WESTERN GAS RESOURCES INC - 10-Q Quarterly Report

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2005

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

FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-10389

WESTERN GAS RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware		84-1127613
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1099 18^th Street, Suite 1200, Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

(303) 452-5603
Registrant’s telephone number, including area code

No Changes
(Former name, former address and former fiscal year, if changed since last report).

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

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

On May 4, 2005, there were 74,226,162 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, 2005 and December 31, 2004

	Consolidated Statement of Cash Flows - Three Months Ended March 31, 2005 and 2004

	Consolidated Statement of Operations - Three Months Ended March 31, 2005 and 2004

	Consolidated Statement of Changes in Stockholders’ Equity - Three Months Ended March 31, 2005

	Notes to Consolidated Financial Statements

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 3.	Quantitative and Qualitative Disclosures about Market Risk

Item 4.	Controls and Procedures

PART II - Other Information

Item 1.	Legal Proceedings

Item 6.	Exhibits

Signatures

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Unaudited)

(Dollars in thousands, except share data)

	March 31, 2005			December 31, 2004

ASSETS
Current assets:
Cash and cash equivalents	$	1,725		$	390
Trade accounts receivable, net	380,047			393,750
Inventory	64,592			94,604
Assets from price risk management activities	20,859			22,238
Other	6,134			12,494
Total current assets	473,357			523,476

Property and equipment:
Gas gathering, processing and transportation	1,191,722			1,150,904
Oil and gas properties and equipment (successful efforts method)	512,175			495,314
Construction in progress	199,183			150,273
	1,903,080			1,796,491
Less: Accumulated depreciation, depletion and amortization	(598,233		)	(570,582		)

Total property and equipment, net	1,304,847			1,225,909

Other assets:
Gas purchase contracts (net of accumulated amortization of $41,124 and $40,652, respectively)	34,426			27,704
Assets from price risk management activities	536			618
Equity investments	36,108			35,729
Other	26,403			26,676

Total other assets	97,473			90,727

TOTAL ASSETS	$	1,875,677		$	1,840,112

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	387,310		$	400,672
Accrued expenses	58,592			60,472
Liabilities from price risk management activities	31,206			11,099
Dividends payable	3,710			3,704
Total current liabilities	480,818			475,947

Long-term debt	385,900			382,000
Liabilities from price risk management activities	310			417
Other long-term liabilities	53,187			51,827
Deferred income taxes payable, net	251,737			247,893

Total liabilities	1,171,952			1,158,084

Stockholders’ equity:
Common stock, par value $.10; 100,000,000 shares authorized; 74,212,479 and 74,078,733 shares issued, respectively	7,444			7,430
Treasury stock, at cost; 50,032 common shares in treasury	(788		)	(788		)
Additional paid-in capital	394,962			392,437
Retained earnings	307,605			278,687
Accumulated other comprehensive income	(5,498		)	4,262

Total stockholders’ equity	703,725			682,028

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,875,677		$	1,840,112

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

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Three Months Ended March 31,
	2005			2004
Reconciliation of net income to net cash provided by operating activities:
Net income	$	32,628		$	29,088
Add income items that do not affect cash:
Depreciation, depletion and amortization	29,078			22,626
Loss on sale of assets	28			—
Deferred income taxes	11,364			10,465
Non-cash change in fair value of derivatives	8,469			6,219
Cumulative effect of change in accounting principle	—			(4,714		)
Compensation expense from common stock options	273			181
Other non-cash items, net	(1,220		)	(2,940		)

Adjustments to working capital to arrive at net cash provided by operating activities:
Decrease in trade accounts receivable	13,908			9,939
Decrease in product inventory	29,654			39,927
(Increase) decrease in other current assets	(1,261		)	642
(Increase) in other assets and liabilities, net	(407		)	(171		)
(Decrease) increase in accounts payable	(9,210		)	6,816
Increase in accrued expenses	5,485			7,932

Net cash provided by operating activities	118,789			126,010

Cash flows from investing activities:
Purchases of property and equipment, including acquisitions	(116,725		)	(36,955		)
Distributions from equity investees	324			—
Proceeds from the dispositions of property and equipment	767			315

Net cash used in investing activities	(115,634		)	(36,640		)

Cash flows from financing activities:

Proceeds from exercise of common stock options	2,307			2,918
Change in outstanding checks	(4,283		)	11,091
Borrowings on revolving credit facility	807,065			260,850
Payments on revolving credit facility	(803,165		)	(354,850		)
Borrowings on long-term debt	25,000			—
Payments on long-term debt	(25,000		)	—
Debt issue costs	(40		)	—
Payments for redemption of preferred stock	—			(672		)
Dividends paid	(3,704		)	(3,056		)

Net cash used in financing activities	(1,820		)	(83,719		)

Net increase in cash and cash equivalents	1,335			5,651

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

Cash and cash equivalents at end of period	$	1,725		$	31,767

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

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

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

	Three Months Ended March 31,
	2005			2004
Revenues:
Sale of gas	$	696,219		$	665,310
Sale of natural gas liquids	132,969			92,915
Gathering, processing and transportation revenue	23,880			16,829
Price risk management activities	(40		)	(5,480		)
Other	1,287			1,642
Total revenues	854,315			771,216

Costs and expenses:
Product purchases	707,354			657,342
Plant and transportation operating expense	27,699			21,934
Oil and gas exploration and production expense	24,896			17,110
Depreciation, depletion and amortization	29,078			22,626
Loss on sale of assets	28			—
Selling and administrative expense	12,532			9,946
(Earnings) from equity investments	(2,134		)	(1,926		)
Interest expense	3,520			5,802
Total costs and expenses	802,973			732,834
Income before taxes	51,342			38,382
Provision for income taxes:
Current	7,350			3,543
Deferred	11,364			10,465
Total provision for income taxes	18,714			14,008

Income before cumulative effect of changes in accounting principles	32,628			24,374

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

Net income	32,628			29,088

Preferred stock requirements	—			(816		)

Income attributable to common stock	$	32,628		$	28,272

Net income per share of common stock before cumulative effect of changes in accounting principles	$	0.44		$	0.34

Cumulative effect of change in accounting principle	$	—		$	0.07

Earnings per share of common stock	$	0.44		$	0.41

Weighted average shares of common stock outstanding	74,148,269			68,365,900

Income attributable to common stock - assuming dilution	$	32,628		$	29,088

Earnings per share of common stock - assuming dilution	$	0.43		$	0.39

Weighted average shares of common stock outstanding - assuming dilution	75,559,318			73,651,610

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

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(Dollars in thousands, except share amounts)

	Shares of Common Stock	Shares of Common Stock in Treasury	Common Stock		Treasury Stock			Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss) Net of Tax			Total Stock- holders’ Equity

Balance at December 31, 2004	74,078,733	50,032	$	7,430	$	(788	)	$	392,437		$	278,687		$	4,262		$	682,028
Comprehensive income:
Net income, first quarter of 2005	—	—	—		—			—			32,628			—			32,628
Translation adjustments	—	—	—		—			—			—			(2,271		)	(2,271		)
Other comprehensive income
From equity investees	—	—	—		—			—			—			77			77
Reclassification adjustment for settled contracts	—	—	—		—			—			—			(316		)	(316		)
Changes in fair value of outstanding hedge positions	—	—	—		—			—			—			(7,305		)	(7,305		)
Change in estimated ineffectiveness	—	—	—		—			—			—			55			55
Fair value of new hedge positions	—	—	—		—			—			—			—			—
Change in accumulated derivative comprehensive income	—	—	—		—			—			—			(7,566		)	(7,566		)
Total comprehensive income, net of tax	—	—	—		—			—			—			—			22,868
Stock options exercised	133,746	—	14		—			2,293			—			—			2,307
Compensation expense from common stock options	—	—	—		—			273			—			—			273
Tax benefit related to stock options exercised	—	—	—		—			(41		)	—			—			(41		)
Dividends declared on common stock	—	—	—		—			—			(3,710		)	—			(3,710		)

Balance at March 31, 2005	74,212,479	50,032	$	7,444	$	(788	)	$	394,962		$	307,605		$	(5,498	)	$	703,725

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

WESTERN GAS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

GENERAL

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

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

In March 2005, we revised our classification in the Statement of Cash Flows for the quarter ended March 31, 2004, of the Change in the balance of outstanding checks from a component of Net cash provided by operating activities to a component of Cash flows from financing activities. This change in classification had the effect of decreasing previously reported cash provided by operating activities by $11.1 million for the quarter ended March 31, 2004, with a corresponding decrease in cash flows used in financing activities.

