Exhibit 99.1

WESTERN GAS RESOURCES, INC.

ANNOUNCES FIRST QUARTER 2004 RESULTS

May 6, 2004.  Western Gas Resources, Inc. (“Western”) (NYSE:WGR) today announced net income of $29.1 million or $0.79 per share of common stock for the quarter ended March 31, 2004.  This compares to net income of $23.4 million or $0.63 per share of common stock for the same period in 2003.  Earnings per share are presented on a fully-diluted basis for both periods and are after giving effect to preferred stock dividends.  Both periods include the effect of a change in accounting principle.  Excluding the effects of the change in accounting principle in both periods, net income in the first quarter of 2004 was $24.4 million and net income in the first quarter of 2003 was $30.1 million.

The Company also reported adjusted EBITDA (earnings before interest, taxes, depreciation and amortization and the cumulative effect of a change in accounting principle) for the first quarter of 2004 of $66.8 million and cash flow before working capital adjustments of $60.9 million.  Revenues totaled $771.2 million.

Cumulative Effect of Changes in Accounting Principles.  Effective January 1, 2004, the Company redefined the asset groupings for the calculation of depreciation and depletion from a property-by-property basis to a field wide basis for each of the Jonah, Pinedale and Sand Wash Basins and to a grouping of all wells drilled into related coal seams for the Powder River Basin.  The change in the asset groupings for depreciation purposes is treated as a change in accounting principle.  Accordingly, the accumulated depreciation for these assets has been recalculated under the new asset groupings.  The cumulative effect of the change in depreciation resulted in a one-time increase to earnings of $4.7 million, net of tax, or $0.13 per common share on a fully-diluted basis in the first quarter of 2004.

In June 2001, the Financial Accounting Standards Board, issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”).  SFAS No. 143 establishes accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost.  The Company adopted SFAS No. 143 on January 1, 2003.  The adoption of SFAS No. 143 resulted in a one-time charge to earnings of $6.7 million, net of tax, or $0.18 per share of common stock on a fully-diluted basis in the first quarter of 2003 for the cumulative effect of the change in accounting principle.

Volumes and prices.  Natural gas equity production sold was 13.2 billion cubic feet equivalent (“Bcfe”) and averaged 145 million cubic feet equivalent per day (“MMcfed”).  Net of prior period adjustments, actual production was 13.5 Bcfe and averaged 149 MMcfed, representing an increase of five percent compared to net production in the same period of 2003.  All of the Company’s production was achieved in the Powder River Basin coal bed methane (“CBM”) play and the Greater Green River Basin.

Total gas sales volumes marketed, including equity gas production, gas purchased under contracts at the Company’s plants and gas purchased from third parties for resale, averaged 1.4 billion cubic feet per day (“Bcfd”)

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in the first quarter of 2004.  Average gas prices for marketed volumes decreased four percent to $5.32 per Mcf compared to $5.53 per Mcf for the same period in 2003.

Total natural gas liquids (“NGLs”)sales volumes marketed averaged 1.6 million gallons per day in the first quarter of 2004.  Average NGL prices for marketed volumes increased two percent to $0.63 per gallon compared to $0.62 per gallon for the same period in 2003.

Operations.  The Company’s fully integrated operations include exploration and production, gathering and processing, transportation and marketing of natural gas and NGLs.

Exploration and production realized operating profit (adjusted EBITDA before general and administrative expenses) of $33.1 million for the first quarter of 2004 compared to $33.4 million for the first quarter of 2003.

Gathering and processing operations realized operating profit of $37.7 million for the first quarter of 2004 compared to $32.0 million for the first quarter of 2003.  The increase is primarily due to improved contract terms on gas gathered in the Powder River Basin and improved prices realized after the effect of equity hedging.

Gas transportation realized operating profit of $2.4 million for the first quarter of 2004 compared to $4.1 million for the first quarter of 2003.  The transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin. Transportation volumes and revenues were lower compared to a year ago as some interruptible volume was transported out of the basin through the Fort Union system.

Marketing realized operating profit of $3.0 million for the first quarter of 2004 compared to $14.8 million for the same period in 2003.  The results for the marketing business in the first quarter of 2003 benefited significantly from transactions utilizing the Company’s firm transportation primarily due to a wider basis differential in the Rockies region relative to the Mid-Continent region.

Hedging.  The Company’s equity hedging positions decreased operating profit by $764,000 for the first quarter of 2004 compared to a decrease in operating profit of $15.5 million in the first quarter of 2003.

