EXHIBIT 99.1

WESTERN GAS RESOURCES, INC.
ANNOUNCES 56 PERCENT RISE IN THIRD QUARTER 2003 EARNINGS

November 11, 2003. Western Gas Resources, Inc. (NYSE:WGR) today announced that for the quarter ended September 30, 2003, net income increased 56 percent to $20.9 million or earnings of $0.56 per share of common stock compared to net income of $13.4 million or earnings of $0.34 per share of common stock for the same period in 2002. Earnings per share for both periods are on a fully-diluted basis and are after giving effect to preferred stock dividends. Revenues for the quarter ended September 30, 2003 totaled $666.8 million.

For the nine months ended September 30, 2003, net income increased 85 percent to $65.2 million or earnings of $1.75 per share of common stock compared to net income of $35.2 million or earnings of $0.86 per share of common stock for the same period in 2002. Earnings per share for both periods are on a fully-diluted basis and are after giving effect to preferred stock dividends. Net income for the nine months ended September 30, 2003 includes the cumulative effect of a one-time after-tax charge for a change in accounting principle of $6.7 million or $0.18 per share. Revenues for the nine months ended September 30, 2003 were $2.2 billion.

For the third quarter of 2003, EBITDA (earnings before interest, taxes, depreciation and amortization) was $57.6 million and cash flow before working capital adjustments was $50.7 million.

For the nine months ended September 30, 2003, EBITDA (earnings before interest, taxes, depreciation and amortization and the cumulative effect of a change in accounting principle) was $187.3 million and cash flow before working capital adjustments was $166.1 million.

Volumes and prices. Natural gas equity production in the third quarter of 2003 increased compared to the same period a year ago and total gas sales volume decreased. Prices received for natural gas and natural gas liquids (“NGLs”) increased significantly from a year ago.

Natural gas equity production in the third quarter of 2003 increased seven percent compared to the same period in 2002, averaging 149 million cubic feet equivalent per day (“MMcfed”). The Company’s production growth was in the Powder River Basin coal bed methane (“CBM”) play and the Greater Green River Basin.

Total gas sales volume, including the sale of equity gas production, the sale of gas produced at the Company’s plants and the sale of gas purchased from third parties for resale, was 1.3 billion cubic feet per day (“Bcfd”) in the third quarter of 2003 compared to 2.0 Bcfd for the same period in 2002. The decrease is primarily from a reduction in the sale of natural gas purchased from third parties for resale. Average gas prices increased 70 percent to $4.70 per Mcf in the third quarter of 2003 compared to $2.77 per Mcf for the same period in 2002.

Total NGLs sales volume averaged 1.6 million gallons per day (“MMGald”) in the third quarter of 2003 compared to

2.2 MMGald in the same period of 2002. The decrease in sales volume was largely the result of a reduction in third party sales volume and as a result of reduced NGL production at our Granger facility, as it was more economical to leave ethane in the natural gas stream. Average NGL prices increased 36 percent to $0.57 per gallon in the third quarter of 2003 compared to $0.42 per gallon in the same period in 2002.

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

Exploration and production realized segment-operating profit (EBITDA before general and administrative expenses) of $28.2 million for the third quarter of 2003 compared to $18.4 million for the same period in 2002. This 53 percent increase was primarily due to substantially higher natural gas prices and production volume growth from the Powder River CBM and Pinedale Anticline developments.

Gathering, processing and treating realized segment-operating profit of $30.7 million for the third quarter of 2003 compared to $25.6 million for the third quarter of 2002. This 20 percent increase is primarily due to higher commodity prices, increased gathering volumes and the acquisition of several gathering systems in February 2003.

Gas transportation realized segment-operating profit of $2.2 million for the third quarter of 2003 compared to $4.2 million for the third quarter of 2002. 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 certain CBM volumes were moved on the Fort Union gathering system rather than MIGC.

Marketing realized segment-operating profit of $4.6 million for the third quarter of 2003 compared to $9.1 million for the same period in 2002. This segment utilizes a dedicated portion of the Company’s firm transportation capacity to purchase gas in the Rocky Mountain region for resale in the higher priced Mid-Continent markets. Operating profit decreased compared to the 2002 period because the price difference between the two regions narrowed as additional transportation capacity out of the Rocky Mountain region became operational in the second quarter of 2003.