EQUITY TRANSACTIONS

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

EARNINGS PER SHARE OF COMMON STOCK

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

	Quarter Ended March 31,
	2005		2004
Common Stock	$	3,710	$	1,765
Preferred Stock	—		789
Total Dividends Declared	$	3,710	$	2,554

Dividends Declared Per Share:
Common Stock	$	0.05	$	0.03
Preferred Stock	$	—	$	0.66

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

	Quarter Ended March 31,
	2005	2004
Weighted average shares of common stock outstanding	74,148,269	68,365,900
Potential common shares from:
Common stock options	1,411,049	1,815,528
$ 2.625 Cumulative Convertible Preferred Stock	—	3,470,182
Weighted average shares of common stock outstanding - assuming dilution	75,559,318	73,651,610

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

ACCUMULATED OTHER COMPREHENSIVE INCOME

Included in Accumulated other comprehensive income at March 31, 2005 were unrealized losses of $7.2 million from the fair value of derivatives designated as cash flow hedges and unrealized losses of $2.3 million of cumulative foreign currency translation adjustments.

Included in Accumulated other comprehensive income at March 31, 2004 were unrealized losses of $2.9 million from the fair value of derivatives designated as cash flow hedges and unrealized gains of $1.4 million of cumulative foreign currency translation adjustments.

REVENUE RECOGNITION

In the Gas Gathering, Processing and Treating segment, we recognize revenue for our services at the time the service is performed. We record revenue from our gas and NGL marketing activities, including sales of our equity production, upon transfer of title. In accordance with EITF 03-11, 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, 2005 and 2004 are immaterial. For our marketing activities, we utilize mark-to-market accounting for our derivatives. Under mark-to-market accounting, the expected margin to be realized over the term of the transaction is recorded in the month of origination. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods. 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 delivered from the pipeline.

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES

Depreciation, Depletion and Amortization for Oil and Gas Properties. We follow the successful efforts method of accounting for oil and gas exploration and production activities. Effective January 1, 2004, we redefined the asset groupings for the calculation of depreciation and depletion on our oil and gas properties from a well-by-well basis to a field wide basis for each of the Jonah, Pinedale and Sand Wash fields and to a grouping of all wells drilled into related coal seams for the Powder River Basin. The cumulative effect of the change in depreciation and depletion methodology for the quarter ended March 31, 2004 was a benefit of $4.7 million, net of tax, or $0.07 per share of common stock - assuming dilution, and is presented in the Consolidated Statement of Operations under the caption Cumulative effect of change in accounting principle, net of tax.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The net gain recognized in earnings through Sale of residue gas and Sale of natural gas liquids during the first three months of 2005 from hedging activities was $487,000. Also during this period we recognized a loss from hedge ineffectiveness of $87,000 through Price risk management activities.

The gains and losses currently reflected in Accumulated other comprehensive income will be reclassified to earnings as the hedged gas or NGLs is sold. Based on the prices for our products on March 31, 2005, approximately

$7.2 million of losses in Accumulated other comprehensive income is anticipated to be reclassified to earnings in 2005.

SUPPLEMENTARY CASH FLOW INFORMATION

Interest paid was $6.1 million and $3.0 million for the three months ended March 31, 2005 and 2004, respectively. No income taxes were paid in the three months ended March 31, 2005 and 2004.

STOCK COMPENSATION

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

We are required to record compensation expense (if not previously accrued) equal to the number of unexercised re-priced options multiplied by the amount by which our stock price at the end of any quarter exceeds $10.50 per share. We had options covering 27,000 and 48,438 common shares outstanding at March 31, 2005 and 2004, respectively, which were treated as repriced options. Based on our stock price at March 31, 2005 of $34.45 per share and our stock price at March 31, 2004 of $25.42 per share, expense of $140,000 and $181,000, respectively, was recorded in the three months ended March 31, 2005 and 2004.

SFAS No. 123 requires pro forma disclosures for each period that a statement of operations is presented. 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, 2005 and 2004, respectively.

	Quarter Ended March 31,
	2005		2004
2002 Plan
Options granted	83,000		35,000
Weighted average fair value per share	$	15.65	$	11.26

During the quarter ended March 31, 2005, the values for the options granted were estimated using the Black-Scholes option-pricing model with the following assumptions:

	2002 Plan
Risk-free interest rate	4.38		%
Expected life (in years)	7
Expected volatility	37		%
Expected dividends (quarterly)	$	0.05

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

	Quarter Ended March 31,
	2005 As Reported		2005 Pro Forma		2004 As Reported		2004 Pro Forma
Net income	$	32,628	$	30,949	$	29,088	$	27,946
Income attributable to common stock	32,628		30,949		28,272		27,130
Earnings per share of common stock	0.44		0.42		0.41		0.39
Earnings per share of common stock - assuming dilution	0.43		0.41		0.39		0.38
Stock-based employee compensation cost, net of related tax effects, included in net income		178		—		115		—
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	$	—	$	1,257

SEGMENT REPORTING

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

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

Substantially all gas flowing through our gathering, processing and treating facilities is supplied under three types of contracts providing for the purchase, treating or processing of natural gas for periods ranging from one month to twenty years or in some cases for the life of the oil and gas lease. Approximately 70% of our plant facilities’ gross margin, or revenues at the plant less product purchases, for the month of March 2005 was under percentage-of-proceeds agreements in which we are typically responsible for the marketing of the gas and NGLs. Under these agreements, we pay producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs.

Approximately 19% of our plant facilities’ gross margin for the month of March 2005 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.

Approximately 11% of our plant facilities’ gross margin for the month of March 2005 was under contracts with “keepwhole” arrangements or wellhead purchase contracts. Under these contracts, we retain the NGLs recovered by the processing facility and keep the producers whole by returning to the producers at the tailgate of the plant an amount of residue gas equal on a Btu basis to the natural gas received at the plant inlet. The “keepwhole” component of the contracts permits us to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, we are adversely affected when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream.

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

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

Transportation. The Transportation segment reflects the operations of Western’s MIGC, Inc. and MGTC, Inc. pipelines. The majority of the revenue presented in this segment is derived from transportation of residue gas for our Marketing segment and other third parties. The Transportation segments’ firm capacity contracts range in duration from seven months to approximately five years.

Segment Information. The following tables set forth our segment information as of and for the three months ended March 31, 2005 and 2004 (dollars in thousands). Due to our integrated operations, the use of allocations in the determination of business segment information is necessary. Inter-segment revenues are valued at prices comparable to those of unaffiliated customers. Prior period Corporate Plant operating and transportation expense of $935,000 in the interim segment information has been reclassified to the Gas Gathering and Processing segment to conform to the presentation used in 2005.

