8-K

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported): August 12, 2003

WESTERN GAS RESOURCES, INC.
(Exact Name of Registrant as Specified in Charter)

Delaware	1-10389	84-1127613
(State of Other Jurisdiction	(Commission	(IRS Employer
of Incorporation)	File Number)	Identification No.)
1099 18th Street, Suite 1200, Denver, Colorado		80202
(Address of Principal Executive Offices)		(Zip Code)
(303) 452-5603 (Registrant's telephone number, including area code)

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

Item 7. Financial Statements and Exhibits

(c)

A list of exhibits filed herewith is contained on the Exhibit Index which immediately precedes such exhibits and is incorporated herein by reference.

Item 9. Regulation FD Disclosure

The following information is furnished pursuant to Item 9 "Regulation FD Disclosure" and Item 12 "Results of Operations and Financial Condition."

On August 12, 2003, Western Gas Holdings, Inc. issued a press release announcing its second quarter 2003 financial results. The press release is furnished as Exhibit 99.1 to this Form 8-K.

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 hereunto duly authorized.

	WESTERN GAS RESOURCES, INC. (Registrant)
Date: August 12, 2003	By:	/s/  WILLIAM J. KRYSIAK Name:  William J. Krysiak Title:    Executive Vice President and Chief Financial Officer

EXHIBIT INDEX

Exhibit Number	Description
99.1	Press release issued on August 12, 2003, announcing second quarter 2003 results for Western Gas Resources, Inc.

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Item 7. Financial Statements and Exhibits
Item 9. Regulation FD Disclosure

SIGNATURES
EXHIBIT INDEX

EX-99.1

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EXHIBIT 99.1

WESTERN GAS RESOURCES, INC.
ANNOUNCES SECOND QUARTER 2003 RESULTS

August 12, 2003. Western Gas Resources, Inc. (NYSE:WGR) today announced that, for the quarter ended June 30, 2003, it had net income of $20.9 million or earnings of $0.56 per share of common stock. This compares to net income of $13.8 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 June 30, 2003 totaled $660.5 million.

For the six months ended June 30, 2003, net income was $44.3 million or earnings of $1.19 per share of common stock. This compares to net income of $21.8 million or earnings of $0.52 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 six months ended June 30, 2003 were $1.55 billion. Net income for the six months ended June 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.

For the second quarter of 2003, EBITDA (earnings before interest, taxes, depreciation and amortization) was $56.9 million and cash flow before working capital adjustments was $43.4 million.

For the six months ended June 30, 2003, EBITDA (earnings before interest, taxes, depreciation and amortization and the cumulative effect of a change in accounting principle), was $129.7 million and cash flow before working capital adjustments was $115.4 million.

Volumes and prices. Natural gas equity production in the second quarter of 2003 increased sharply compared to the same period a year ago and total gas sales volumes marketed decreased. Prices received for natural gas and natural gas liquids ("NGLs") increased significantly from a year ago.

Natural gas equity production in the second quarter of 2003 increased 24 percent compared to the same period in 2002, averaging 149 million cubic feet equivalent per day ("MMcfed"). All of 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 volumes marketed, including equity gas production, gas produced at the Company's plants and gas purchased from third parties for resale, were 1.2 billion cubic feet per day ("Bcfd") in the second quarter of 2003 compared to 1.9 Bcfd for the same period in 2002. The decrease is primarily from reduced sales of natural gas purchased from third parties for resale. Average gas prices increased 61 percent to $4.86 per Mcf in the second quarter of 2003 compared to $3.02 per Mcf for the same period in 2002.

Total NGLs sales volumes marketed averaged 1.6 million gallons per day ("MMGald") in the second quarter of 2003 compared to 2.1 MMGald in the same period of 2002. The decrease in sales volumes was largely the result of the Company's sale of its Toca facility in September 2002. Average NGL prices increased 32 percent to $0.54 per gallon in the second quarter of 2003 compared to $0.41 per gallon in the same period in 2002.

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

Exploration and production realized segment-operating profit (EBITDA before general and administrative expenses) of $29.4 million for the second quarter of 2003 compared to $15.9 million for the same period in 2002. This increase was primarily due to substantially higher natural gas prices and significant production volume growth from the Powder River CBM and Pinedale Anticline developments.