Hedging. The Company’s equity-hedging positions decreased operating profit by $7.1 million in the third quarter of 2003 and by $29.2 million in the nine months ended September 30, 2003. This compares to an increase in operating profit of $6.4 million in the third quarter of 2002 and to an increase in operating profit of $19.2 million in the nine months ended September, 30, 2002 resulting from hedge positions in that year. The hedging positions in the remainder of 2003 are outlined in Table A.

The Company has hedged 70,000 MMbtus of its 2004 equity production in a costless collar structure with a minimum price of $4.00 per MMbtu and an average maximum price of $7.81 per MMbtu on a NYMEX-equivalent basis. These hedging positions are outlined in Table B.

Powder River Basin Coal Bed Methane. Net CBM production sold increased three percent to 11.7 Bcf in the third quarter of 2003 as compared to the same period in 2002, and averaged 127 MMcfd, including six MMcfd of prior period adjustments. In 2003, the Company has participated in the drilling of 470 wells through October 2003 and plans to participate in a total of 600 to 650 wells.

The Bureau of Land Management’s (“BLM”) Buffalo, Wyoming field office has issued permits for 273 CBM wells on federal acreage since the final Record of Decision (“ROD”) for the Powder River Basin Oil and Gas Environmental Impact Statement (“EIS”) was approved in April 2003. Since the issuance of the ROD through October 2003, Western and its co-developer have received 89 CBM well permits. The BLM has publicly stated that their goal is to issue to industry a total of 3,000 permits annually.

As of October 2003, gross natural gas production from CBM wells, in which the Company has an interest, in the Big George coal was approximately 37 MMcfd of gas. This production was from the All Night Creek, Pleasantville and

Kingsbury areas. Overall, total industry production from the Big George coal has increased approximately 158 percent in the last 12 months to approximately 112 MMcfd in August 2003. The Company expects to participate in 240 Big George wells in 2003 as part of its overall drilling program. Western has identified over 10,000 potential gross CBM well drilling locations in the Powder River Basin based on current criteria.

Western averaged 423 MMcfd of CBM gathering volumes, including third-party gas, during the third quarter of 2003. This represents a seven percent increase compared to the same period in 2002. Of that volume, approximately 111 MMcfd was transported through the Company’s MIGC pipeline. The Company remains the largest gatherer and transporter of CBM in the Powder River Basin.

Greater Green River Basin. Production sold from the Pinedale Anticline, Jonah Field and Sand Wash Basin development areas in southwest Wyoming and northwest Colorado increased 41 percent to 2.1 Bcfe net in the third quarter of 2003 and averaged 23 MMcfed. The Company has participated in 48 wells drilled or drilling to date in 2003. Western plans to participate in a total of approximately 65 wells in 2003.

In the third quarter of 2003, the Wyoming Oil & Gas Commission approved two in-fill pilot programs on the Company’s leasehold to evaluate decreasing the well spacing on the Pinedale Anticline to 20 acres per well from 40 acres per well. A total of 64 wells are expected to be drilled by two of the operators in this area during the next 12 to 24 months in this program. The Company has the option to participate in this new drilling program on a well-by-well basis. If the increased density concept proves successful, the Company could participate in up to 1,000 additional well locations over the next 15 to 20 years on 20-acre spacing.

An expansion of the Rendezvous gathering system is planned for completion in December 2003. The expansion would extend the system approximately 24 miles further north on the Pinedale Anticline and increase the overall capacity of the system from 275 MMcfd to 350 MMcfd. The estimated cost of this expansion is $32.0 million gross, of which the Company’s share is approximately $16.0 million. As part of Rendezvous’ expansion process, Western is also implementing a 100 MMcf per day processing capacity upgrade at the Company’s Granger plant at a cost of $2.0 million.

Acquisition of Sand Wash Basin Properties. The Company acquired all of the capital stock of a private corporation for $12.9 million effective August 2003. The assets of this entity primarily consisted of non-operating interests in various Sand Wash properties operated by Western. The acquisition included 2.1 MMcfed of production, 10.6 Bcfed of proved reserves, approximately 10 development locations and 11,000 net acres.