Quarter Ended March 31, 2005:

	Gas Gathering and Processing			Exploration and Production			Marketing		Trans-portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	(227	)	$	4,035		$	690,333	$	745		$	—		$	—		$	694,886
Sale of natural gas liquids	49			—			133,766		—			—			—			133,815
Equity hedges:
Gas	107			1,226			—		—			—			—			1,333
Liquids	(846		)	—			—		—			—			—			(846		)
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		)	—			47		—			—			—			(40		)
Interest income	—			4			—		—			9,502			(9,506		)	—
Other, net	1,105			2			—		—			180			—			1,287
Total revenues	298,247			74,373			841,850		5,937			9,692			(375,784		)	854,315

Product purchases	221,453			1,279			840,044		858			—			(356,280		)	707,354
Plant and transportation operating expense	26,639			4			1		1,812			—			(757		)	27,699
Oil and gas exploration and production expense	—			34,138			—		—			—			(9,242		)	24,896
(Earnings) from equity investments	(2,134		)	—			—		—			—			—			(2,134		)
Segment-operating profit	52,289			38,952			1,805		3,267			9,692			(9,505		)	96,500

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 tax	$	40,974		$	23,322		$	1,768	$	3,021		$	(17,754	)	$	11		$	51,342

Identifiable assets:
Equity investment	$	36,108		—			—		$	1,071		$	757,071		$	(758,142	)	$	36,108
Property and equipment	712,270			$	503,184		$	15	35,862			53,516			—			1,304,847
Other allocated assets	5,251			19,210			133,714		48,960			425,113			(98,095		)	534,722
Total identifiable assets	$	753,629		$	522,394		$	133,729	$	86,462		$	1,235,700		$	(856,237	)	$	1,875,677

Quarter Ended March 31, 2004:

	Gas Gathering and Processing			Exploration and Production		Marketing			Trans-portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	924		$	2,239	$	659,936		$	562		$	—		$	—		$	663,661
Sale of natural gas liquids	1			—		95,306			—			—			—			95,307
Equity hedges:
Gas	149			1,500		—			—			—			—			1,649
Liquids	(2,392		)	—		—			—			—			—			(2,392		)
Gathering, processing and transportation revenue	15,086			—		—			1,743			—			—			16,829
Total revenues from unaffiliated customers	13,768			3,739		755,242			2,305			—			—			775,054
Inter-segment revenues	257,652			55,931		12,805			3,434			—			(329,822		)	—
Price risk management activities	(21		)	—		(5,459		)	—			—			—			(5,480		)
Interest income	—			—		—			—			4,009			(4,009		)	—
Other, net	341			1		(2		)	—			1,302			—			1,642
Total revenues	271,740			59,671		762,586			5,739			5,311			(333,831		)	771,216

Product purchases	215,577			628		759,869			1,581			—			(320,313		)	657,342
Plant and transportation operating expense	21,099			248		(242		)	1,760			—			(931		)	21,934
Oil and gas exploration and production expense	—			25,681		—			—			—			(8,571		)	17,110
(Earnings) from equity investments	(1,926		)	—		—			—			—			—			(1,926		)
Segment-operating profit	36,990			33,114		2,959			2,398			5,311			(4,016		)	76,756

Depreciation, depletion and amortization	9,001			10,991		17			416			2,201			—			22,626
Selling and administrative expense	—			—		—			—			9,961			(15		)	9,946
(Gain) loss from sale of assets	—			—		—			—			—			—			—
Interest expense	—			34		95			(62		)	9,744			(4,009		)	5,802
Income before income tax	$	27,989		$	22,089	$	2,848		$	2,044		$	(16,595	)	$	8		$	38,382

Identifiable assets:
Equity investment	—			—		—			—			$	483,720		$	(443,954	)	$	39,766
Property and equipment	$	623,219		$	304,721	$	17		$	38,503		54,346			(569		)	1,020,237
Other allocated assets	5,974			4,737		60,172			27,152			319,475			(52,120		)	365,390
Total identifiable assets	$	629,193		$	309,458	$	60,189		$	65,655		$	857,541		$	(496,643	)	$	1,425,393

LEGAL PROCEEDINGS

Gracey et al. v. Western Gas Resources, Inc. et al., United States District Court, Southern District of New York, Case No.
03-CV-6186 (vm) (S.D.N.Y.). On September 17, 2004, the plaintiffs, traders of natural gas futures contracts on NYMEX filed this action on behalf of themselves and a putative class of others similarly situated. In the complaint, the plaintiffs claim that the Company manipulated the prices of natural gas futures on the NYMEX in violation of the Commodity Exchange Act, or CEA, by reporting allegedly “inaccurate, misleading and false trading information” to trade publications that compile and publish indices of natural gas spot prices. In addition, the complaint asserts that the Company aided and abetted the alleged CEA violations of others. The plaintiffs seek to recover actual damages on behalf of themselves and a class of natural gas futures traders, and their costs of litigation including attorney’s fees. The Company believes that the claims are without merit and intends to vigorously contest the allegations in this case.

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

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 in 2005. The following pronouncements have been issued but not yet adopted.

SFAS No. 123(R). SFAS No. 123(R), “Share Based Payment” was issued in December 2004 and now must be adopted for annual periods that begin after June 15, 2005. This pronouncement requires companies to expense the fair value of employee stock options and other forms of stock based compensation. We intend to adopt this pronouncement in the first quarter of 2006. Currently, we are complying with the pro forma disclosure requirements of SFAS No. 123, “Accounting for Stock Based Compensation.” If SFAS No. 123(R) had been in effect during the first quarter of 2005, Earnings per share of common stock - assuming dilution in the first quarter ended March 31, 2005 would have been $0.41 per share of common stock or a reduction of approximately $0.02 per share of common stock from the actual results for the first quarter of 2005.

SFAS No. 151. SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4” was issued in November 2004 and is effective for the Company for inventory costs incurred in fiscal years beginning after June 15, 2005, and will be applied prospectively. SFAS No. 151 amends APB Opinion No. 43, Chapter 4, “Inventory Pricing” to clarify the accounting for abnormal amounts of costs and the allocation of fixed production overheads.

We believe that the adoption of SFAS No. 151 will not affect our results of operations, financial position or cash flows.

SFAS No. 153. SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29” was issued in December 2004 and is effective for the Company for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005, and will be applied prospectively. SFAS No. 153 amends APB Opinion No. 29, Accounting for Nonmonetary Transactions. The guidance in APB Opinion No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged but included certain exceptions to that principle. SFAS No. 153 amends APB Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. We will adopt SFAS No. 153 as required.

EITF No. 04-13. At its November 2004 meeting, the Emerging Issues Task Force, or EITF, of the FASB began discussion of Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” This Issue addresses the question of when it is appropriate to measure non-monetary purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The EITF did not reach a consensus on this issue, but requested the FASB staff to further explore the alternative views. The implementation of this EITF, if approved, may reduce revenues and related costs but will not have a material impact on our results of operations, financial position or cash flows.

In order to minimize transportation costs or make product available at a location of our customer’s preference, from time to time, we will enter into arrangements to buy product from a party at one location and arrange to sell a like quantity of product to this same party at another location. In accordance with EITF 03-11, we record revenue on these transactions on a gross basis versus sales net of purchases basis because we obtain title to the product that we buy, bear the risk of loss, credit and performance exposure on these transactions, and take physical delivery of the product. For the quarters ended March 31, 2005 and 2004, we recorded revenues of $28.7 million and $25.2 million, respectively, and product purchases of $26.7 million and $23.9 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.