Gathering and processing realized segment-operating profit of $27.9 million for the second quarter of 2003 compared to $25.4 million for the second quarter of 2002. This increase is primarily due to higher commodity prices and increased gathering volumes from equity and third-party CBM production and the acquisition of several gathering systems in February 2003.

Gas transportation realized segment-operating profit of $2.9 million for the second quarter of 2003 compared to $3.2 million for the second quarter of 2002. The transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin.

Marketing realized segment-operating profit of $9.2 million for the second quarter of 2003 compared to $13.4 million for the same period in 2002. The results for the marketing business benefited significantly from transactions utilizing the Company's firm transportation capacity and storage positions. The Company's firm transportation allows it to purchase gas in the Rocky Mountain region for resale in the Mid-Continent markets. Operating profit decreased compared to the 2002 period as 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 $6.9 million in the second quarter of 2003 and by $22.3 million in the six months ended June 30, 2003. This compares to an increase in operating profit of $3.3 million in the second quarter of 2002 and to an increase in operating profit of $12.8 million in the six months ended June 30, 2002 resulting from hedge positions in that year. The Company has similar hedging positions in place for the remainder of 2003. The Company has begun hedging its estimated 2004 equity production including 30,000 MMbtus in a costless collar structure with a minimum price of $4.00 per MMbtu and a maximum price of $8.88 per MMbtu on a NYMEX-equivalent basis. These hedging positions are outlined in Table A.

Powder River Basin CBM. Net CBM production sold increased nine percent to 11.1 Bcf in the second quarter of 2003 as compared to the same period one year ago and averaged 122 MMcfd. The Company has participated in the drilling of 273 CBM wells through July 2003 and plans to participate in a total of 600 to 650 CBM wells in 2003. Completion of the Company's 2003 drilling program will be subject to obtaining the necessary drilling and water discharge permits in a timely fashion.

As of July 2003, gross CBM production from wells in which the Company has an interest in the Big George coal was approximately 32 MMcfd of gas from one development and two pilot areas. Overall, total industry production from the Big George coal has increased approximately 175 percent in the last 12 months to approximately 99 MMcfd in May 2003. The Company expects to participate in 255 Big George wells in 2003 as part of its overall drilling program.

The Bureau of Land Management's ("BLM") Buffalo, Wyoming field office issued the final Record of Decision ("ROD") for the Powder River Basin Oil and Gas Environmental Impact Statement ("EIS") on April 30, 2003. On May 12, 2003, the BLM began accepting new applications to drill CBM wells on federal acreage. To date, 46 of the 86 permits approved since the ROD will benefit the Company.

Western averaged 414 MMcfd of CBM gathering volumes, including third-party gas, during the second quarter of 2003. This represents a 15 percent increase compared to the same period in 2002. Of that volume, approximately 107 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. Production sold from the Pinedale Anticline, Jonah Field and Sand Wash Basin development areas in southwest Wyoming and northwest Colorado increased 206 percent to 2.5 Bcfe net in the second quarter of 2003 and averaged 27 MMcfed. The Company has participated in 24 wells drilled or drilling to date in 2003 with a 100 percent success rate. Western plans to participate in a total of approximately 50 wells in 2003.

A third and fourth phase expansion of the Company's 50 percent-owned Rendezvous gathering system into the Pinedale Anticline is under construction. The two phases will increase gathering capacity to 350 MMcfd and are expected to be completed by December 2003 at a net cost of $17.7 million to Western. Volumes on the operational portion of the Rendezvous system averaged 216 MMcfd in June 2003. As part of our expansion process we are implementing a 100 MMcfd processing capacity upgrade at the Company's Granger plant.

Capital Expenditures. The Company increased its budget capital expenditures for 2003 to $210.1 million. The new 2003 capital budget includes approximately $77.0 million for exploration and production and lease acquisition activities, $83.9 million for midstream activities and $37.1 million for the acquisition of gathering assets in Wyoming. Overall, capital expenditures in the Powder River Basin coal bed methane development and in southwest Wyoming operations represent 28 percent and 51 percent, respectively, of the total 2003 budget.

