
Gathering, processing, treating and pipeline assets	$	185.0	*	$	71.4	*
Exploration and production and lease acquisition activities	336.2			65.4
Acquisition of CBM properties	136.7			136.7
Information technology and other items	4.5			0.5
Capitalized interest and overhead	13.4			5.4
Total Capital Expenditures	$	675.8		$	279.4

*  Includes $22.2 million budgeted in 2006 and $3.7 million expended in the first quarter 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 approximately $136.7 million before adjustments. 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.

Contractual Commitments and Obligations

Contractual Commitments and Cash Obligations. A summary of our contractual commitments and cash obligations as of March 31, 2006 is as follows (dollars in thousands):

			Payments Due by Period
Contractual Obligations (1)	Total		Due in 2006		Due in 2007 – 2008		Due in 2009 – 2010		Due  Thereafter
Guarantee of Fort Union Project Financing	$	4,057	$	781	$	2,313	$	963	$	—
Operating Leases	71,579		13,909		32,716		20,232		4,722
Firm Transportation Capacity Agreements	238,899		33,958		85,760		59,283		59,898
Firm Storage Capacity Agreements	40,158		9,751		17,886		5,258		7,263
Long-term Debt	515,000		10,000		10,000		370,000		125,000
Interest on Long-term Debt (2)	113,144		22,221		57,319		25,026		8,578
Total Contractual Cash Obligations	$	982,837	$	90,620	$	205,994	$	480,762	$	205,461

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(1)  Not included in the table are approximately $3.0 million per year of various payments for right-of-way, surface use and midstream and upstream site leases that are cancelable when the properties are no longer in use.

(2) The interest rate assumed on the revolving credit facility at March 31, 2006 is 5.7% per annum. Actual interest rates are assumed for the debt under our master shelf agreement.

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

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

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

The fixed fees associated with our existing contracts for firm transportation capacity during 2006 will average approximately $0.17 per Mcf. The associated contract periods range from one month to eleven years. Under firm transportation contracts, we are required to pay the fees associated with these contracts whether or not the transportation is used.

Firm Storage Capacity Agreements. We customarily store gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and to capture seasonal price differentials. As of March 31, 2006, we had contracts in place for approximately 17.0 Bcf of storage capacity at various third-party facilities. Firm storage agreements generally require the payment of fixed monthly fees regardless of the quantity of gas that is in storage under a particular agreement.

The fees associated with these contracts in 2006 will average $0.76 per Mcf of annual capacity. The associated contract periods at March 31, 2006 had an average term of 36 months. At March 31, 2006, we held gas in our contracted storage facilities and in imbalances of approximately 14.0 Bcf at an average cost of $6.76 per Mcf compared to 13.4 Bcf at an average cost of $5.83 per Mcf at March 31, 2005. These positions are for storage withdrawals within the next thirteen months. At the time we place product into storage, we contract for the sale of that product, physically or financially, and do not speculate on the future value of the product.

At March 31, 2006, we held NGLs in line pack and in storage at various third-party facilities of 2,770 MGal, consisting primarily of propane and ethane, at an average cost of $0.39 per gallon compared to 3,669 MGal at an average cost of $0.45 per gallon at March 31, 2005.

Long-term Debt

 Revolving Credit Facility. At March 31, 2006, the commitment under the revolving credit facility was $700 million with a maturity date in November 2010. At March 31, 2006, $370.0 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

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debt to capitalization ratio. This fee is paid on unused amounts of the commitment. As of March 31, 2006, the interest rate payable on borrowings under this facility was approximately 5.7% 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.

Master Shelf Agreement. Amounts outstanding under our master shelf agreement at March 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	$	20,000	7.61	%	July 28, 2007	$10,000 on July 28, 2006 and 2007
June 30, 2004	100,000		5.92	%	June 30, 2011	Single payment at maturity
January 18, 2005	25,000		5.57	%	January 18, 2015	Single payment at maturity
Total	$	145,000

Our borrowings under our master shelf agreement are secured by a pledge of the capital stock of our significant subsidiaries. These subsidiaries also guarantee the borrowings under this facility. All of the borrowings under our master shelf agreement can be prepaid prior to their final maturity by paying a yield-maintenance fee. Under our master shelf agreement, we are subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55% and maintaining a quarterly test of EBITDA, as defined in our master shelf agreement, to interest for the last four quarters in excess of 3.0 to 1.0. During 2006, we will make scheduled payments totaling $10.0 million on this facility. We intend to fund this repayment with funds available under the revolving credit facility.