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

FASB Interpretation No. 47. FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143”, or FIN 47, was issued in March 2005 and is effective in fiscal periods beginning after December 31, 2005. FIN 47 clarifies the term “conditional asset retirement obligation” as used in FASB Statement 143, “Accounting for Asset Retirement Obligations”. Conditional asset retirement obligations as used in FASB Statement 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform an asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. When sufficient information exists, uncertainty about the timing and (or) method of settlement should be factored into the measurement of the liability. This interpretation is not expected to have a material impact on our results of operation, financial position or cash flows.

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

Company Overview

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

Industry and Company Overview. In North America, our industry has experienced several consecutive years of declining natural gas production despite increased drilling activity. Most of the major gas producing areas, such as the Gulf of Mexico, are mature and are in production decline. We are concentrating our efforts in the Rocky Mountain area and other unconventional gas plays, where there are estimated to be large quantities of undeveloped gas. In the U.S, the federal 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. Additionally, to date we have been successful in obtaining drilling rigs and related oil field services to accomplish our drilling plans. However, we believe that as we expand into new areas and continue the development of the areas in which we currently participate, obtaining rigs, related services and experienced employees will become increasingly difficult.

Our operations are conducted through the following four business segments:

Exploration and Production. We explore for, develop and produce natural gas reserves independently and to enhance and support our existing gathering and processing operations. Our producing properties are primarily located in the Powder River, Greater Green River, San Juan, and Sand Wash Basins. These plays provide low geologic risk, and are multi-year development projects. These provide us with the opportunity to steadily increase our production volume over time at reasonable operating and low finding and development costs. In the first quarter of 2005 our average production sold was 164 MMcfe per day, which is a 13% increase over the daily average production volume sold in the first quarter of 2004.

We continue to seek to add additional upstream core projects that are focused on Rocky Mountain natural gas. We will utilize our expertise in exploration and low-risk development of unconventional gas reservoirs including tight-gas sands, coal bed methane, biogenic, and shale gas plays to evaluate acquisitions of either additional leaseholds, proven and undeveloped reserves or companies with operations primarily focused in the Rockies. We may also evaluate unconventional gas reservoirs in areas outside the Rockies where we can leverage our related exploration, production and gathering expertise. In January 2005, we opened an office in Calgary, Alberta, Canada to evaluate opportunities in the Western Canadian Sedimentary Basin. Overall, at March 31, 2005, we have acquired

the drilling rights on approximately 1.6 million net acres in various Rocky Mountain basins and continue to expand our leasehold positions.

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

This segment of our operations has provided a stream of operating profit that is available for reinvestment into other projects or other segments of our business. Overall throughput in our facilities during the first quarter of 2005 remained relatively constant as compared to the same period in 2004 and averaged a total of 1.4 Bcf per day.

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

Marketing. The primary goal of our gas-marketing segment is to ensure that the product from our processing facilities and upstream activities is delivered timely to the market. Additionally, our gas marketing operations seek to preserve and enhance the value received for our equity volumes of natural gas. This goal is achieved through the use of hedges on the production of our equity natural gas and NGLs and through the use of firm transportation capacity. We also buy and sell natural gas and NGLs in the wholesale market in the United States and in Canada. These third-party sales, our firm transportation capacity on interstate pipelines and our gas storage positions, combined with the stable supply of gas from our facilities and production, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods.

RESULTS OF OPERATIONS

Three months ended March 31, 2005 compared to the three months ended March 31, 2004

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

	Three Months Ended March 31,						Percent Change
	2005			2004			Percent Change
Financial results:
Revenues	$	854,315		$	771,216		11
Net income	32,628			29,088			12
Earnings per share of common stock	0.44			0.41			7
Earnings per share of common stock-assuming dilution	0.43			0.39			10
Net cash provided by operating activities	118,789			126,010			(6	)
Net cash used in investing activities	(115,634		)	(36,640		)	215
Net cash used in financing activities	$	(1,820	)	$	(83,719	)	(97	)

Operating data:
Average gas sales (MMcf/D)	1,302			1,367			(5	)
Average NGL sales (MGal/D)	1,763			1,611			9
Average gas prices ($/Mcf)	$	5.91		$	5.32		11
Average NGL prices ($/Gal)	$	0.84		$	0.63		33

Net income increased $3.5 million for the three months ended March 31, 2005 compared to the same period in 2004. The increase in net income was primarily attributable to higher production of equity gas volumes and higher product prices in the first quarter of 2005. Partially offsetting these items was an increase in operating costs and depreciation, depletion and amortization in the first quarter of 2005 and the cumulative effect of a change in accounting principle in the first quarter of 2004. Effective as of January 1, 2004, we revised our depreciation and depletion methodology for our oil and gas properties. This change in accounting principle resulted in a cumulative reduction of depreciation for periods prior to 2004 of $4.7 million, net of tax, in the quarter ended March 31, 2004.

Revenues from the sale of gas increased $30.9 million to $696.2 million for the three months ended March 31, 2005 compared to the same period in 2004. This increase was primarily due to an increase in product prices in the three months ended March 31, 2005. Average gas prices realized by us increased $0.59 per Mcf to $5.91 per Mcf for the quarter ended March 31, 2005 compared to the same period in 2004. Included in the realized gas price were approximately $1.3 million of gains recognized in the three months ended March 31, 2005 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately 61% of our equity gas for the remainder of 2005. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk”. Average gas sales volumes decreased by 5% to 1,302 MMcf per day for the quarter ended March 31, 2005 compared to the same period in 2004.

Revenues from the sale of NGLs increased $40.1 million to $133.0 million for the three months ended March 31, 2005 compared to the same period in 2004. This increase is primarily due to an increase in product prices. Average NGL prices realized by us increased $0.21 per gallon to $0.84 per gallon for the three months ended March 31, 2005 compared to the same period in 2004. Included in the realized NGL price were approximately $846,000 of losses recognized in the three months ended March 31, 2005 related to futures positions on equity NGL volumes. We have entered into additional futures positions for approximately 32% of our equity NGL production for the remainder of 2005. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk”. Average NGL sales volumes increased 9% to 1,763 MGal per day for the three months ended March 31, 2005 compared to the same period in 2004. This increase in sales volume was primarily due to the acquisition of various gathering and processing assets in the first quarter of 2005.

Product purchases increased by $50.0 million for the quarter ended March 31, 2005 compared to the same period in 2004 as a result of the increase in product prices. Overall, combined product purchases as a percentage of sales of all products decreased slightly to 86% in the first quarter of 2005 as compared to the first quarter of 2004. This decrease is due to the reduction in third party sales volumes of natural gas.

Plant and transportation operating expense increased by $5.8 million for the quarter ended March 31, 2005 compared to the same period in 2004. The increase was primarily due to increases in property tax expenses, labor costs, repairs and maintenance, and third party gathering.

Oil and gas exploration and production expenses increased by $7.8 million for the quarter ended March 31, 2005 compared to the same period in 2004. The increase was substantially due to increased lease operating expenses, or LOE, in the Powder River Basin coal bed development, the newly acquired production assets in the San Juan Basin, and unsuccessful well expense of $1.7 million primarily related to an exploratory well in the Sand Wash area. Overall, LOE averaged $0.87 per Mcf in the 2005 period compared to $0.64 per Mcf in 2004. The increase in LOE is substantially due to higher water handling charges on dewatering wells in several new pilot areas that have no offsetting gas production as yet, contract labor, and fuel and operating costs of wellhead blowers in the Powder River Basin as well as increased costs related to initiating operations of the San Juan Basin production assets.

Depreciation, depletion and amortization, or DD&A, increased by $6.5 million in the quarter ended March 31, 2005 compared to the same period in 2004. 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 the February 2005 acquisition of additional midstream assets in the Greater Green River Basin. We also had $4.6 million increase in DD&A in our upstream operations primarily due to our continued development in the Powder River Basin, downward revisions to reserves in the Powder River Basin, and our October 2004 acquisition of producing properties in the San Juan Basin.