Balance sheet. At June 30, 2003, Western had total assets of $1.4 billion, cash and cash equivalents in short-term investments of $40.2 million, total long-term debt outstanding of $333.3 million and a debt to capitalization ratio, net of cash and cash equivalents, of 36 percent.

CEO comments. Peter Dea, President and Chief Executive Officer, commented, "Our strong performance in the second quarter continues to reflect the benefits of our integrated approach to the natural gas business. We benefited from strong prices, volume growth in our production and midstream businesses and our firm transportation positions to Mid-Continent markets. The Powder River CBM and the Pinedale Anticline developments both experienced significant volume growth from year ago periods. We are particularly encouraged by stellar results from the Big George coal as it nears 100 MMcf per day of total industry production. We feel confident that the recent release of permits from the BLM is an indication of a steady stream of permits to follow in the coming months. This will allow us to develop our dominant position in this emerging, prolific fairway and will drive future growth beginning in the second half of 2004."

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. The following information represents modifications to the previous guidance.

Production. For the full year 2003, production volumes are expected to be 145 MMcfed, an increase of eight percent compared to 2002. Production volumes are expected to average 144 MMcfed net during the second half of 2003. This includes 119 MMcfd of CBM production in the Powder River Basin and 25 MMcfed from the Greater Green River Basin. Gathering and transportation expense is expected to average $0.65 per Mcf for the second half of 2003. Lease operating expense (LOE) for all production is expected to average approximately $0.49 per Mcf for the remainder of the year, which includes production overhead of $0.09 per Mcf. Other miscellaneous expenses, which include land and exploration costs, are expected to be $0.10 per Mcf. The Company follows the successful efforts method of accounting for oil and gas exploration and production activities.

Gathering and Processing. Throughput volumes for the second half of 2003 are expected to average 1,379 MMcfd. Plant gas sales are expected to average 594 MMcfd and plant NGL sales are expected to average 1,165 MGald for the second half of 2003. Fee revenues are expected to average $0.22 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 $0.41 per Mcf of facility throughput for the remainder of 2003. Gross operating margin is dependent on commodity prices, and these estimates are based on an assumption of $5.35 per Mcf for natural gas and $29.10 per barrel for crude oil (NYMEX-equivalent prices.) Plant operating expenses are expected to average $0.17 per Mcf of throughput for the second half of 2003.

Marketing. Total gas sales volumes marketed (which include production, plant and third-party gas) are expected to range from 1.7 to 1.8 Bcfd for the last six months of 2003. Gas marketing margins are expected to average approximately $0.015 per Mcf. Total NGL sales volumes marketed, including plant and third party volumes, are expected to average 1,750 MGald. NGL marketing margins are expected to average approximately $0.006 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 $18.5 million, depreciation, depletion and amortization expenses are expected to be $41.3 million and interest expenses are estimated to be $12.9 million for the second half of 2003.

