Exhibit 99.1

WESTERN GAS RESOURCES, INC.

ANNOUNCES RECORD THIRD QUARTER 2004 INCOME

DENVER, November 5, 2004. Western Gas Resources, Inc. (NYSE:WGR) today announced that for the quarter ended September 30, 2004, net income increased 68 percent to a record $35.1 million, or earnings of $0.47 per share of common stock, compared to net income of $20.9 million, or earnings of $0.28 per share of common stock, for the same period in 2003. Revenues for the quarter ended September 30, 2004 totaled $718.3 million.

For the nine months ended September 30, 2004, net income was $78.2 million, or earnings of $1.06 per share of common stock. This compares to net income of $65.2 million, or earnings of $0.87 per share of common stock, for the same period in 2003. Revenues for the nine months ended September 30, 2004 were $2.2 billion.

Results for the nine months ended September 30, 2004 include the effect of the previously announced $6.7 million and $7.0 million after-tax charges for debt prepayment and a regulatory settlement, and the $4.7 million after-tax benefit from the cumulative effect of a change in accounting principle. In total, these items reduced earnings per share of common stock by $0.12. Results for the nine months ended September 30, 2003 include a reduction of earnings per share of common stock from the cumulative effect of a change in accounting principle of $0.09.

Earnings per share for all periods are on a fully-diluted basis and are after giving effect to preferred stock dividends. All earnings per share amounts for 2003 have been restated to reflect the two for one stock split completed on June 18, 2004.

For the third quarter of 2004, Adjusted EBITDA (earnings before interest, debt prepayment charges, taxes, depreciation and amortization) was $81.5 million and cash flow before working capital adjustments was $68.7 million.

For the nine months ended September 30, 2004, Adjusted EBITDA (earnings before interest, debt prepayment charges, taxes, depreciation and amortization and the cumulative effect of a change in accounting principle), was $213.2 million and cash flow before working capital adjustments was $184.7 million.

Volumes and prices. Net production was 14.0 billion cubic feet equivalent (“Bcfe”) in the third quarter of 2004 and averaged 152 million cubic feet equivalent per day (“MMcfed”), representing a six percent increase compared to the same period of 2003. Natural gas equity production sold was 14.3 Bcfe in the third quarter of 2004, or 155 MMcfed.

Gas throughput volumes at the Company’s gathering and processing facilities were 1.4 billion cubic feet per day (“Bcfd”) in the third quarter of 2004.

Total gas sales volumes marketed, including equity gas production, gas produced at the Company’s plants and gas purchased from third parties for resale, were 1.1 Bcfd in the third quarter of 2004. Average gas prices received increased 14 percent to $5.38 per thousand cubic feet (“Mcf”) in the third quarter of 2004 compared to $4.70 per Mcf

for the same period in 2003.

Total natural gas liquids (“NGLs”) sales volumes marketed averaged 1.7 million gallons per day (“MMGald”) in the third quarter of 2004, a six percent increase from the same period in 2003. Average NGL prices received increased 37 percent to $0.78 per gallon in the third quarter of 2004 compared to $0.57 per gallon in the same period in 2003.

Hedging. The Company’s equity-hedging positions decreased operating profit by $4.8 million in the third quarter of 2004 and by $6.4 million in the nine months of 2004. This compares to a decrease in operating profit of $7.1 million in the third quarter of 2003 and $29.2 million in the nine months of 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 segment-operating profit of $37.1 million for the third quarter of 2004 compared to $28.2 million for the same period in 2003. This increase was primarily due to substantially higher natural gas prices.

Gathering and processing realized segment-operating profit of $44.3 million for the third quarter of 2004 compared to $31.1 million for the third quarter of 2003. This increase is primarily due to higher gas and NGL prices and improved contract terms in the Powder River Basin.

Gas transportation realized segment-operating profit of $2.7 million for the third quarter of 2004 compared to $2.2 million for the third quarter of 2003. The transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin.

Marketing realized segment-operating profit of $6.7 million for the third quarter of 2004 compared to $4.6 million for the same period in 2003.