Selling and administrative expenses increased by $2.6 million in the quarter ended March 31, 2005 compared to the same period in 2004. This increase is due to higher compensation and benefit costs, audit fees and legal fees.

Cash Flow Information

Cash flows from operating activities decreased by $7.2 million in the first quarter of 2005 compared to the first quarter of 2004. This decrease was primarily due to the timing of cash receipts and payables.

Cash flows used in investing activities increased by $79.0 million in the first quarter of 2005 compared to the first quarter of 2004. This increase was primarily due to an increased level of capital expenditures including the February 2005 acquisition of additional midstream assets in the Greater Green River Basin.

Cash flows used in financing activities decreased by $81.9 million in the first quarter of 2005 compared to the first quarter of 2004. This decrease was due to a significant reduction in our outstanding debt in the first quarter of 2004, as compared to the utilization of funds provided by financing activities to fund our capital investments in 2005.

Segment Information

Gas Gathering, Processing and Treating. The Gas Gathering, Processing and Treating segment realized segment-operating profit of $52.3 million for the three months ended March 31, 2005 compared to $37.0 million in the same period in 2004. The increase in operating profit in this segment in 2004 is primarily due to higher realized prices and the resulting increase in net margin as shown below.

	Quarter Ended March 31,
	2005		2004
Gross Margin ($/Mcf)	$	0.64	$	0.49
Operating Expense ($/Mcf)	0.22		0.18
Net Margin ($/Mcf)	$	0.42	$	0.31

Exploration and Production. The Exploration and Production segment realized segment-operating profit of $39.0 million in the first quarter of 2005 compared to $33.1 million in 2004. The increase is due to increased equity production, higher product prices, and the acquisition of production assets in the San Juan basin in the fourth quarter of 2004. During the first quarter of 2005, our production of natural gas, as compared to the same period in 2004 increased by 9% to 14.3 Bcfe. The following table sets forth the average sales price received for our oil and gas products in the three months ended March 31, 2005 and 2004.

	Three Months Ended March 31,
	2005		2004
Average sales price: (1)
Oil ($/Bbl)	$	43.83	$	35.43
Gas ($/Mcf),excluding the effect of hedging positions	4.89		4.39
Gas ($/Mcf), including the effect of hedging positions	4.97		4.51

Production and other costs:
Lease operating expense ($/Mcfe)	0.87		0.64
Production tax expense ($/Mcfe)	0.47		0.51
Gathering and transportation expense ($/Mcfe)(2)	0.83		0.71
Other expenses ($/Mcfe)	0.01		0.01
Total costs ($/Mcfe)	$	2.18	$	1.87

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

(2) Of the total Gathering and transportation expense, approximately $0.63 per Mcfe and $0.66 per Mcfe in the quarters ended March 31, 2005 and 2004, respectively, was the result of inter-segment charges.

Marketing. The Marketing segment realized segment-operating profit of $1.8 million for the three months ended March 31, 2005 compared to $3.0 million in the same period of 2004. The decrease was due to lower price differentials between the Rocky Mountain and Mid Continent market centers, which impacted the Marketing segment’s ability to capitalize on our transportation contracts.

Transportation. The Transportation segment realized segment-operating profit of $3.3 million for the three months ended March 31, 2005 compared to $2.4 million in the same period of 2004. The Transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin.

Liquidity and Capital Resources

Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of debt and equity securities. In the past, these sources have been sufficient to meet our needs and finance the growth of our business. We can give no assurance that the historical sources of liquidity and capital resources will be available for future development and acquisition projects, and we may be required to seek additional or alternative financing sources. Product prices,

hedges of equity production, sales of inventory, the volume of natural gas processed by our facilities, the volume of natural gas produced from our producing properties, the margin on third-party product purchased for resale, as well as the timely collection of our receivables are all expected to have significant influences on our future net cash provided by operating activities. Additionally, our future growth will be dependent upon obtaining additions to dedicated plant reserves, acquisitions, new project development, marketing results, efficient operation of our facilities and our ability to obtain financing at favorable terms.

During the past several years, we have been successful in developing additional reserves of natural gas and increasing our equity natural gas production. However, the overall level of drilling and production associated with our producing properties will depend upon, among other factors, the price for gas, availability of transportation capacity to market centers, the energy and environmental policy and regulation by governmental agencies, the drilling schedules of the operators of our non-operated properties, the issuance of drilling and water disposal permits, the available 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. Any reduction in the levels of exploration, development and production by us or a significant reduction in natural gas prices could have a material adverse effect on our financial condition, results of operations and cash flows.

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

We believe that the amounts available to be borrowed under our financing facilities, together with net cash provided by operating activities, will provide us with sufficient funds to connect new reserves, maintain our existing facilities and complete our current capital expenditure program. Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital. Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third-parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or use a combination of alternatives. While we believe that we would be able to secure additional financing, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing. We believe that amounts available under the revolving credit facility will be sufficient to meet scheduled principal repayments during 2005 of $10.0 million under the master shelf agreement.

We have effective shelf registration statements filed with the SEC for an aggregate of $262.0 million of debt securities, preferred stock or common stock. These shelf registrations allow us to access the debt and equity markets, subject to market conditions.

Sources and Uses of Funds. Our sources and uses of funds for the quarter ended March 31, 2005 are summarized as follows (dollars in thousands):

Sources of funds:
Borrowings under the revolving credit facility	$	807,065
Borrowings under the master shelf agreement	25,000
Proceeds from the dispositions of property and equipment	767
Net cash provided by operating activities	118,789
Distributions from equity investments	324
Proceeds from exercise of common stock options	2,307
Total sources of funds	$	954,252
Uses of funds:
Payments related to long-term debt (including debt issue costs)	$	828,205
Capital expenditures	116,725
Change in balance of outstanding checks	4,283
Common dividends paid	3,704
Total uses of funds	$	952,917

Capital Investment Program. We currently anticipate capital expenditures in 2005 of approximately $376.4 million. The 2005 capital budget is a 24% increase over the amount expended in 2004. This increase is the result of an expected increase in drilling activity in each of our 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 34% and 29%, respectively, of the total 2005 budget. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2005 will not change or that we will actually incur this level of capital expenditures. This budget may be increased to provide for acquisitions if approved by our board of directors.

The 2005 capital budget and our capital expenditures during the quarter ended March 31, 2005 are presented in the following table (dollars in millions).

Type of Capital Expenditure	2005 Capital Budget		Capital Expenditures During the Quarter Ended March 31, 2005
Gathering, processing, treating and pipeline assets (1)	$	132.8	$	27.9
Exploration and production and lease acquisition activities	204.3		56.7
Acquisition of Greater Green River Basin midstream assets	28.0		28.0
Information technology and other items	3.0		.6
Capitalized interest and overhead	8.3		2.8
Total Capital Expenditures	$	376.4	$	116.0

(1) Includes $13.7 million budgeted in 2005 and $1.2 million expended in the quarter ended March 31, 2005 for maintaining existing facilities.

Contractual Commitments and Obligations

Contractual Cash Obligations. A summary of our contractual cash obligations as of March 31, 2005 is as follows (dollars in thousands):

	Payments by Period
Type of Obligation	Total Obligations		Due in 2005		Due in 2006 – 2007		Due in 2008 – 2009		Due Thereafter
Guarantee of Fort Union Project Financing	$	4,531	$	654	$	1,931	$	1,946	$	—
Operating Leases	83,255		12,941		33,172		25,334		11,808
Firm Transportation Capacity Agreements	243,598		29,564		72,959		59,932		81,143
Firm Storage Capacity Agreements	30,500		6,925		9,830		4,819		8,926
Long-term Debt	385,900		10,000		20,000		230,900		125,000
Interest on Long-term Debt (1)	93,612		13,981		35,044		28,696		15,891
Total Contractual Cash Obligations	$	841,396	$	74,065	$	172,936	$	351,627	$	242,768

(1) The interest rate assumed on the revolving credit facility at March 31, 2005 is 4.1% per annum.