Upstream Operations

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

Our principal upstream operations are summarized in the following table:

Production Area	Gross Acres Under Lease at March 31, 2006	Net Acres Under Lease at March 31, 2006	Average Net Production Sold for the Quarter Ended March 31, 2006 (MMcfe/day)	Gross Productive Gas Wells at March 31, 2006	Net Productive Gas Wells at March 31, 2006
Powder River Basin CBM	1,062,000	561,000	125	5,387	2,547
Pinedale Anticline/Jonah	132,000	24,000	45	384	43
San Juan Basin	30,000	29,000	12	185	164
Sand Wash Basin	113,000	107,000	5	23	23
Red Desert/Washakie/Uinta	76,000	47,000	1	8	3
Denver-Julesburg Basin	385,000	331,000	—	9	9
Canada	44,000	43,000	—	22	21
Central Montana	639,000	562,000	—	—	—
Other	30,000	26,000	—	10	2
Total	2,511,000	1,730,000	188	6,028	2,812

Drilling Results. The following table sets forth the number of wells we completed during the quarters ended March 31, 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

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number of productive wells drilled, quantities of reserves found or economic value. Productive wells are producing wells and wells capable of production.

	Three Months Ended March 31,
	2006		2005
Productive Area	Gross	Net	Gross	Net
Powder River Basin CBM
Productive wells completed	207	93	145	77
Pinedale Anticline and Jonah Fields
Development productive wells completed	8	1	7	1
Exploratory productive wells completed	2	0	3	0
Dry exploratory wells drilled	0	0	1	0
San Juan Basin
Development productive wells completed	9	9	12	11
Exploratory productive wells completed	4	4	5	5
Sand Wash Basin
Dry exploratory wells completed	0	0	1	1
Canada (1)
Exploratory productive wells completed	4	4	0	0
Other (1)
Exploratory productive wells completed	3	1	0	0

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

Powder River Basin Coal Bed Methane. We continue to develop our Powder River Basin CBM reserves and expand the associated gathering system in northeast Wyoming. Our net production sold from the Powder River Basin CBM averaged 125 MMcf per day in the first quarter of 2006.

Our production from the Big George coal continues to increase and averaged 185 MMcf per day gross, or 71 MMcf per day net, in April 2006 from various development areas. In these development areas and our areas of exploration, as of March 31, 2006, we had 1,217 gross Big George wells producing gas, 1,367 gross Big George wells dewatering or awaiting connection to begin dewatering. Typically 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.

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

Our 2006 capital budget for the Powder River Basin CBM project is approximately $282.2 million, of which $136.7 million was expended in our March 2006 acquisition of properties. The remaining $145.5 million is for drilling, production equipment, leasehold acquisition and water treatment of approximately 900 gross wells. In 2006, in the Big George and related coals, we plan to participate in the drilling of approximately 850 gross wells, or

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450 net wells, and in the Wyodak and related coals, we plan to participate in an additional 100 gross wells, or 50 net wells. Together with our co-developer, we have received 45% of the drilling permits and 54% of the water discharge permits required for our drilling program for 2006. The remainder of our 2006 federal and state permits required for our 2006 drilling program have been submitted to the respective agencies. There is, however, no assurance as to the future timing of the receipt of drilling and water discharge permits, any changes in regulations governing drilling and water discharge,  the success of our drilling program, the availability of materials used in water treatment, or the dewatering time as our development progresses into the western and northern parts of the Powder River Basin. During the first quarter of 2006, we expended approximately $168.6 million in the Powder River Basin CBM project for the March 2006 property acquisition, drilling costs, production equipment and other lease acquisitions.

In 2003, the BLM issued the final Record of Decision, or ROD, for the Powder River Basin Oil & Gas Environmental Impact Statement, or EIS. The ROD requires additional surveys for plant and animal species, cultural surveys and noxious weed mitigation prior to the BLM granting a drilling permit. A number of cases have been filed by environmental groups against the BLM in Wyoming disputing the validity of the EIS and ROD. Due to our interests in developing federal leases in the Powder River Basin, we are an intervenor defendant in these cases. In one of these cases filed in the United States District Court of Montana, the court was asked to address the adequacy of the Montana Powder River Basin ROD and whether the BLM should have issued a single EIS for the Powder River Basin. Under an Order dated March 4, 2005, the court found that a single EIS for the Powder River Basin is not required under the National Environmental Policy Act, or NEPA, but remanded the EIS back to the BLM for further analysis. As these cases proceed, the BLM, in the event of any adverse rulings, may be required to perform further environmental analysis and, in addition, could be ordered to cease issuing drilling permits until it has completed such further analysis. Consequently, our ability to receive permits and develop our leases may be delayed or restricted by the outcome of these cases.