Powder River Basin CBM.  Net CBM production volumes sold decreased ten percent to 10.1 Bcf in the first quarter of 2004 as compared to the same period in 2003 and averaged 111 MMcfd.  Net of prior period adjustments, actual net CBM production decreased five percent.  Previous permitting delays, a decline in Wyodak production and the normal 12 to 24 month dewatering period for new Big George wells account for the year over year change.  The Company, with its partner, continues to be the largest producer of methane in the basin.  Western currently plans to participate in over 800 gross wells in the Powder River Basin in 2004, of which 161 wells were drilled year to date.  Completion of the Company’s 2004 drilling program will be subject to obtaining the necessary drilling and water discharge permits in a timely fashion.

Gross CBM production from wells in which the Company has an interest in the Big George coal increased an estimated 38 percent from a year ago and averaged approximately 39 MMcfd in the first quarter of 2004.  As of April 30, 2004, gross CBM production had increased to approximately 48 MMcfd from five development areas.  Industry, including Western, was producing over 122 MMcfd in February 2004 from the Big George coal in 11 pilots over a 50-mile area.  In total, 909 Big George wells have been drilled by the Company and its partner through April 2004, of which 424 are producing gas and 485 of which are dewatering or awaiting hookup.  The Company expects to drill approximately 500 gross wells in various pilots in the Big George coal during 2004.

Western averaged 390 MMcfd of CBM gathering volumes, including third-party gas, during the first quarter of 2004. This represents a six percent decrease compared to the same period in 2003.  Of that volume, approximately 105 MMcfd was transported through the Company’s MIGC pipeline. The Company remains the largest gatherer

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and transporter of CBM in the Powder River Basin.

Greater Green River Basin.  Production from the Pinedale Anticline and Jonah Field development areas of southwest Wyoming and the Sand Wash Basin development area in northwest Colorado increased 54 percent to 3.1 Bcfe net in the first quarter of 2004 compared to the same period of 2003 and averaged 33.6 MMcfed.  In 2004, Western plans to participate in the completion of approximately 90 gross wells on the Pinedale Anticline, of which 12 were drilled in the first quarter.  Nine gross wells are planned in the Sand Wash Basin, of which three were drilled in the first quarter.  The Company has exposure to participate in up to 1,000 gross (100 net) potential drilling locations on the Pinedale Anticline based on 20-acre spacing in this area.

Balance sheet.  At March 31, 2004, Western had total assets of $1.4 billion, total debt outstanding of $245 million and a debt to capitalization ratio of 27 percent, net of cash and cash equivalents.

CEO comments.  Peter Dea, Chief Executive Officer and President, commented, “ We continue to make progress in the development of our 2.1 Tcf of unbooked, unrisked probable and possible reserves in our two consolidated projects.  Meaningful production increases are occurring in the Pinedale Anticline and the Big George coal in the Powder River Basin as we strive to fully develop these significant gas fairways.  We are realizing the benefit from higher commodity prices, our low-cost structure and strong margins from our midstream operations as we continue to deliver shareholder value through our fully integrated natural gas operations.”

Revisions to operational performance guidance for the remainder of 2004.  The Company provided operational performance guidelines for 2004 in a press release dated February 13, 2004.  The following information represents modifications to the previous guidance.  Other guidance information remains unchanged.

Production.  Gathering and transportation expense is expected to average $0.68-0.70 per Mcfe for the remainder of 2004.  Lease operating expense (LOE) for all production is expected to average $0.62 per Mcfe for the remainder of the year, which includes $0.10 per Mcfe of production overhead.  The increase in LOE is related to the cost of installing and operating wellhead blowers to recover gas from older Wyodak wells and increased water handling costs in the Big George coal.  Other miscellaneous expenses, which include land related costs and exploration costs, are expected to be $0.11 per Mcfe.

Gathering and Processing.  Plant gas sales are expected to average 380 MMcfd for the remainder of the year.    The gross operating margin (gross revenues less product purchase expenses) for the gathering and processing business is expected to average approximately $0.49 per Mcf of facility throughput for the remainder of 2004.  Gross operating margin is dependent on commodity prices, and these estimates are based on a higher assumption of $5.75 per Mcf for natural gas and $34.65 per barrel for crude oil (NYMEX-equivalent prices.)

Other expenses.  Depreciation, depletion and amortization expenses are expected to be $67 million for the remainder of 2004, which includes $36 million for exploration and production.

Earnings conference call.  Western invites you to participate in its first quarter 2004 earnings conference call today at 9:30 AM Mountain Time by dialing (719) 457-2602.  A replay of the conference call will be available through midnight, May 12, 2004 by dialing (719) 457-0820 (pass code 584066).  The live conference call may also be accessed on the Internet by logging onto Western’s Web site at www.westerngas.com.  Select Financial/Investor Information followed by the Current News option on the menu.  Log on at least ten minutes prior to the start of the call to register, download and install any necessary audio software.  An audio replay will be available on the web site through May 31, 2004.