Guarantee of Fort Union Project Financing. We own a 13% equity interest in Fort Union Gas Gathering, L.L.C., or Fort Union, and are the construction manager and field operator. Fort Union gathers and treats natural gas in the Powder River Basin in northeast Wyoming. Initial construction and any expansions of the gathering header and treating system have been project financed by Fort Union. This debt is amortizing on an annual basis and is scheduled to be fully paid in 2009. Our requirement to fund under this guarantee would be reduced by the value of assets held by Fort Union. This guarantee is not reflected on our Consolidated Balance Sheet.

Operating Leases. In the ordinary course of our business operations, we enter into operating leases for office space, and for office, communication, transportation and compression equipment. Payments made on these leases are a component of operating expenses and are reflected on the Consolidated Statement of Operations and, as operating leases, are not reflected on our Consolidated Balance Sheet. Our leases have terms ranging from one month to ten years and the majority of the leases have return or fair market purchase options available at various times during the lease. If we were to exercise the purchase options on all the leased compression equipment, these purchase options would require the capital expenditure of approximately $44.9 million between 2007 and 2013.

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

At March 31, 2005, the fixed fees associated with our existing contracts for firm transportation capacity during 2005 will average approximately $0.16 per Mcf. The associated contract periods range from one month to twelve years. Under firm transportation contracts, we are required to pay the fees associated with these contracts whether or not the transportation is used.

Firm Storage Capacity Agreements. We customarily store gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and to capture seasonal price differentials. As of March 31, 2005, we had contracts in place for approximately 15.6 Bcf of storage capacity at various third-party facilities. Firm storage agreements generally require the payment of fixed monthly fees regardless of the quantity of gas that is in storage under a particular agreement. Of the total storage capacity under contract, approximately 5.0 Bcf is under contract to our Canadian subsidiary, WGR Canada, Inc., and Western guarantees the subsidiary’s performance under these contracts. This subsidiary is wholly owned by us and fully consolidated in our financial statements.

The fees associated with these contracts in 2005 will average $0.59 per Mcf of annual capacity. The associated contract periods at March 31, 2005 had an average term of 39 months. At March 31, 2005, we held gas in our contracted storage facilities and in imbalances of approximately 13.4 Bcf at an average cost of $5.83 per Mcf compared to 4.9 Bcf at an average cost of $5.03 per Mcf at March 31, 2004. These positions are for storage withdrawals within the next 14 months. At the time we place product into storage, we contract for the sale of that product, physically or financially, and do not speculate on the future value of the product. These agreements for storage capacity are not reflected on our Consolidated Balance Sheet.

From time to time, we lease NGL storage space at major trading locations to facilitate the distribution of products. At March 31, 2005, we held NGLs in storage at various third-party facilities of 3,669 MGal, consisting primarily of propane and ethane, at an average cost of $0.45 per gallon compared to 2,863 MGal at an average cost of $0.30 per gallon at March 31, 2004.

Long-term Debt

Revolving Credit Facility. The commitment under the revolving credit facility totals $500 million and matures in June 2009. At March 31, 2005, $230.9 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 the credit facility bear interest at Eurodollar rates or a base rate, as requested by us, plus an applicable percentage based on our debt to capitalization ratio. The base rate is the agent’s published prime rate. We also pay a quarterly commitment fee ranging between 0.20% and 0.375%, depending on our debt to capitalization ratio. This fee is paid on unused amounts of the commitment. At March 31, 2005, the interest rate

payable on borrowings under this facility was approximately 4.1% per annum. Under the credit facility, we are subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55% and maintaining a ratio of EBITDA, as defined in the credit facility, to interest over the last four quarters in excess of 3.0 to 1.0. The credit facility ranks equally with borrowings under our master shelf agreement with The Prudential Insurance Company. This facility has been rated Ba1 by Moody’s and BB+ by S&P.

Master Shelf Agreement. Amounts outstanding under the master shelf agreement at March 31, 2005 are as indicated in the following table (dollars in thousands):

Issue Date	Amount		Interest Rate		Final Maturity	Principal Repayment Schedule
July 28, 1995	$	30,000	7.61	%	July 28, 2007	$10,000 on each July 28 of 2005 through 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	$	155,000

Our borrowings under the master shelf agreement are secured by a pledge of the capital stock of our significant subsidiaries. These subsidiaries also guarantee the borrowings under the facility. All of the borrowings under the 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 the master shelf agreement, to interest for the last four quarters in excess of 3.0 to 1.0.

In December 2004, we gave notice to Prudential of our intention to prepay a $25 million note due January 17, 2008. This note bore interest at 6.36% per annum and was prepaid at par on January 18, 2005. To fund the prepayment, we issued a new $25 million note to Prudential, due January 2015 and bearing interest at 5.57% per annum. During 2005, we will make scheduled payments totaling $10.0 million on these notes. We intend to fund these repayments with funds available under the revolving credit facility.

Upstream Operations

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

Our principal upstream operations are summarized in the following table:

Production Area	Gross Acres Under Lease at March 31, 2005	Net Acres Under Lease at March 31, 2005	Average Net Production for the Quarter Ended March 31, 2005(1)	Gross Productive Gas Wells at March 31, 2005	Net Productive Gas Wells at March 31, 2005
Powder River Basin	1,048,000	535,000	112	4,309	2,045
Jonah/Pinedale Field	160,000	28,000	36	237	28
San Juan Basin	34,000	26,000	10	139	128
Sand Wash Basin	146,000	137,000	5	19	19
Denver-Julesburg Basin	395,000	340,000	—	—	—
Other	573,000	500,000	1	12	2
Total	2,356,000	1,566,000	164	4,716	2,222

(1) Represents net production sold in MMcfe/day.

Drilling Results. The following table sets forth the number of wells we drilled during the three months ended March 31, 2005 and 2004 in each of our major producing areas. This information should not be considered

indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are defined as those that produce commercial quantities of hydrocarbons whether or not they produce a reasonable rate of return.

	Quarter Ended March 31,
	2005		2004
Productive Area	Gross	Net	Gross	Net
Powder River Basin CBM
Productive wells drilled:	173	88	161	83

Jonah/Pinedale Field
Productive wells drilled:	19	2	12	1
Dry exploratory wells drilled:	1	0	0	0

San Juan Basin
Productive wells drilled:	17	16	0	0

Sand Wash Basin
Productive wells drilled:	0	0	3	3
Dry exploratory wells drilled:	1	1	0	0

Other
Exploratory productive wells drilled:	2	1	0	0

Powder River Basin Coal Bed Methane. We continue to develop our Powder River Basin CBM reserves and expand the associated gathering system in northeast Wyoming. Our net production sold from the Powder River Basin CBM averaged 112 MMcf per day in the first quarter of 2005.

Our production from the Big George coal continues to increase and was 89 MMcf per day gross at March 31, 2005, or 37 MMcf per day net, from the All Night Creek Unit, Pleasantville, SG Palo, Bullwhacker, Schoonover and Kingsbury Unit areas. In the Big George coal, as of April 2005, we had 748 wells dewatering and producing gas, 431 wells dewatering and 634 wells drilled and in various stages of completion and hook-up in preparation for dewatering and production.