Pinedale Anticline and Jonah Fields. Our exploration and production assets in the Green River Basin of southwest Wyoming are located in the Pinedale Anticline and Jonah Field areas. During 2006, we expect to participate as a non-operating working interest in the drilling of 132 gross wells, or approximately 15 net wells, on the Pinedale Anticline and in the Jonah Field. Our capital budget for 2006 in the Pinedale Anticline area provides for expenditures of approximately $78.2 million for drilling costs and production equipment. During the first quarter of 2006, we expended approximately $15.0 million in the Pinedale Anticline and Jonah Field for drilling costs and production equipment.

Historically, drilling in the Jonah Field and on the Pinedale Anticline has been allowed on one well per 40-acre tract. More recently, the State of Wyoming has approved the drilling of two wells per 40-acre tract on most of the Pinedale Anticline and four wells per 40-acre tract in the Jonah Field and on a portion of the Pinedale Anticline. As a result, we have significantly increased our number of drilling locations in these areas. The BLM has also approved several 10 acre density well programs on a pilot basis for the Pinedale Anticline.

Midstream Operations

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

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

Our 2006 capital budget for midstream activities provides for expenditures of $185.0 million.  This capital budget includes $61.1 million for gathering and compression in the Powder River Basin of Wyoming, $17.5 million for compression and loop lines to expand the capacity of our Red Desert Complex, $24.6 million to complete the

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expansion of our Oklahoma system, and $32.1 million for new well connects to our facilities throughout our operations.

Transportation Operations

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

Marketing

Gas. We market gas produced from our wells and gas processed at our plants, as well as gas purchased from third-parties to end-users, local distribution companies, or LDCs, pipelines and other marketing companies throughout the United States and Canada. In addition to our offices in Denver, we have marketing offices in Houston, Texas and Calgary, Alberta. Third-party sales, firm transportation capacity on interstate pipelines and our gas storage positions, combined with the stable supply of gas from our facilities and production, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods.

One of the primary goals of our gas marketing operations continues to be the preservation and enhancement of the value received for our equity volumes of natural gas. This goal is achieved through the use of hedges on the production of our equity natural gas and through the use of firm transportation capacity. 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 for both our equity production and for gas purchased from third-parties in the Rocky Mountain region.

NGLs. We market NGLs, or ethane, propane, iso-butane, normal butane, natural gasoline and condensate, produced at our plants and purchased from third-parties, in the Rocky Mountain, Mid-Continent and Southwestern regions of the United States. A majority of our production of NGLs moves to the Gulf Coast and Mid-Continent areas, which are the largest NGL markets in the United States. Through the development of end-use markets and distribution capabilities, we seek to ensure that products from our plants move on a reliable basis, avoiding curtailment of production.

Consumers of NGLs are primarily the petrochemical industry, the petroleum refining industry and the retail and industrial fuel markets. As an example, the petrochemical industry uses ethane, propane, normal butane and natural gasoline as feedstocks in the production of ethylene, which is used in the production of various plastics and clothing products. Further, consumers use propane for home heating, transportation and agricultural applications. Price, seasonality and the economy primarily affect the demand for NGLs.

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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.

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

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

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

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

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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.

To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must be highly effective at offsetting changes in the price of the forecasted transaction being hedged so that our exposure to the risk of commodity price changes is reduced. To meet this requirement, we hedge the price of the commodity and, if applicable, the basis between that derivative’s contract delivery location and the cash market location used for the actual sale of the product. This structure attains a high level of effectiveness, ensuring that a change in the price of the forecasted transaction will result in an equal and opposite change in the price of the derivative instrument hedging the transaction. We utilize crude oil as a surrogate hedge for natural gasoline and condensate. Our hedges are tested for effectiveness at inception and on a quarterly basis thereafter. We use regression analysis based on a five-year period of time for this test. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Price risk management activities. During the first quarter of 2006, we recognized no gains or losses from ineffectiveness from our cash flow hedges.

