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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 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 13, 2002
	(August 13, 2002)

WESTERN GAS RESOURCES, INC.
(Exact name of registrant as specified in its charter)

Delaware	1-10389	84-1127613
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)
12200 N. Pecos Street	Denver, Colorado	80234-3439
(Address of principal executive offices)		(Zip Code)

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

No Changes
(Former name or former address, if changed since last report).

ITEM 9. REGULATION FD DISCLOSURE

        The following information is furnished pursuant to Regulation FD, Rules 100-103:

        Western Gas Resources, Inc. (NYSE:WGR) today announced that, for the quarter ended June 30, 2002, it had net income of $13.8 million or earnings of $0.34 per share of common stock on a fully-diluted basis. This compares to net income of $29.5 million for the same period in 2001 or earnings of $0.77 per share of common stock on a fully-diluted basis. Earnings per share for both periods are after giving effect to preferred stock dividends.

        For the second quarter of 2002, EBITDA (earnings before interest, taxes, depreciation and amortization) was $45.7 million and cash flow from operations (net cash provided by operating activities before adjustments for working capital) was $29.2 million. Revenues totaled $614.9 million.

        For the six months ended June 30, 2002, net income was $21.8 million or earnings of $0.52 per share of common stock on a fully-diluted basis. This compares to net income of $70.0 million or earnings of $1.85 per share of common stock on a fully-diluted basis for the same period in 2001. Excluding an asset sale in 2001, the Company had net income from recurring operations for the six months ended June 30, 2001 of $63.9 million or earnings of $1.69 per share of common stock on a fully-diluted basis. Earnings per share for both periods are after giving effect to preferred stock dividends.

        For the six months ended June 30, 2002, EBITDA (earnings before interest, taxes, depreciation and amortization), was $82.9 million and cash flow from operations (net cash provided by operating activities before adjustments for working capital) was $69.9 million. Revenues were $1.2 billion.

        Overall, the Company benefited from its hedge positions for natural gas. These equity-hedging positions increased operating income by $3.0 million in the second quarter of 2002 and by $12.3 million in the six months ended June 30, 2002. This compares favorably to a reduction of operating income by $1.7 million in the second quarter of 2001 and to a reduction of operating income by $16.0 million in the six months ended June 30, 2001 resulting from hedge positions in that year.

        Volumes and prices.    Natural gas production in the second quarter of 2002 increased sharply compared to the same period a year ago and total gas sales volumes increased slightly. The volume increases, however, were more than offset by significant reductions in the prices received for natural gas and natural gas liquids from a year ago.

        Natural gas equity production in the second quarter of 2002 increased 25 percent compared to the same period in 2001, averaging 121 million cubic feet equivalent per day (MMcfed). All of the Company's production growth was achieved organically through the drill bit in the Powder River Basin coal bed methane play and the Greater Green River Basin.

        Total gas sales volumes, including equity gas production, gas produced at the Company's plants and gas purchased from third parties for resale, increased one percent to an average of 1.9 billion cubic feet per day (Bcfd) in the second quarter of 2002 compared to the same period in 2001.

        Natural gas liquid (NGL) sales volumes averaged 2.1 million gallons per day (MMGald) in the second quarter of 2002. This represents a decrease of 10 percent as compared to 2001, which was largely the result of the Company's reduced emphasis on the trading of third-party NGLs.

        Average gas prices decreased 32 percent to $3.07 per Mcf compared to $4.53 per Mcf for the same period in 2001. Average NGL prices decreased 23 percent to $0.41 per gallon compared to $0.53 per gallon in the same period in 2001.

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

        Exploration and production realized operating income (EBITDA before general and administrative expenses) of $9.0 million for the second quarter of 2002 compared to $16.9 million for the same period in 2001. This decrease was due to substantially lower gas prices realized. The price decreases were partially offset by significant volume growth from the Powder River Basin CBM development.

        Gathering and processing realized operating income of $26.9 million for the second quarter of 2002 compared to $36.0 million for the second quarter of 2001. This decrease was again primarily due to the reduction in product prices.

        Gas transportation realized operating income of $4.1 million for the second quarter of 2002 compared to $4.5 million for the second quarter of 2001.

        Marketing realized operating income of $14.2 million for the second quarter of 2002 compared to operating income of $18.2 million for the same period in 2001. The results for the marketing business for both periods benefited from transactions utilizing the Company's contracts for storage and for firm transportation capacity where regional differentials widened.

        Powder River Basin CBM.    Net CBM production sold increased 31 percent to 112 MMcfd in the second quarter of 2002 compared to a year ago. The Company has participated in the drilling of 675 wells through July 31, 2002 and plans to participate in a total of over 900 wells in 2002.