Company Description.  Western is an independent natural gas explorer, producer, gatherer, processor, transporter and energy marketer providing a broad range of services to its customers from the wellhead to the sales delivery

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point.  The Company’s producing properties are located primarily in Wyoming, including the developing Powder River Basin coal bed methane play, where Western is a leading acreage holder and producer, and the rapidly growing Pinedale Anticline.  The Company also designs, constructs, owns and operates natural gas gathering, processing and treating facilities in major gas-producing basins in the Rocky Mountain, Mid-Continent and West Texas regions of the United States.  For additional Company information, visit Western’s web site at www.westerngas.com.

This press release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 regarding future drilling activity, operating expenses and production and sales volumes.  Although the Company believes that its expectations are based on reasonable assumptions, Western can give no assurances that its goals will be achieved. These statements are subject to a number of risks and uncertainties, which may cause actual results to differ materially.  These risks and uncertainties include, among other things, changes in natural gas and NGL prices, government regulation or action, geological risk, environmental risk, weather, rig availability, transportation capacity, the ability of Western’s partners to fund the necessary capital expenditures and the progress of ongoing litigation and related disputes with its co-developer in the Powder River Basin of Wyoming, and other factors as discussed in the Company’s 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission.

Investor Contact:	Ron Wirth, Director of Investor Relations
	(800) 933-5603
	e-mail: rwirth@westerngas.com

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Financial Results:

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

	Three Months Ended March 31,
	2004			2003
Revenues:
Sale of residue gas	$	665,198		$	793,270
Sale of natural gas liquids	92,915			92,049
Gathering, processing and transportation revenues	16,829			19,777
Price risk management activities	(5,368		)	(17,694		)
Other, net	1,642			704
Total Revenues	771,216			888,106
Costs and expenses:
Product purchases	657,342			771,602
Plant and transportation operating expense	21,934			21,922
Oil and gas exploration and production expense	17,110			12,511
Depreciation, depletion and amortization	22,626			18,143
Selling and administrative expense	9,946			10,592
Loss from asset sales	—			281
(Earnings) from equity investments	(1,926		)	(1,562		)
Interest expense	5,802			6,814
Total costs and expenses	732,834			840,303
Income before taxes	38,382			47,803
Provision for income taxes	14,008			17,704
Net income before cumulative effect of changes in accounting principles	24,374			30,099
Cumulative effect of changes in accounting principles, net of tax	4,714			(6,724		)
Net income	29,088			23,375
Preferred stock requirements	(816		)	(1,811		)
Net income available to common stock	$	28,272		$	21,564
Weighted average shares of common stock outstanding	34,182,950			33,087,680
Earnings per share of common stock	$	0.83		$	0.65
Weighted average shares of common stock – assuming dilution	36,825,805			37,163,098
Earnings per share of common stock - assuming dilution	$	0.79	(1)	$	0.63	(2)

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(1)Fully-diluted earnings per share for the quarter ended March 31, 2004 include, as potential common shares, the issuance of 907,764 common shares from the possible exercise of stock options and 1,735,091 common shares upon an assumed conversion of the $2.625 cumulative convertible preferred stock, and also include an assumed reduction of preferred dividends of $0.8 million in determining net income attributable to common stock.

(2)Fully-diluted earnings per share for the quarter ended March 31, 2003 include, as potential common shares, the issuance of 603,719 common shares from the possible exercise of stock options and 3,471,699 common shares upon an assumed conversion of the $2.625 cumulative convertible preferred stock, and also include an assumed reduction of preferred dividends of $1.8 million in determining net income attributable to common stock.

Condensed Consolidated Balance Sheet:

(Dollars in thousands)

	As of March 31, 2004		As of December 31, 2003
Assets:
Current assets	$	329,552	$	387,303
Property and equipment, net	1,020,237		996,761
Other assets	75,604		76,460
Total assets	$	1,425,393	$	1,460,524
Liabilities and Stockholders’ equity:
Liabilities:
Current liabilities	$	378,811	$	358,981
Long-term debt	245,000		339,000
Other liabilities	213,218		200,034
Total liabilities	837,029		898,015
Stockholders’ equity	588,364		562,509
Total liabilities and stockholders’ equity	$	1,425,393	$	1,460,524

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Reconciliation of Net Income to Adjusted EBITDA:

(Dollars in thousands)

	Three months Ended March 31,
	2004			2003
Net income	$	29,088		$	23,375
Add:
Cumulative effect of change in accounting principle, net of tax	(4,714		)	6,724
Depreciation, depletion and amortization	22,626			18,143
Interest expense	5,802			6,814
Income taxes	14,008			17,704
Adjusted EBITDA	$	66,810		$	72,760