Outstanding Equity Hedge Positions and the Associated Basis for 2006 and 2007. The following table details our hedge positions as of March 31, 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.

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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. 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 from April through December with an average minimum price of $7.00 per MMBtu and an average maximum price of $10.25 per MMBtu	Mid-Continent – 40,000 MMBtu per day with an average basis price of $0.55 per MMBtu. Permian – 7,500 MMBtu per day with an average basis price of $0.97 per MMBtu. San Juan – 7,500 MMBtu per day with an average basis price of $1.38 per MMBtu and 5,000 MMBtu per day from April through December with an average basis price of $1.70 per MMBtu. Rocky Mountain – 20,000 MMBtu per day with an average basis price of $1.44 per MMBtu and 5,000 MMBtu per day from April through December with an average basis price of $1.71 per MMBtu. NGPL  Texas Oklahoma – 10,000 MMBtu per day with an average basis price of $0.45 per MMBtu and 20,000 MMBtu per day from April through December with an average basis price of $0.55 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 for April through December 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 for April through December with an average minimum price of $0.83 per gallon and an average maximum price of $1.04 per gallon.	Not Applicable

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Account balances related to hedging transactions (designated as cash flow hedges under SFAS 133) at March 31, 2006 were $29.0 million in Current assets from price risk management activities, $4.9 million in Long term assets from price risk management activities, $3.2 million in Current liabilities from price risk management activities, $11.2 million in Deferred income tax payable, net, and a $19.5 million after-tax unrealized gain in Accumulated other comprehensive income, a component of Stockholders’ equity. Of the unrealized gain in Accumulated other comprehensive income at March 31, 2006, $16.3 million will be reclassified to earnings in 2006 and $3.2 million will be reclassified to earnings in 2007.

Earnings Sensitivities. At March 31, 2006, we held gas in our contracted storage facilities and in imbalances of approximately 14.0 Bcf. 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 $14.0 million and a $1.00 decrease in the forward price of gas in the anticipated month of withdrawal would increase pre-tax earnings by $14.0 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 March 31, 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. As 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 March 31, 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	61,728
Increase in value due to new contracts entered into during the period	16,930
Contract settlements during the period	(48,600		)
Changes in fair value attributable to changes in valuation techniques	—
Fair value of contracts outstanding at March 31, 2006	$	50,198

A summary of the sources of fair value of our net outstanding derivative positions at March 31, 2006 is as follows (dollars in thousands):

	Fair Value of Contracts at March 31, 2006
Source of Fair Value	Total Fair Value		Maturing In 2006		Maturing In 2007-2008		Maturing In 2009-2010		Maturing Thereafter
Exchange published prices	$	6,515	$	5,656	$	859	—		—
Other actively quoted prices (1)	29,498		21,415		8,083		$	—	—
Other valuation methods (2)	14,185		13,064		1,121		—		—
Total fair value	$	50,198	$	40,135	$	10,063	$	—	—

(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 March 31, 2006, we had sold forward contracts for $40.6 million in Canadian dollars in exchange for $35.5 million in United States dollars, and the fair market value of these contracts was a gain of $285,500 in United States dollars.

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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 March 31, 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 March 31, 2006, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 6.    EXHIBITS

Exhibit
Number	Description
3.1	Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.1 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.2	Certificate of Amendment to the Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.2 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.3	Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock (previously filed as part of Exhibit 1 to our Form 8-A filed on March 30, 2001 and incorporated herein by reference).
3.4	Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on 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).
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.

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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: May 9, 2006	WESTERN GAS RESOURCES, INC.
	(Registrant)
	By:	/s/ PETER A. DEA
		Peter A. Dea
		Chief Executive Officer and President
Date: May 9, 2006	By:	/s/WILLIAM J. KRYSIAK
		William J. Krysiak
		Executive Vice President - Chief Financial Officer
		(Principal Financial and Accounting Officer)

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INDEX TO EXHIBITS

Exhibit Number	Description
3.1	Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.1 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.2	Certificate of Amendment to the Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.2 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.3	Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock (previously filed as part of Exhibit 1 to our Form 8-A filed on March 30, 2001 and incorporated herein by reference).
3.4	Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on 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).
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

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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: May 9, 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: May 9, 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 March 31, 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 represents, in all material respects, the financial condition and results of operations of Western Gas Resources.

This Certification is executed as of May 9, 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