Powder River Basin Coal Bed Methane (“CBM”). In the third quarter of 2004, net Powder River Basin CBM production increased two percent to 10.7 Bcfe compared to the second quarter of 2004 and was four percent less than the same period last year. Net CBM production sold increased one percent to 10.9 Bcfe in the third quarter of 2004 compared to the second quarter of 2004, and decreased six percent from the same period last year. The Company, with its partner, continues to be the largest producer of coal bed methane in the basin.

As of November 2004, gross CBM production from wells in which the Company has an interest in the Big George coal was approximately 68 MMcfd of gas from six development areas, an increase of approximately 84 percent from a year ago. Overall, total industry production from the Big George coal has increased to approximately 151 MMcfd as of August 2004. Based on drilling and permitting progress to date, the Company expects to drill in 2004 approximately 725 CBM wells in the Powder River Basin, including 545 wells in the Big George coal.

Western averaged 394 MMcfd of CBM gathering volumes, including third-party gas, during the third quarter of 2004. Of that volume, approximately 105 MMcfd was transported through the Company’s MIGC pipeline. The Company remains the largest gatherer and transporter of coal bed methane in the Powder River Basin.

Greater Green River Basin. Net production from the Greater Green River Basin increased 51 percent to 3.3 Bcfe in the third quarter of 2004 compared to the same period last year and averaged 35.6 MMcfed. This area includes the Pinedale Anticline and Jonah Field in southwest Wyoming and the Sand Wash Basin in northwest Colorado. Net production sold increased 60 percent to 3.3 Bcfe net in the third quarter of 2004 compared to the same period last year. In 2004, Western plans to participate in approximately 70 gross wells on the Pinedale Anticline, of which approximately 50 have been drilled year to date. Five gross wells have been drilled in the Sand Wash Basin in 2004.

Capital Expenditures. The Company increased its budget for capital expenditures in 2004 to $352.4 million, including $82.2 million for the previously announced acquisition of upstream and midstream assets in the San Juan Basin. The

revised 2004 capital budget includes approximately $146.6 million for exploration, production and acquisition activities, $112.8 million for midstream activities and $10.8 million for administrative and capitalized interest and overhead costs.

Balance sheet. At September 30, 2004, Western had total assets of $1.6 billion, cash and cash equivalents in short-term investments of $2.7 million, total long-term debt outstanding of $317.5 million and a debt to capitalization ratio, net of cash and cash equivalents, of 33 percent.

CEO comments. Peter Dea, President and Chief Executive Officer, commented, “High commodity prices combined with increased volumes and low costs led to record net income for the quarter. Our midstream assets have been particularly profitable with very high natural gas and liquid prices and resulting strong margins. Continued production growth from the Big George coal and Pinedale Anticline will provide positive momentum into 2005. Combined with an outlook for strong prices, high liquid margins and expanding exploration plays, Western is poised for future shareholder value.”

Operational performance guidance for the remainder of 2004. Operational performance guidelines for 2004 were provided in a press release by the Company dated February 13, 2004 and updated May 6, 2004 and August 5, 2004. The following information represents modifications to the previous guidance.

Production. Production volumes are expected to average 163 MMcfed net during the fourth quarter of 2004. This includes 114 MMcfd of CBM production in the Powder River Basin, 36 MMcfed from the Greater Green River Basin and 13 MMcfd in the San Juan Basin. For the full year 2004 production volumes are expected to be 151 MMcfed, an increase of five percent compared to 2003. In 2005, the Company expects production growth of approximately 10 percent from all sources. Gathering and transportation expense for all production is expected to average approximately $0.72 per Mcf for the fourth quarter of 2004. Lease operating expense for all production is expected to average approximately $0.68 per Mcf for the fourth quarter of 2004, which includes production overhead of $0.10 per Mcf. Other miscellaneous expenses, which includes land and exploration costs, are expected to be $0.09 per Mcf for the fourth quarter of 2004. The Company follows the successful efforts method of accounting for oil and gas exploration and production activities.