Capital Expenditures. Capital expenditures for the nine months ended September 30, 2003 totaled approximately $136.0 million. Overall, capital expenditures during this period consisted of the following: (i) approximately $77.4 million related to gathering, processing, treating and pipeline assets, including $6.9 million for maintaining existing facilities; (ii) approximately $50.3 million related to exploration and production and lease acquisition activities; and (iii) approximately $8.3 million for miscellaneous items including capitalized overhead and interest.

Balance sheet. At September 30, 2003, Western had total assets of $1.4 billion, cash and cash equivalents in short-term investments of $57.9 million, total long-term debt outstanding of $341.3 million and a debt to capitalization ratio, net of cash and cash equivalents, of 34 percent.

CEO comments. Peter Dea, President and Chief Executive Officer, commented, “I am very proud of our employees once again delivering our shareholders an exceptional quarter. Our upstream and midstream operations performed exceptionally well and realized significant increases in segment operating profit from year ago levels. In our upstream operations, we expect double-digit production growth in 2003 for the sixth year in a row as we drill into our vast inventory of low-risk, low-cost unbooked reserves. Our fully integrated operations allow us to control our own destiny, maximize profitability and secure optimum prices for our natural gas and related liquids.”

Operational performance guidance for the remainder of 2003. Operational performance guidelines for 2003

were provided in a press release by the Company dated February 20, 2003 and updated May 8, 2003 and August 12, 2003. The following information represents modifications to the previous guidance.

Production. For the full year 2003, production volumes are expected to be 149 MMcfed, an increase of 12 percent compared to 2002. Production volumes are expected to average 152 MMcfed net during the fourth quarter of 2003. This includes 122 MMcfd of CBM production in the Powder River Basin and 30 MMcfed from the Greater Green River Basin. Gathering and transportation expense is expected to average $0.69 per Mcf for the fourth quarter of 2003. Lease operating expense (LOE) for all production is expected to average approximately $0.45 per Mcf for the fourth quarter of the year, which includes production overhead of $0.07 per Mcf. Other miscellaneous expenses, which include land and exploration costs, are expected to be $0.10 per Mcf. The Company expects to sell approximately 70 percent of its equity production in the Mid-Continent region as a result of its firm transportation agreements and the remaining 30 percent in the Rocky Mountain region. The Company follows the successful efforts method of accounting for oil and gas exploration and production activities.

Gathering and Processing. Gathering throughput volumes for the fourth quarter of 2003 are expected to average 1,400 MMcfd. Plant gas sales are expected to average 500 MMcfd and plant NGL sales are expected to average 1,400 MGald for the fourth quarter of 2003. Fee revenues are expected to average $0.23 per Mcf of throughput. The gross operating margin (gross revenues less product purchase expenses) for the gathering and processing business is expected to average approximately $0.39 per Mcf of gathering throughput for the fourth quarter of 2003. Gross operating margin is dependent on commodity prices, and these estimates are based on an assumption of $4.50 per Mcf for natural gas and $29.00 per barrel for crude oil (NYMEX-equivalent prices.) Plant operating expenses are expected to average $0.16 per Mcf of throughput for the fourth quarter of 2003.

Marketing. Total gas sales volumes marketed (which include production, plant and third-party gas) are expected to average approximately 1.4 Bcfd for the fourth quarter of 2003. Gas marketing margins are expected to average approximately $0.02 per Mcf. Total NGL sales volumes marketed, including plant and third party volumes, are expected to average 1,700 MGald. NGL marketing margins are expected to average approximately $0.005 per gallon. These assumptions include the impact of mark-to-market accounting for the Company’s marketing activities.

Other expenses. General and administrative expense is expected to be $9.2 million, depreciation, depletion and amortization expense is expected to be $19 million and interest expense is estimated to be $6.2 million for the fourth quarter of 2003.

Earnings conference call. Western invites you to participate in its third quarter 2003 earnings conference call today at 9:30 a.m. (Mountain Time) by dialing (719) 457-2627. 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 18, 2003 by dialing (719) 457-0820 (passcode 187825). 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, 2003.

Company description. Western is an independent natural gas explorer, producer, gatherer, processor, transporter and energy marketer. The Company’s producing properties are based in Wyoming and Colorado, including the developing Powder River Basin coal bed methane play, where Western is a leading acreage holder and producer. 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, providing a broad range of services to its customers from the wellhead to the sales delivery point. 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, drilling activity and production volumes for the remainder of 2003. 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, geological risk, environmental 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.