        Big George update.    On August 4, 2002, the Company's All Night Creek development was producing 10.7 MMcfd of gas from 63 wells with an additional 27 wells dewatering and 48 wells awaiting connection. Overall, total industry production from the Big George coal has increased 300 percent over the last year to approximately 34 MMcfd. The Company expects to have wells drilled in 12 additional Big George areas by year-end.

        Greater Green River Basin.    Production sold from the Pinedale Anticline, Jonah Field and Sand Wash Basin development areas in Southwest Wyoming and Northwest Colorado averaged 8.7 MMcfed net in the second quarter of 2002. Western plans to participate in a total of approximately 31 wells in 2002.

        The first phase of the Company's 50 percent-owned Rendezvous gathering expansion into the Pinedale Anticline is completed. The second phase construction is underway with completion expected by October 2002. Volumes on the operational portion of the system have reached 125 MMcfd in July in 2002.

        Hedging positions.    The Company's hedging positions for approximately 63 percent of its equity volumes of natural gas in 2002 and 25 percent of its equity volumes of natural gas in 2003 remain unchanged. The Company's hedges for 68 percent of its NGLs in 2002 also remain unchanged.

        Balance sheet.    At June 30, 2002, Western had total assets of $1.3 billion, cash and cash equivalents in short-term investments of $27.7 million, total debt outstanding of $381.6 million and a debt to capitalization ratio, net of cash and cash equivalents, of 42 percent.

        CEO comments.    Peter Dea, President and Chief Executive Officer, commented, "In the second quarter of 2002, we continued to grow production by 31 percent from the Powder River coal bed development in the Wyodak and Big George coals. The vast majority of our 2002 natural gas sales continue to benefit from equity hedge positions and firm transportation capacity to the Mid-continent. Overall, our operating income in the gathering and processing, exploration and production and marketing businesses are all ahead of our projections through the first six months of 2002."

        Operational performance guidance for the remainder of 2002.    Operational performance guidelines for 2002 were provided in a press release by the Company dated February 28, 2002 and updated May 15, 2002. The following information represents modifications to the previous guidance.

        Production.    Production volumes are expected to average 147 MMcfed net during the second half of 2002. This includes 130 MMcfd of CBM production in the Powder River Basin and 17 MMcfed from the Greater Green River Basin. The Company anticipates selling approximately 65 to 70 percent of its production in the Mid-continent region and 30 to 35 percent in the Rocky Mountain region. This excludes the effect of equity hedges. LOE expenses for all production are expected to average approximately $0.45 per Mcf for the remainder of the year. This includes production overhead of $0.09 per Mcf and other miscellaneous expenses of $0.06 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 2002 are expected to average 1,125 MMcfd. This assumes completion of the Toca sale and the resulting elimination of associated volumes. Natural gas sales are expected to average 495 MMcfd and NGL sales volumes are expected to average 1.5 MMGald for the second half of 2002. 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 facility throughput for the remainder of 2002. Gross operating margin is dependent on commodity prices, and these estimates are based on an assumption of $3.25 per Mcf for natural gas and $25.60 per barrel for crude oil (NYMEX-equivalent prices.) Plant operating expenses are expected to average $0.17 per Mcf of throughput.

        Marketing.    Marketed natural gas volumes (which include production, plant and third-party gas) are expected to range from 1.6 to 1.7 Bcfd. Gas marketing margins are expected to range from $0.01 to $0.02 per Mcf. Marketed NGL volumes, including plant and third party volumes, are expected to range from 2.3 to 2.4 MMGald. NGL marketing margins are expected to average between $0.001 and $0.002 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 $16 to $17 million for the second half of 2002 and interest expenses are estimated to be $14 to $15 million.

        Earnings conference call.    Western invites you to participate in its second quarter 2002 earnings conference call today at 8:00 a.m. (Mountain Time) by dialing (719) 457-2600. Please dial in five to ten minutes before the start of the call. A replay of the conference call will be available after 10:00 a.m. (Mountain Time) today for one week following the call by dialing (719) 457-0820 (passcode 265685). 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 30, 2002.

        Company description.    Western is an independent natural gas 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 based primarily in Wyoming, 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. 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 2002. 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.