Gathering and Processing. Throughput volumes for the fourth quarter of 2004 are expected to average 1.4 Bcfd. Plant gas sales are expected to average 350 MMcfd and plant NGL sales are expected to average 1.45 MMGald for the fourth quarter of 2004. The gross operating margin (gross revenues less product purchase expenses) for the gathering and processing business is expected to average approximately $0.58 per Mcf of facility throughput for the fourth quarter of 2004. Gross operating margin is dependent on commodity prices, and these estimates are based on an assumption of $6.75 per Mcf for natural gas and $53.00 per barrel for crude oil (NYMEX-equivalent prices) for the quarter. Plant operating expenses are expected to average $0.17 per Mcf of throughput for the fourth quarter of 2004.

Transportation. Gas transportation and sales volumes are expected to be approximately 155 MMcfd and revenues are projected to be approximately $5.5 million for the fourth quarter of 2004. Operating income, after deducting pipeline operating expense and product purchase expense, is expected to be approximately $2.4 million for the fourth quarter of 2004.

Marketing. Total gas sales volumes marketed (which include production, plant and third-party gas) are expected to be 1.3 Bcfd for the fourth quarter of 2004. Total NGL sales volumes marketed, including plant and third party volumes, are expected to average 1.65 MMgald for the fourth quarter of 2004. Gas marketing margins are expected to average approximately $0.025 per Mcf. NGL marketing margins are expected to average approximately $0.01 per gallon. These assumptions include the impact of mark-to-market accounting for the Company’s marketing activities.

Other expenses. General and administrative expenses are expected to be $10.0 million, depreciation, depletion and amortization expenses are expected to be $24.0 million and interest expenses are estimated to be $3.7 million for the fourth quarter of 2004. The provision for income taxes for the fourth quarter of 2004 is expected to be approximately 37 percent.

Earnings conference call. Western invites you to participate in its third quarter 2004 earnings conference call today at 9:30 a.m. (Mountain Time) by dialing (719) 457-2661. Please dial in five to ten minutes before the start of the call. A replay of the conference call will be available through midnight, November 11, 2004 by dialing (719) 457-0820 (passcode 909032). 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 November 30, 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 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 commodity prices, expenses, sales and operating margins, sales volumes, acquisitions, capital expenditures, drilling activity and production volumes for the remainder of 2004 and 2005. 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, litigation, environmental risk, geological risk, weather, rig availability, transportation capacity and other factors as discussed in the Company’s 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission.

Financial Results:

(Dollars in thousands except share and per share amounts)

	Quarter Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003

Revenues:
Sale of gas	$	560,983		$	557,105		$	1,821,974		$	1,909,297
Sale of natural gas liquids	124,464			86,009			319,400			258,840
Gathering, processing and transportation revenues	25,080			21,884			66,319			63,119
Price risk management activities	7,158			1,065			5,338			(18,050		)
Other, net	570			737			2,743			2,191

Total revenues	718,255			666,800			2,215,774			2,215,397

Costs and expenses:
Product purchases	585,774			566,937			1,845,282			1,898,375
Plant and transportation operating expense	23,976			21,944			68,165			66,478
Oil and gas exploration and production expense	18,510			13,029			55,432			38,830
Depreciation, depletion and amortization	22,039			17,477			67,013			53,305
Selling and administrative expense	10,305			8,972			37,506			29,487
(Gain) loss from asset sales	(230		)	56			1,409			142
(Earnings) from equity investments	(1,542		)	(1,780		)	(5,244		)	(5,209		)
Interest expense	3,912			6,449			15,065			19,692
Loss from early extinguishment of debt	—			—			10,662			—

Total costs and expenses	662,744			633,084			2,095,290			2,101,100

Income before taxes	55,511			33,716			120,484			114,297

Provision for income taxes	20,393			12,827			47,017			42,409

Net income before cumulative effect of changes in accounting principles	35,118			20,889			73,467			71,888

Cumulative effect of changes in accounting principles, net of tax	—			—			4,714			(6,724		)

Net income	35,118			20,889			78,181			65,164

Preferred stock requirements	—			(1,811		)	(835		)	(5,434		)