Condensed Statement of Operations:

(Dollars in thousands except share and per share amounts)

	Quarter Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002

Revenues:
Sale of residue gas	$	556,606		$	510,764		$	1,890,435		$	1,566,551
Sale of natural gas liquids	86,009			85,214			258,568			229,888
Gathering, processing and transportation revenues	21,884			17,007			63,119			47,466
Non-cash change in fair value of derivatives	1,564			396			1,084			(2,733		)
Other, net	737			701			2,191			2,954

Total revenues	666,800			614,082			2,215,397			1,844,126

Costs and expenses:
Product purchases	566,937			529,911			1,898,375			1,602,806
Plant and transportation operating expense	21,944			20,824			66,478			59,485
Oil and gas exploration and production costs	13,029			7,553			38,830			24,084
Depreciation, depletion and amortization	17,477			18,813			53,305			54,002
Selling and administrative expense	8,972			8,061			29,487			28,639
Loss from asset sales	56			562			142			644
Earnings from equity investments	(1,780		)	(1,141		)	(5,209		)	(2,793		)
Interest expense	6,449			6,858			19,692			20,288

Total costs and expenses	633,084			591,441			2,101,100			1,787,155

Income before taxes	33,716			22,641			114,297			56,971

Provision for income taxes	12,827			9,254			42,409			21,818

Net income before cumulative effect of change in accounting principle	20,889			13,387			71,888			35,153

Cumulative effect of change in accounting principle	—			—			(6,724		)	—

Net income	20,889			13,387			65,164			35,153

Preferred stock requirements	(1,811		)	(2,130		)	(5,434		)	(6,390		)

Net income available to common stock	$	19,078		$	11,257		$	59,730		$	28,763

Weighted average shares of common stock outstanding	33,197,265			33,010,914			33,144,296			32,921,846

Earnings per share of common stock	$	.57		$	.34		$	1.80		$	.87

Weighted average shares of common stock - assuming dilution	37,345,148			33,589,743			37,270,704			33,580,658

Earnings per share of common stock - assuming dilution	$	.56	(1)	$	.34	(2)	$	1.75	(3)	$	.86	(4)

(1) Fully-diluted earnings per share for the quarter ended September 30, 2003 include, as potential common shares, the issuance of 676,185 shares from the possible exercise of stock options and 3.5 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 net income attributable to common stock. The conversion of the preferred stock has not actually occurred.

(2) Fully-diluted earnings per share for the quarter ended September 30, 2002 include, as potential common shares, the issuance of 578,829 common shares from the possible exercise of stock options.

(3) Fully-diluted earnings per share for the nine months ended September 30, 2003 include, as potential common shares, the issuance of 654,710 common shares from the possible exercise of stock options and 3.5 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 net income attributable to common stock. The conversion of the preferred stock has not actually occurred.

(4) Fully-diluted earnings per share for the nine months ended September 30, 2002 include, as potential common shares, the issuance of 658,812 common shares from the possible exercise of stock options.

Condensed Consolidated Balance Sheet:

(Dollars in thousands)

	As of September 30, 2003		As of December 31, 2002
Assets:
Current assets	$	384,301	$	370,248
Property and equipment, net	954,820		866,646
Other assets	75,485		65,250

Total assets	$	1,414,606	$	1,302,144

Liabilities and Stockholders’ Equity:
Liabilities:
Current liabilities	$	339,739	$	332,771
Long-term debt	341,333		359,933
Other liabilities	189,197		126,372

Total liabilities	870,269		819,076

Stockholders’ equity	544,337		483,068

Total liabilities and stockholders’ equity	$	1,414,606	$	1,302,144

Reconciliation of Net Income to EBITDA:

(Dollars in thousands)

	Quarter Ended September 30,				Nine Months Ended September 30,
	2003		2002		2003		2002

Net income	$	20,889	$	13,387	$	65,164	$	35,153

Add:
Cumulative effect of change in accounting principle	—		—		6,724		—
Depreciation, depletion and amortization	17,477		18,813		53,305		54,002
Interest expense	6,449		6,858		19,692		20,288

Income taxes	12,827		9,254		42,409		21,818

EBITDA	$	57,642	$	48,312	$	187,294	$	131,261

These data do not purport to reflect any measure of operations or cash flow. EBITDA is not a measure determined pursuant to generally accepted accounting principles, or GAAP, nor is it an alternative to GAAP income. The Company is presenting this information, as it is a measure of financial performance used in the Company’s credit facilities to monitor the Company’s ability to perform under these facilities.