		Quarter Ended June 30						Six Months Ended June 30
		2002			2001			2002			2001
Financial Statistics:
($000s except share and per share amounts)
Revenues		$	614,930		$	887,024		$	1,231,696		$	2,084,300
Costs and expenses:
	Product purchases		528,289			784,550			1,072,895			1,871,150
	Plant operating expense		19,790			18,240			38,661			35,277
	Oil and gas exploration and production costs		9,142			9,098			16,531			18,703
	Depreciation, depletion and amortization		17,243			15,283			35,189			29,761
	Selling and administrative expense		11,887			7,545			20,578			16,024
	Loss (gain) from asset sales		73			—			82			(11,223)
	Interest expense		6,770			5,992			13,430			12,821
Total costs and expenses			593,194			840,708			1,197,366			1,972,513
Income before taxes			21,736			46,316			34,330			111,787
Provision for income taxes			7,970			16,863			12,564			41,744
Net income			13,766			29,453			21,766			70,043
Preferred stock requirements			2,130			2,584			4,260			5,169
Net income available to common stock			11,636			26,869			17,506			64,874
Weighted average shares of common stock outstanding			32,994,543			32,579,509			32,877,312			32,492,276
Earnings per share of common stock		$	.35		$	.82		$	.53		$	2.00
Weighted average shares of common stock—assuming dilution			33,779,869			37,073,854			33,621,877			36,965,284
Earnings per share of common stock—assuming dilution		$	.34	(1)	$	.77	(2)	$	.52	(3)	$	1.85	(4)
Cash flow from operations(5)		$	29,174		$	59,261		$	69,933		$	114,785
	EBITDA	$	45,749		$	67,591		$	82,949		$	154,369

(1)

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.

(2)

Fully-diluted earnings per share for the quarter ended June 30, 2001 include, as potential common shares, the issuance of 1,023,000 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.

(3)

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.

(4)

Fully-diluted earnings per share for the six months ended June 30, 2001 include, as potential common shares, the issuance of 1,000,000 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.

(5)

Represents net cash provided by operating activities before adjustments for working capital.

	Quarter Ended June 30				Six Months Ended June 30
	2002		2001		2002		2001
Segment Operating Statistics:
Production:
Gas Production—Net Volumes Sold (MMcfed)		121		96		121		93
Average Gas Prices ($/Mcf)(1)	$	1.69	$	2.66	$	1.48	$	3.87
Production Taxes ($/Mcf)	$	0.22	$	0.34	$	0.20	$	0.47
LOE Expense ($/Mcf)(2)	$	0.55	$	0.36	$	0.47	$	0.36
Other Expense ($/Mcf)(3)	$	0.11	$	0.06	$	0.11	$	0.11
Gas Gathering and Processing:
Gas Throughput Volumes (MMcfd)		1,137		1,186		1,152		1,149
Average Plant Gas Sales (MMcfd)		440		405		445		405
Average Plant NGL Sales (MGald)		1,490		1,565		1,370		1,480
Average Gas Prices ($/Mcf)(4)	$	2.67	$	4.10	$	2.37	$	5.35
Average NGL Prices ($/Gal)(5)	$	0.37	$	0.48	$	0.36	$	0.54
Fee Revenues ($/Mcf)(6)	$	0.21	$	0.17	$	0.20	$	0.19
Gross Operating Margin ($/Mcf)(6)	$	0.43	$	0.49	$	0.38	$	0.54
Plant Operating Expenses ($/Mcf)(6)	$	0.17	$	0.16	$	0.16	$	0.15
Gas Transportation:
Gas Transportation Volumes (MMcfd)		188		194		192		195
Marketing:
Average Gas Sales (MMcfd)		1,855		1,835		2,150		1,755
Average NGL Sales (MGald)		2,125		2,370		2,035		2,300
Average Gas Prices ($/Mcf)	$	3.07	$	4.53	$	2.73	$	5.68
Average NGL Prices ($/Gal)	$	0.41	$	0.53	$	0.39	$	0.58
Average Gas Sales Margin ($/Mcf)	$	0.08	$	0.10	$	0.05	$	0.10
Average NGL Sales Margin ($/Gal)	$	0.006	$	0.007	$	0.008	$	0.008

(1)

Net of fuel, shrink, gathering and transportation.

(2)

Includes production overhead.

(3)

Includes delay rentals, impairment and unsuccessful well expense.

(4)

Represents average sales price adjusted for appropriate locational differential.

(5)

Represents average sales price adjusted for appropriate transportation and fractionation charges.

(6)

Per Mcf of throughput. Gross operating margin is gross revenues less product purchases and joint interest.

SIGNATURES

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

	WESTERN GAS RESOURCES, INC. (Registrant)
Date: August 13, 2002	By:	/s/  WILLIAM J. KRYSIAK William J. Krysiak Chief Financial Officer (Principal Financial and Accounting Officer)

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ITEM 9. REGULATION FD DISCLOSURE

SIGNATURES