Net income available to common stock	$	35,118		$	19,078		$	77,346		$	59,730

Weighted average shares of common stock outstanding	73,778,729			66,394,530			71,887,962			66,288,592

Earnings per share of common stock	$	0.48		$	0.29		$	1.08		$	0.90

Weighted average shares of common stock - assuming dilution	74,998,146			74,690,296			72,934,517			74,541,408

Earnings per share of common stock - assuming dilution	$	0.47	(1)	$	0.28	(2)	$	1.06	(3)	$	0.87	(4)

(1) Fully-diluted earnings per share for the quarter ended September 30, 2004 include, as potential common shares, the issuance of 1.2 million common shares from the possible exercise of stock options.

(2) Fully-diluted earnings per share for the quarter ended September 30, 2003 include, as potential common shares, the issuance of 1.4 million common shares from the possible exercise of stock options and 7.0 million 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 income attributable to common stock.

(3) Fully-diluted earnings per share for the nine months ended September 30, 2004 include, as potential common shares, the issuance of 1.0 million common shares from the possible exercise of stock options.

(4) Fully-diluted earnings per share for the nine months ended September 30, 2003 include, as potential common shares, the issuance of 1.3 million common shares from the possible exercise of stock options and 7.0 million common shares upon an assumed conversion of the $2.625 cumulative convertible preferred stock, and also include an assumed reduction of preferred dividends of $5.4 million in determining income attributable to common stock.

Condensed Consolidated Balance Sheet:

(Dollars in thousands)

	As of September 30, 2004		As of December 31, 2003
Assets:
Current assets	$	397,184	$	387,303
Property and equipment, net	1,086,172		996,761
Other assets	70,570		76,460

Total assets	$	1,553,926	$	1,460,524

Liabilities and Stockholders’ Equity:
Liabilities:
Current liabilities	$	361,503	$	358,981
Long-term debt	317,500		339,000
Other liabilities	243,630		200,034

Total liabilities	922,633		898,015

Stockholders’ equity	631,293		562,509

Total liabilities and stockholders’ equity	$	1,553,926	$	1,460,524

Reconciliation of Net Income to Adjusted EBITDA:

(Dollars in thousands)

	Quarter Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004			2003

Net income	$	35,118	$	20,889	$	78,181		$	65,164

Add:
Cumulative effect of change in accounting principle, net of tax	—		—		(4,714		)	6,724
Depreciation, depletion and amortization	22,039		17,477		67,013			53,305
Interest expense	3,912		6,449		15,065			19,692
Loss from early extinguishment of debt	—		—		10,662			—
Income taxes	20,393		12,827		47,017			42,409

Adjusted EBITDA	$	81,462	$	57,642	$	213,224		$	187,294

Reconciliation of Net Income to

Cash Flow before Working Capital Adjustments:

(Dollars in thousands)

	Quarter Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003

Net income	$	35,118		$	20,889		$	78,181		$	65,164
Add income items that do not affect operating cash flows:
Depreciation, depletion and amortization	22,039			17,477			67,013			53,305
Deferred income taxes	18,444			12,283			42,533			39,272
Distributions less than equity income, net	(1,077		)	1,200			(742		)	1,244
(Gain)loss on sale of property and equipment	(230		)	56			1,409			142
Non-cash change in fair value of derivatives	(6,859		)	(1,564		)	(2,163		)	(1,084		)
Compensation expense from repriced stock options	6			482
Foreign currency translation adjustments	1,248			170			144			857
Cumulative effect of changes in accounting principles	—			—			(4,714		)	6,724
Other non-cash items	—			142			2,584			426

Cash flow before working capital adjustments	$	68,689		$	50,653		$	184,727		$	166,050

Operating Results:

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

	Quarter Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Exploration and Production:
Average gas production – net volumes sold (MMcfed)	155			149			149			148
Average gas price ($/Mcfe) (1)	$	4.55		$	4.04		$	4.52		$	4.31
Gathering and transportation expense ($/Mcfe)	$	0.78		$	0.69		$	0.74		$	0.68
Average wellhead gas price ($/Mcfe) (2)	$	3.77		$	3.35		$	3.78		$	3.63
Production taxes ($/Mcfe)	$	0.46		$	0.43		$	0.48		$	0.46
LOE ($/Mcfe) (3)	$	0.61		$	0.47		$	0.64		$	0.43
Other expense ($/Mcfe) (4)	$	0.12		$	0.08		$	0.14		$	0.09
Effect of equity hedges	$	324		$	(4,920	)	$	3,441		$	(18,247	)
Segment - operating profit	$	37,145		$	28,239		$	106,818		$	90,154
Depreciation, depletion and amortization	$	10,245		$	7,393		$	32,111		$	23,421

Gas Gathering and Processing:
Gas throughput volumes (MMcfd)	1,389			1,369			1,361			1,334
Average plant gas sales (MMcfd)	323			482			355			475
Average plant NGL sales (MGald)	1,441			1,300			1,405			1,350
Average gas price ($/Mcf) (5)	$	5.10		$	4.44		$	5.05		$	4.68
Average NGL price ($/Gal) (6)	$	0.76		$	0.53		$	0.67		$	0.54
Gross operating margin ($/Mcf) (7)	$	0.55		$	0.41		$	0.52		$	0.43
Plant operating expense ($/Mcf) (7)	$	0.18		$	0.16		$	0.18		$	0.17
Effect of equity hedges	$	(5,081	)	$	(2,208	)	$	(9,819	)	$	(10,940	)
Income from equity investments	$	1,542		$	1,780		$	5,244		$	5,209
Segment - operating profit	$	44,348		$	31,077		$	122,874		$	88,947
Depreciation, depletion and amortization	$	9,769		$	7,485		$	27,981		$	22,603

Gas Transportation:
Gas transportation volumes (MMcfd)	154			155			156			165
Transportation and sales revenue	$	5,456		$	5,397		$	16,910		$	16,633
Operating and product purchase expense	$	2,715		$	3,166		$	9,242		$	7,395
Segment - operating profit	$	2,741		$	2,231		$	7,668		$	9,238
Depreciation, depletion and amortization	$	415		$	413		$	1,239		$	1,275

Marketing:
Average gas sales (MMcfd)	1,130			1,285			1,229			1,374
Average NGL sales (MGald)	1,741			1,639			1,665			1,640
Average gas price ($/Mcf)	$	5.38		$	4.70		$	5.39		$	5.08
Average NGL price ($/Gal)	$	0.78		$	0.57		$	0.70		$	0.58
Average gas sales margin ($/Mcf)	$	0.045		$	0.026		$	0.025		$	0.064
Average NGL sales margin ($/Gal)	$	0.013		$	0.011		$	0.010		$	0.009
Segment - operating profit	$	6,732		$	4,639		$	13,004		$	28,231
Depreciation, depletion and amortization	$	35		$	35		$	87		$	106

(1) Net of fuel and shrink.

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

(3) Includes production overhead.

(4) Includes exploratory expense, delay rentals, 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 –Q4 2004 and 2005 Equity Gas and NGL Hedges

Product	Year	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	2004	70,000 MMBtu per day with a minimum price of $4.00 and a maximum price ranging from $6.50 to $9.45 per MMBtu (average of $7.81 per MMBtu.)	Mid-Continent – 55,000 MMBtu per day with an average basis price of $0.27 per MMBtu.

			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.

	2005	80,000 MMBtu per day with an average minimum price of $4.75 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.

			Rockies – 15,000 MMBtu per day with an average basis price of $0.72 per MMBtu.

			El Paso Permian – 5,000 MMBtu per day with an average basis prices of $0.48 per MMBtu.

Crude, Condensate, Natural Gasoline	2004	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

	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	2004	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

	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	2004	50,000 Barrels per month. Floor at $0.31 per gallon.	Not Applicable

	2005	75,000 barrels per month. Floor at $0.38 per gallon.	Not Applicable

Investor Contact: Ron Wirth, Director of Investor Relations
(800) 933-5603 or (303) 252-6090
e-mail: rwirth@westerngas.com