Earnings conference call. Western invites you to participate in its second quarter 2003 earnings conference call today at 9:30 a.m. (Mountain Time) by dialing (719) 457-2625. Please dial in five to ten minutes before the start of the call. A replay of the conference call will be available through midnight, August 18, 2003 by dialing (719) 457-0820 (passcode 523469). 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 August 31, 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 prices, government regulation or action, litigation, 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 June 30						Six Months Ended June 30
		2003			2002			2003			2002
Revenues:
	Sale of residue gas	$	554,090		$	510,198		$	1,333,829		$	1,055,787
	Sale of natural gas liquids		80,510			79,866			172,559			144,674
	Gathering, processing and transportation revenues		21,458			15,028			41,235			30,459
	Non-cash change in fair value of derivatives		3,683			7,866			(480	)		(3,129	)
	Other, net		750			1,170			1,454			2,253
	Total revenues		660,491			614,128			1,548,597			1,230,044
Costs and expenses:
	Product purchases		559,836			528,289			1,331,438			1,072,895
	Plant and transportation operating expense		22,612			19,790			44,534			38,661
	Oil and gas exploration and production costs		13,290			9,142			25,801			16,531
	Depreciation, depletion and amortization		17,685			17,243			35,828			35,189
	Selling and administrative expense		9,923			11,887			20,515			20,578
	(Gain) loss from asset sales		(195	)		73			86			82
	Earnings from equity investments		(1,867	)		(802	)		(3,429	)		(1,652	)
	Interest expense		6,429			6,770			13,243			13,430
Total costs and expenses			627,713			592,392			1,468,016			1,195,714
Income before taxes			32,778			21,736			80,581			34,330
Provision for income taxes			11,878			7,970			29,582			12,564
Net income before cumulative effect of change in accounting principle			20,900			13,766			50,999			21,766
Cumulative effect of change in accounting principle			—			—			(6,724	)		—
Net income			20,900			13,766			44,275			21,766
Preferred stock requirements			(1,811	)		(2,130	)		(3,623	)		(4,260	)
Net income available to common stock		$	19,089		$	11,636		$	40,652		$	17,506
Weighted average shares of common stock outstanding			33,147,943			32,994,543			33,117,812			32,877,312
Earnings per share of common stock		$	.58		$	.35		$	1.23		$	.53
Weighted average shares of common stock—assuming dilution			37,263,359			33,779,869			37,208,441			33,621,877
Earnings per share of common stock—assuming dilution		$	.56(1	)	$	.34(2	)	$	1.19(3	)	$	.52(4	)

(1)

Fully-diluted earnings per share for the quarter ended June 30, 2003 include, as potential common shares, the issuance of 643,718 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 $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 June 30, 2002 include, as potential common shares, the issuance of 785,326 common shares from the possible exercise of stock options.

(3)

Fully-diluted earnings per share for the six months ended June 30, 2003 include, as potential common shares, the issuance of 618,931 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 $3.6 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 six months ended June 30, 2002 include, as potential common shares, the issuance of 744,565 common shares from the possible exercise of stock options.

Condensed Consolidated Balance Sheet:
(Dollars in thousands)

		As of June 30, 2003		As of December 31, 2002
Assets:
	Current assets	$	413,048	$	370,248
	Property and equipment, net		917,471		866,646
	Other assets		67,659		65,250
Total assets		$	1,398,178	$	1,302,144
Liabilities and Stockholders' Equity:
Liabilities:
	Current liabilities	$	381,818	$	332,771
	Long-term debt		333,333		359,933
	Other liabilities		165,730		126,372
Total liabilities			880,881		819,076
Stockholders' equity			517,297		483,068
Total liabilities and stockholders' equity		$	1,398,178	$	1,302,144

Reconciliation of Net Income to EBITDA:
(Dollars in thousands)

		Quarter Ended June 30				Six Months Ended June 30
		2003		2002		2003		2002
Net income		$	20,900	$	13,766	$	44,275	$	21,766
Add:
	Cumulative effect of change in accounting principle		—		—		6,724		—
	Depreciation, depletion and amortization		17,685		17,243		35,828		35,189
	Interest Expense		6,429		6,770		13,243		13,430
	Income taxes		11,878		7,970		29,582		12,564
	EBITDA	$	56,892	$	45,749	$	129,652	$	82,949

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 June 30						Six Months Ended June 30
		2003			2002			2003		2002
Net income		$	20,900		$	13,766		$	44,275	$	21,766
Add income items that do not affect operating cash flows:
	Depreciation, depletion and amortization		17,685			17,243			35,828		35,189
	Deferred income taxes		9,806			4,019			26,989		7,855
	Distributions less than equity income, net		(1,387	)		(394	)		44		(993	)
	(Gain)loss on sale of property and equipment		(195	)		73			86		82
	Non-cash change in fair value of derivatives		(3,683	)		(7,866	)		480		3,129
	Foreign currency translation adjustments		105			611			687		794
	Cumulative effect of change in accounting principle		—			—			6,724		—
	Other non-cash items		142			1,711			284		1,788
Cash flow before working capital
Adjustments		$	43,373		$	29,163		$	115,397	$	69,610