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

Our 2005 capital budget for the Powder River Basin coal bed project is estimated at $81.2 million, of which $29.1million was spent in the first quarter of 2005. In 2005, we plan to participate in the drilling of 730 gross wells, or 365 net wells, in the Big George and related coals and an additional 120 gross wells, or 60 net wells, in the Wyodak and related coals. An estimated 640 wells of the 850-well program will be on federal leaseholds and require drilling permits from the Bureau of Land Management, or BLM. The remaining 210 well locations are on fee or state leaseholds. Together with our co-developer, as of May 5, 2005, we have drilling permits approved for 421 of the federal wells planned for 2005. Federal drilling permit applications for another 581 locations have been submitted to the BLM. Timely receipt of these permits would allow us to complete our planned 2005-drilling program, and a portion of our 2006-drilling program, on federal leaseholds.

Approximately 300 gross wells in our 2005-drilling program will require permits to treat produced water. The remainder of the wells to be drilled in 2005 will require more conventional types of water discharge permits, such as reservoir containment or surface discharge. To date, we, together with our co-developer in this area, have received water discharge permits from the DEQ for approximately 49% of the wells we plan to drill in 2005. An additional

484 permit applications have been submitted to the DEQ which, when combined with permits received, is more than enough necessary to complete our 2005 drilling program. Historically, the DEQ permit process has required approximately 120 to 150 days from initial submittal to final approval. There is, however, no assurance as to the future timing of the receipt of drilling and water discharge permits, the success of our drilling program, or the dewatering time as our development progresses into the western and northern parts of the Powder River Basin.

On April 30, 2003, the BLM issued the final Record of Decision, or ROD, for the Powder River Basin Oil & Gas Environmental Impact Statement, or EIS. The ROD requires additional surveys for plant and animal species, cultural surveys and noxious weed mitigation prior to the BLM granting a drilling permit. A number of cases have been filed by environmental groups against the BLM in Wyoming disputing the validity of the environmental impact statement and ROD. Due to our interests in developing federal leases in the Powder River Basin, we are an intervenor defendant in each of the foregoing cases. In one of these cases filed in the United States District Court of Montana, the Court was asked to address the adequacy of the Montana Powder River Basin ROD and whether the BLM should have issued a single EIS for the Powder River Basin. Under an Order dated March 4, 2005, the Court found that a single EIS for the Powder River Basin is not required under NEPA. As these cases proceed, the BLM, in the event of any adverse rulings, may be required to perform further environmental analysis and, in addition, could be ordered to cease issuing drilling permits until it has completed such further analysis. Consequently, our ability to receive permits and develop our leases may be delayed or restricted by the outcome of these cases.

On August 10, 2004, the Tenth Circuit Court of Appeals issued its decision in Pennaco Energy, Inc. v. United States Department of the Interior. The court upheld a decision by the Interior Board of Land Appeals, or IBLA, that the BLM had not complied with the National Environmental Policy Act in issuing three federal leases to Pennaco Energy, Inc. in the Powder River Basin for coalbed methane development. We are not a party to the case, and the IBLA and Tenth Circuit decisions do not directly address any federal leases held by us. However, we hold approximately 70,000 net acres of federal leasehold in the Powder River Basin, which may potentially be affected by the response to the Pennaco case. In order to resolve the issues raised in the Pennaco decision and related issues, the BLM filed for and received public comment on two proposed environmental assessments. After completion of the environmental assessments, we are advised that the BLM believes the issues raised in the Pennaco decision will be resolved. We cannot predict what other actions the Department of Interior or third parties might take in response to this matter, or how the decision and actions taken by the BLM in response to the decision may affect the pace of federal leasing or permitting and development in the Powder River Basin.

A complaint was filed on January 31, 2005 in the U.S. District Court of Wyoming against the BLM and the Department of Interior. The complaint alleges that the BLM violated NEPA “as described in Pennaco Energy, Inc. v. United States Department of the Interior” because the BLM did not consider the effects of CBM development prior to issuing five leases including one issued to us. The plaintiffs have asked the court for a “review of the issuance” of these leases. We cannot predict what actions, if any, the Department of the Interior, third parties, or the Court might take in response to this case, or how these actions may affect the pace of federal drilling or permitting and development of the Powder River Basin.

Jonah/Pinedale Fields. Our exploration and production assets in the Green River Basin of southwest Wyoming are located in the Pinedale Anticline and Jonah Field areas. During 2005, we expect to participate in the drilling of 80 gross wells, or approximately nine net wells, on the Pinedale Anticline. Our capital budget for 2005 in the Pinedale Anticline area provides for expenditures of approximately $47.9 million for drilling costs and production equipment, of which $16.8 million was spent in the first quarter of 2005. Due to drilling and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure during 2005.

Midstream Operations

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

Gas Gathering, Processing and Treating. We operate a variety of gathering, processing and treating facilities, or plant operations, as presented on the Principal Gathering and Processing Facilities Table set forth below. Our

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

In February 2005, we closed on the purchase of certain natural gas gathering and processing assets in the eastern Greater Green River Basin for approximately $28.0 million, before closing adjustments. We currently plan to integrate portions of the acquired systems into our Red Desert plant and our Table Rock, Wamsutter and Desert Springs gathering systems during the third quarter of 2005.

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

Principal Gathering and Processing Facilities Table. The following table provides information concerning our principal gathering, processing and treating facilities at March 31, 2005.

	Year	Gas	Gas	Average for the Quarter Ended March 31, 2005
Facilities (1)	Placed in Service	Gathering System Miles	Throughput Capacity (MMcf/D)(2)	Gas Throughput (MMcf/D) (3)	Gas Production (MMcf/D)(4)	NGL Production (MGal/D) (4)
Texas
Gomez Treating (5)	1971	389	280	89	81	—
Midkiff/Benedum	1949	2,332	165	141	93	810
Mitchell Puckett Treating (5)	1972	126	120	36	22	1
Wyoming
Coal Bed Methane Gathering	1990	1,369	548	387	356	—
Desert Springs Gathering	1979	65	10	6	6	21
Fort Union Gas Gathering(12)	1999	167	635	469	469	—
Granger Complex (6)(7)(8)	1987	714	325	289	248	396
Granger Straddle Plant	2004	—	200	155	—	12
Hilight Complex (6)	1969	657	124	17	13	60
Kitty/Amos Draw (6)	1969	321	17	5	3	24
Newcastle (6)	1981	146	5	3	2	21
Patrick Draw(6)(9)	1997	284	150	23	19	54
Red Desert (6)	1979	125	42	18	31	58
Rendezvous (10)	2001	238	275	326	326	—
Reno Junction (7)	1991	—	—	—	—	110
Table Rock Gathering	1979	100	20	13	13	—
Wamsutter Gathering (11)	1979	242	50	44	40	25
Wind River Gathering	1979	137	80	46	46	—
Oklahoma
Chaney Dell/Westana	1966	3,307	175	191	168	302
New Mexico
San Juan River (5)	1955	277	60	25	20	36
Utah
Four Corners Gathering	1988	104	15	3	2	15
Yellow Creek (9)(13)	1985	—	—	—	—	66
Total		11,100	3,296	2,286	1,958	2,011

(1) Our interest in all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%); Fort Union (13%) and Rendezvous (50%). We operate all facilities, and all data include our interests and the interests of other joint interest owners and producers of gas volumes dedicated to the facility. Unless otherwise indicated, all facilities shown in the table are gathering, processing or treating facilities.

(2) Gas throughput capacity is as of March 31, 2005 and represents capacity in accordance with design specifications unless other constraints exist, including permitting or field compression limits.

(3) Aggregate natural gas volumes delivered into our gathering systems.

(4) Volumes of gas and NGLs are allocated to a facility when a well is connected to that facility; volumes exclude NGLs fractionated for third-parties.