Reconciliation of Net Income to

Cash Flow before Working Capital Adjustments:

(Dollars in thousands)

	Three months Ended March 31,
	2004			2003
Net income	$	29,088		$	23,375
Add income items that do not affect operating cash flows:
Depreciation, depletion and amortization	22,626			18,143
Deferred income taxes	10,465			17,183
Distributions less than equity income, net	(1,460		)	1,431
Loss on sale of property and equipment	—			281
Non-cash change in fair value of derivatives	6,219			4,163
Compensation expense from repriced stock options	181			241
Foreign currency translation adjustments	(1,528		)	-
Cumulative effect of changes in accounting principles	(4,714		)	6,724
Other non-cash items	48			683
Cash flow before working capital adjustments	$	60,925		$	72,224

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Operating Results:

(Dollars in thousands, except per Mcfe, per Mcf and per Gal amounts)

	Three Months Ended March 31,
	2004			2003
Production:
Average gas production – net volumes sold (MMcfed)	145			147
Average gas price ($/Mcfe) (1)	$	4.41		$	4.87
Gathering and transportation expense ($/Mcfe)	$	0.71		$	0.72
Average wellhead gas price ($/Mcfe) (2)	$	3.70		$	4.15
Production taxes ($/Mcfe)	$	0.51		$	0.57
LOE ($/Mcfe) (3)	$	0.64		$	0.36
Other expense  ($/Mcfe) (4)	$	0.18		$	0.05
Effect of equity hedges	$	1,500		$	(8,836	)
Segment – operating profit	$	33,114		$	33,399
Depreciation, depletion and amortization	$	10,992		$	8,420
Gas Gathering and Processing:
Gas throughput volumes (MMcfd)	1,312			1,299
Average plant gas sales (MMcfd)	382			476
Average plant NGL sales (MGald)	1,398			1,393
Average gas price ($/Mcf) (5)	$	4.95		$	5.11
Average NGL price ($/Gal) (6)	$	0.61		$	0.60
Gross operating margin ($/Mcf) (7)	$	0.488		$	0.490
Plant operating expense ($/Mcf) (7)	$	0.169		$	0.173
Effect of equity hedges	$	(2,264	)	$	(6,637	)
Income from equity investments	$	1,926		$	1,562
Segment - operating profit	$	37,749		$	32,022
Depreciation, depletion and amortization	$	9,000		$	7,535
Gas Transportation:
Gas transportation volumes (MMcfd)	153			193
Transportation and sales revenue	$	5,739		$	6,010
Operating and product purchase expense	$	3,341		$	1,948
Segment - operating profit	$	2,398		$	4,062
Depreciation, depletion and amortization	$	416		$	433
Marketing:
Average gas sales (MMcfd)	1,367			1,593
Average NGL sales (MGald)	1,611			1,655
Average gas price ($/Mcf)	$	5.32		$	5.53
Average NGL price ($/Gal)	$	0.63		$	0.62
Average gas sales margin ($/Mcf)	$	0.019		$	0.095
Average NGL sales margin ($/Gal)	$	0.004		$	0.008
Segment – operating profit	$	2,952		$	14,784
Depreciation, depletion and amortization	$	17		$	35

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(1)Net of fuel and shrink.

(2)Net of fuel, shrink, gathering and transportation.  Excludes effect of hedging.

(3)Includes production overhead.

(4)Includes delay rentals, geological and geophysical expense, impairment and unsuccessful well expense.

(5)Represents average gas sales price adjusted for appropriate regional differential.

(6)Represents average NGL sales price adjusted for appropriate transportation and fractionation charges.

(7)Per Mcf of throughput.  Gross operating margin is gross revenues less product purchases and joint interest and excludes effect of hedging.

Table A – Q2-Q4 –2004 Equity Gas and NGL Hedges

Product	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	70,000 MMBtu per day with a minimum price of $4.00 per MMBtu and an average maximum price of $7.81 per MMBtu.	Mid-Continent – 55,000 MMBtu per day with an average basis price of ($0.27). Permian – 5,000 MMBtu per day with an average basis price of ($0.34) per MMBtu. Rocky Mountain – 10,000 MMBtu per day with an average basis price of ($0.74) per MMBtu.
Crude, Condensate, Natural Gasoline	50,000 Barrels per month with a minimum price of $22.00 per barrel and a maximum price of $30.08 per barrel.	Not Applicable
Propane	90,000 Barrels per month with a minimum price of $0.42 per gallon and a maximum price of $0.56 per gallon.	Not Applicable
Ethane	50,000 Barrels per month.  Floor at $0.305 per gallon.	Not Applicable

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