Reconciliation of Net Income to
Cash Flow before Working Capital Adjustments:

(Dollars in thousands)

	Quarter Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
Net income	$	20,889		$	13,387		$	65,164		$	35,153
Add income items that do not affect operating cash flows:
Depreciation, depletion and amortization	17,477			18,813			53,305			54,002
Deferred income taxes	12,283			6,747			39,272			14,602
Distributions (less than) in excess of equity income, net	1,200			(734		)	1,244			(1,727		)
Loss on sale of property and equipment	56			562			142			644
Non-cash change in fair value of derivatives	(1,564		)	(396		)	(1,084		)	2,733
Foreign currency translation adjustments	170			(365		)	857			429
Cumulative effect of change in accounting principle	—			—			6,724			—
Other non-cash items	142			(119		)	426			1,992

Cash flow before working capital adjustments	$	50,653		$	37,895		$	166,050		$	107,828

Cash Flow before Working Capital Adjustments is not a measure determined pursuant to generally accepted accounting principles, or GAAP, nor is it an alternative to GAAP income. The Company is presenting this information as it is an important measure of financial performance used by equity analysts to evaluate the Company’s ability to fund future liquidity requirements.

Operating Results:

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

	Quarter Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
Production:
Average gas production – net volumes sold (MMcfed)	149			139			148			127

Average gas price ($/Mcfe) (1)	$	4.04		$	2.12		$	4.31		$	2.11
Gathering and transportation expense ($/Mcfe)	$	0.69		$	0.68		$	0.68		$	0.64
Average wellhead gas price ($/Mcfe) (2)	$	3.35		$	1.44		$	3.63		$	1.47
Production taxes ($/Mcfe)	$	0.43		$	0.19		$	0.46		$	0.19
LOE ($/Mcfe) (3)	$	0.47		$	0.40		$	0.43		$	0.43
Other expense ($/Mcfe) (4)	$	0.08		$	0.05		$	0.09		$	0.09
Effect of equity hedges	$	(4,920	)	$	7,536		$	(18,247	)	$	22,047
Segment - operating profit	$	28,239		$	18,365		$	90,154		$	48,907
Depreciation, depletion and amortization	$	7,393		$	6,356		$	23,421		$	16,470
Selling and administrative expense	$	2,749		$	2,390		$	8,936		$	7,995

Gas Gathering and Processing:
Gas throughput volumes (MMcfd)	1,369			1,198			1,333			1182
Average plant gas sales (MMcfd)	482			447			475			444
Average plant NGL sales (Mgald)	1,300			1,516			1,350			1,418
Average gas price ($/Mcf) (5)	$	4.44		$	2.18		$	4.68		$	2.24
Average NGL Price ($/Gal) (6)	$	0.53		$	0.40		$	0.54		$	0.38
Gross operating margin ($/Mcf) (7)	$	0.411		$	0.398		$	0.432		$	0.381
Plant operating expense ($/Mcf) (7)	$	0.164		$	0.166		$	0.172		$	0.164
Effect of equity hedges	$	(2,208	)	$	(1,139	)	$	(10,940	)	$	(2,843	)
Income from equity investments	$	1,780		$	1,141		$	5,209		$	2,793
Segment - operating profit	$	30,717		$	25,582		$	88,920		$	69,811
Depreciation, depletion and amortization	$	7,485		$	10,353		$	22,603		$	31,303
Selling and administrative expense	$	4,016		$	3,496		$	13,060		$	12,604

Gas Transportation:
Gas transportation volumes (MMcfd)	155			181			165			188
Transportation and sales revenue	$	5,397		$	5,962		$	16,633		$	18,915
Operating and product purchase expense	$	3,166		$	1,760		$	7,395		$	7,209
Segment - operating profit	$	2,231		$	4,202		$	9,238		$	11,706
Depreciation, depletion and amortization	$	413		$	412		$	1,275		$	1,272
Selling and administrative expense	$	485		$	678		$	1,882		$	2,368