(5) Sour gas facility (capable of processing or treating gas containing hydrogen sulfide and/or carbon dioxide).

(6) Processing facility that includes fractionation (capable of fractionating raw NGLs into end-use products).

(7) NGL production includes conversion of third-party feedstock to iso-butane.

(8) The Granger Complex includes the Lincoln Road facility. The volume information for this facility is reported with the volume information for Granger.

(9) This facility was acquired in a transaction, which closed on February 1, 2005.

(10) The majority of the gas gathered by the Rendezvous gas gathering system is delivered to our Granger facility and is included with the volume information reported for Granger.

(11) A portion of the gas gathered by the Wamsutter gas gathering system is delivered to our Red Desert facility and is included with the volume information reported for Red Desert.

(12) A portion of the gas gathered by Fort Union is also reported under Coal Bed Methane Gathering.

(13) NGL fractionation facility that receives product from a third-party owned liquids pipeline.

Transportation Operations

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

The following table provides information concerning our principal transportation assets at March 31, 2005.

			Average for the Quarter Ended March 31, 2005
Transportation Facilities (1)	Year Placed In Service	Transportation Miles	Pipeline Capacity (MMcf/D) (2)	Gas Throughput (MMcf/D) (3)
MIGC	1970	263	130	146
MGTC	1963	251	18	7
Total		514	148	153

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

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

(3) Aggregate volumes transported by a pipeline.

Marketing

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

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

We enter into futures transactions on the New York Mercantile Exchange, or NYMEX, and through OTC swaps and options with various counterparties, consisting primarily of investment banks, financial institutions and other natural gas companies. We conduct credit reviews of all of our OTC counterparties and have agreements with many of these parties that contain collateral requirements. We generally use standardized swap agreements that allow for offset of positive and negative OTC exposures with the same counterparty. OTC exposure is marked-to-market daily for the credit review process. Our exposure to OTC credit risk is reduced by our ability to require a margin deposit from our counterparties based upon the mark-to-market value of their net exposure. We are also subject to margin deposit requirements under these same agreements and under margin deposit requirements for our NYMEX transactions. At March 31, 2005, we had $13.1 million of margin deposits outstanding.

We continually monitor and review the credit exposure to our marketing counterparties. In recent months the prices of natural gas and NGLs, and therefore our credit exposures, have increased significantly. In order to minimize our credit exposures, we have utilized existing netting agreements to reduce our net credit exposure, established new netting agreements with additional customers, terminated several long-term marketing obligations, negotiated accelerated payment terms with several customers, and increased the amount of credit which we make available to substantial companies which meet our credit requirements. Although netting agreements similar to those that we utilize have been upheld by bankruptcy courts in the past, if any of the customers with whom we have netting agreements were to file for bankruptcy, we can provide no assurance that our agreements will not be challenged or as to the outcome of any challenge.

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

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 the board of directors.

Hedge Positions. As of March 31, 2005, we have hedged approximately 61% of our projected 2005 equity natural gas volumes and approximately 32% of our projected 2005 equity production of crude oil, condensate, and NGLs. All these 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 correlated with 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 cash price of the hedged commodity. 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 2005, we recognized a loss of $87,000 from the ineffective portions of our hedges.

Outstanding Equity Hedge Positions and the Associated Basis for 2005. The following table details our hedge positions as of March 31, 2005. In order to determine the hedged price to the particular operating region, deduct the basis differential from the NYMEX price. The prices for NGLs do not include the cost of the hedges of approximately $468,000 as of March 31, 2005. There is no associated cost for the natural gas hedges.

Product	Year	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	2005	80,000 MMBtu per day with an average minimum price of $4.75 per MMBtu and an average maximum price of $8.88 per MMBtu.	Mid-Continent – 60,000 MMBtu per day with an average basis price of $0.42 per MMBtu. Permian – 5,000 MMBtu per day with an average basis price of $0.48 per MMBtu. Rocky Mountain – 15,000 MMBtu per day with an average basis price of $0.72 per MMBtu.
Crude, Condensate, Natural Gasoline	2005	50,000 Barrels per month with an average minimum price of $31.00 per barrel and an average maximum price of $48.01 per barrel.	Not Applicable
Propane	2005	75,000 Barrels per month with an average minimum price of $0.52 per gallon and an average maximum price of $0.88 per gallon.	Not Applicable
Ethane	2005	75,000 Barrels per month. Floor at $0.38 per gallon.	Not Applicable

Account balances related to hedging transactions (designated as cash flow hedges under SFAS 133) at March 31, 2005 were $2.1 million in Current assets from price risk management activities, $13.5 million in Current liabilities from price risk management activities, ($4.1) million in Deferred income taxes payable, net, and a $7.2 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Stockholders’ equity. The unrealized loss in Accumulated other comprehensive income will be reclassified to earnings in 2005.

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

Fair value of contracts outstanding at December 31, 2004	$	11,341
Decrease in value due to change in price	(11,759		)
Decrease in value due to new contracts entered into during the period	(41		)
Gains realized during the period from existing and new contracts	(9,662		)
Changes in fair value attributable to changes in valuation techniques	—
Fair value of contracts outstanding at March 31, 2005	$	(10,121	)

A summary of our outstanding derivative positions at March 31, 2005 is as follows (dollars in thousands):

	Fair Value of Contracts at March 31, 2005
Source of Fair Value	Total Fair Value			Maturing In 2005			Maturing In 2006-2007			Maturing In 2008-2009		Maturing Thereafter
Exchange published prices	$	(8,255	)	$	(5,888	)	$	(2,367	)	—		—
Other actively quoted prices (1)	11,265			6,061			5,180			$	24	—
Other valuation methods (2)	(13,131		)	(13,131		)	—			—		—
Total fair value	$	(10,121	)	$	(12,958	)	$	2,813		$	24	—

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

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

Foreign Currency Derivative Market Risk. As a normal part of our business, we enter into physical gas transactions which are payable in Canadian dollars. We enter into forward purchases and sales of Canadian dollars from time to time to fix the cost of our future Canadian dollar denominated natural gas purchase, sale, storage, and transportation obligations. This is done to protect marketing margins from adverse changes in the U.S. 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, 2005, we had sold forward contracts for $14.3 million in Canadian dollars in exchange for $11.9 million in U.S. dollars, and the fair market value of these contracts was a loss of $30,000 in U.S. dollars.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures.

Under the direction of our Chief Executive Officer and President, (“CEO”), and our Executive Vice President and Chief Financial Officer, (“CFO”), we reviewed and evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based on such evaluation, our CEO and CFO concluded, as of the date of such evaluation, that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting.

There have not been any changes in our internal control over financial reporting during the quarter ended March 31, 2005, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 May 7, 2004 (previously filed as Exhibit 99.1 to our Current Report on Form 8-K filed on May 11, 2004 and incorporated herein by reference).

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.

SIGNATURES

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

	WESTERN GAS RESOURCES, INC.
	(Registrant)


Date: May 6, 2005	By:	/s/ Peter A. Dea
		Peter A. Dea
		Chief Executive Officer and President


Date: May 6, 2005	By:	/s/ William J. Krysiak
		William J. Krysiak
		Executive Vice President - Chief Financial Officer
		(Principal Financial and Accounting Officer)

INDEX TO EXHIBITS

Exhibit Number		Description

3.1		Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.1 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).

3.2		Certificate of Amendment to the Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.2 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).

3.3		Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock (previously filed as part of Exhibit 1 to our Form 8-A filed on March 30, 2001 and incorporated herein by reference).

3.4		Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on May 7, 2004 (previously filed as Exhibit 99.1 to our Current Report on Form 8-K filed on May 11, 2004 and incorporated herein by reference).

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