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 June 30						Six Months Ended June 30
	2003			2002			2003			2002
Production:
Average gas production—net volumes sold (MMcfed)		149			121			148			121
Average gas price ($/Mcfe) (1)	$	4.12		$	2.38		$	4.49		$	2.11
Gathering and transportation expense ($/Mcfe)	$	0.65		$	0.68		$	0.68		$	0.62
Average wellhead gas price ($/Mcfe) (2)	$	3.47		$	1.70		$	3.81		$	1.49
Production taxes ($/Mcfe)	$	0.42		$	0.22		$	0.48		$	0.20
LOE ($/Mcfe) (3)	$	0.46		$	0.51		$	0.41		$	0.45
Other expense ($/Mcfe) (4)	$	0.12		$	0.13		$	0.09		$	0.12
Effect of equity hedges	$	(4,439	)	$	6,090		$	(13,328	)	$	14,511
Segment—operating profit	$	29,443		$	15,947		$	62,719		$	30,798
Depreciation, depletion and amortization	$	8,498		$	4,784		$	16,558		$	10,105
Selling and administrative expense	$	2,937		$	3,333		$	6,178		$	5,597
Gas Gathering and Processing:
Gas throughput volumes (MMcfd)		1,332			1,166			1,315			1,174
Average plant gas sales (MMcfd)		468			442			472			443
Average plant NGL sales (MGald)		1,358			1,489			1,376			1,368
Average gas price ($/Mcf) (5)	$	4.51		$	2.57		$	4.81		$	2.27
Average NGL Price ($/Gal) (6)	$	0.50		$	0.38		$	0.55		$	0.36
Fee revenue ($/Mcf) (7)	$	0.24		$	0.20		$	0.24		$	0.20
Gross operating margin ($/Mcf) (7)	$	0.41		$	0.42		$	0.45		$	0.37
Plant operating expense ($/Mcf) (7)	$	0.18		$	0.16		$	0.17		$	0.16
Effect of equity hedges	$	(2,420	)	$	(2,760	)	$	(9,004	)	$	(1,704	)
Income from equity investments	$	1,867		$	802		$	3,429		$	1,652
Segment—operating profit	$	27,853		$	25,448		$	59,690		$	44,230
Depreciation, depletion and amortization	$	6,693		$	10,363		$	14,588		$	20,959
Selling and administrative expense	$	4,296		$	5,254		$	9,031		$	9,095
Gas Transportation:
Gas transportation volumes (MMcfd)		157			188			175			192
Transportation and sales revenue	$	5,183		$	6,041		$	11,194		$	12,955
Operating and product purchase expense	$	2,300		$	2,834		$	4,265		$	5,449
Segment—operating profit	$	2,883		$	3,207		$	6,929		$	7,506
Depreciation, depletion and amortization	$	430		$	425		$	863		$	860
Selling and administrative expense	$	834		$	975		$	1,395		$	1,687
Marketing:
Average gas sales (MMcfd)		1,247			1,856			1,419			2,148
Average NGL sales (MGald)		1,626			2,118			1,640			2,031
Average gas price ($/Mcf)	$	4.86		$	3.02		$	5.18		$	2.71
Average NGL price ($/Gal)	$	0.54		$	0.41		$	0.58		$	0.39
Average gas sales margin ($/Mcf)	$	0.065		$	0.078		$	0.082		$	0.048
Average NGL sales margin ($/Gal)	$	0.012		$	0.006		$	0.010		$	0.008
Segment—operating profit	$	9,213		$	13,434		$	24,244		$	21,405
Depreciation, depletion and amortization	$	36		$	40		$	71		$	80
Selling and administrative expense	$	1,856		$	2,425		$	3,910		$	4,198

(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—2H -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.	Mid-Continent—20,000 MMbtu per day with an average basis price of ($0.15) 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.	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 A—2004 Equity Gas and NGL Hedges

Product	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	30,000 MMbtu per day with a minimum price of $4.00 per MMbtu and an average maximum price of $8.88 per MMbtu.	Mid-Continent—25,000 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.
Crude, Condensate, Natural Gasoline	25,000 Barrels per month with a minimum price of $22.00 per barrel and a maximum price of $30.15 per barrel.	Not Applicable
Butanes	25,000 Barrels per month. Floor at $22.00 per barrel. (Crude oil used as surrogate for butanes.)	Not Applicable

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

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EXHIBIT 99.1