Marketing:
Average gas sales (MMcfd)	1,285			2,001			1,374			2,098
Average NGL sales (MGald)	1,639			2,219			1,640			2,094
Average gas price ($/Mcf)	$	4.70		$	2.77		$	5.03		$	2.73
Average NGL price ($/Gal)	$	0.57		$	0.42		$	0.58		$	0.40
Average gas sales margin ($/Mcf)	$	0.026		$	0.040		$	0.064		$	0.045
Average NGL sales margin ($/Gal)	$	0.011		$	0.009		$	0.009		$	0.008
Segment - operating profit	$	4,639		$	9,138		$	28,231		$	30,724
Depreciation, depletion and amortization	$	35		$	41		$	106		$	120
Selling and administrative expense	$	1,734		$	1,510		$	5,650		$	5,714

(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. As reconciled below, gross operating margin is gross revenues less product purchases and joint interest and excludes effect of hedging.

Reconciliation of Gas Gathering and Processing

Segment-Operating Profit to Gross Operating Margin:

(Dollars in thousands)

	Quarter Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002

Segment – operating profit	$	30,717		$	25,582		$	88,920		$	69,811

Subtract:
Income from equity investments	1,780			1,141			5,209			2,793
Effect of equity hedges	(2,208		)	(1,139		)	(10,940		)	(2,843		)

Add:
Plant operating expense	20,609			18,246			62,472			53,043

Gross operating margin	$	51,754		$	43,826		$	157,123		$	122,905

Table A — Q4 2003 Equity Gas and NGL Hedges

Product	Quantity and Settle Price	Hedge of Basis Differential
Natural Gas	50,000 MMbtu per day with an average price of $3.94 per MMbtu. 20,000 MMbtu per day with a minimum price of $3.50 per MMbtu and an average maximum price of $4.43 per MMbtu.	Mid-Continent – 20,000 MMbtu per day with an average basis price of ($0.15) per MMbtu. Permian – 5,000 MMbtu per day with an average basis price of ($0.13) per MMbtu. Rocky Mountain – 45,000 MMbtu per day with an average basis price of ($0.78) per MMbtu.

Crude, Condensate, Natural Gasoline	55,000 Barrels per month at an average price of $24.97 per barrel.	Not Applicable

Butanes	50,000 Barrels per month. Floor at $24.00 per barrel. (Crude oil used as surrogate for butanes.)	Not Applicable

Propane	100,000 Barrels per month. Average minimum and maximum price of $0.37 per gallon and $0.50 per gallon, respectively.	Not Applicable

Ethane	75,000 Barrels per month. Average minimum and maximum price of $0.25 per gallon and $0.37 per gallon, respectively.	Not Applicable

Table B – 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 and a maximum price ranging from $6.50 to $9.45 (average of $7.81 per MMBtu.)	Mid-Continent – 55,000 MMBtu per day with an average basis price of ($0.266). Permian – 5,000 MMBtu per day with an average basis price of ($0.345) per MMbtu. Rocky Mountain – 10,000 MMBtu per day with an average basis price of ($0.745) 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

Butanes	50,000 Barrels per month. Floor at $22.00 per barrel. (Crude oil used as surrogate for butanes.)	Not Applicable

Propane	90,000 Barrels per month with minimum and maximum price of $0.425 per gallon and $0.56 per gallon, respectively.	Not Applicable

Ethane	50,000 Barrels per month. Floor at $0.305 per gallon.	Not Applicable

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

Delaware	1-10389	84-1127613
(State of Other Jurisdiction of Incorporation)	(Commission File Number)	(IRS 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)


(Former Name or Former Address, if Changed Since Last Report)

			WESTERN GAS RESOURCES, INC.
			(Registrant)


Date:	November 11, 2003	By:		/s/ William J. Krysiak
				Name: William J. Krysiak
				Title: Executive Vice President and Chief Financial Officer

Exhibit Number		Description

99.1		Press release issued on November 11, 2003, announcing third quarter 2003 results for Western Gas Resources, Inc.

Item 7. Financial Statements and Exhibits

Item 12. Results of Operations and Financial Condition

Table A — Q4 2003 Equity Gas and NGL Hedges

Product

Quantity and Settle Price

Hedge of Basis Differential

Product

Quantity and Settle Price

Hedge of Basis Differential