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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) February 28, 2002
(February 28, 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. ("Western" or the "Company") today provided projections related to its expected operational performance in 2002.

        These Company estimates have been prepared based on current expectations for gas and NGL volumes, commodity pricing differentials, expenses, debt and other items resulting from the Company's planned 2002 capital budget. These projections are forward-looking and subject to various factors, including but not limited to those factors outlined in this release. These estimates do not include possible acquisitions or divestitures or other unforeseen events that may occur after this release.

Modeling Assumptions Relating to the Company's Upstream Operations:

        Production.    Natural gas production for Powder River Basin coal bed methane ("CBM") is expected to average approximately 125 MMcf per day net (320 MMcf per day gross) in 2002. These production increases are expected to occur primarily in the last nine months of the year. Natural gas production volumes from activities in the Greater Green River Basin are expected to average approximately 15 MMcf per day net in 2002.

        The Company's gas production is sold into various markets including the Rocky Mountain and Mid-Continent areas. Based on the Company's transportation contracts and derivative contracts for locational differences (basis), the Company expects to realize approximately $0.36 less than the Henry Hub NYMEX price for its production. The sales price is further reduced by approximately 14 percent for fuel and shrink. In addition, in order to deliver its gas from the wellhead to these markets, the Company pays gathering, compression and transportation expenses of approximately $0.65 per Mcf. These realizations do not consider the effect of hedging positions currently in place for 2002, which are detailed in Table A below.

        Additional costs to be deducted from the wellhead price are production taxes and lease operating expenses (LOE). Production taxes are expected to average approximately 13 percent of wellhead prices. LOE expenses, which include production overhead and other expenses, are expected to be approximately $0.33 per Mcf.

Modeling Assumptions Relating to the Company's Midstream Operations:

        Gathering, Processing and Treating.    Gas throughput volumes at the Company's facilities are expected to average approximately 1.25 Bcf per day. Natural gas sales volumes are expected to average approximately 485 MMcf per day. Gas price realizations are estimated to be approximately $0.40 below the NYMEX Henry Hub Index. NGL sales volumes are expected to be approximately 1,400 Mgal per day. Composite NGL price realizations have historically been about 70 to 75 percent of NYMEX crude oil prices adjusted by approximately $0.04 per gallon for the cost of transportation and fractionation. However, the crude oil to NGL relationship can vary dramatically for short periods based on various market factors. These realizations do not consider the effect of hedging positions currently in place for 2002, which are detailed in Table A below.

        The revenues from the Company's gathering, processing and treating facilities are derived under percent of proceeds, keep-whole and fee-based contracts. The gross operating margin for services under these types of contracts is expected to average approximately $0.34 per Mcf of facility throughput. Gross operating margin (gross revenues less product purchase expenses) is dependent on commodity prices, and these estimates are based on an assumption of $2.50 per Mcf for natural gas and $20.00 per barrel for crude oil (NYMEX-equivalent prices). Of the average gross operating margin, approximately $0.17 per Mcf is comprised of fee revenues and is not subject to changes in commodity prices.

        Plant operating expenses are projected to be approximately $0.15 per Mcf of throughput.

        Transportation.    Transportation volumes and margins are projected to approximate 2001 levels.

        Marketing.    Marketed natural gas volumes (which include plant and third-party gas) are expected to range from 1.6 to 1.8 Bcf per day. Gas marketing margins are projected to be approximately $0.02 per Mcf. Volatility of commodity prices and changes in locational differences (basis) between market areas could affect the gas marketing margin either positively or negatively. Marketed NGL volumes, including plant and third-party NGLs, are expected to range from 2,400 to 2,500 Mgal per day. NGL marketing margins and fees are projected to be approximately $0.003 per gallon. These assumptions include the impact of mark-to-market accounting for the Company's marketing activities.

Other Modeling Assumptions:

        Other, net Revenues.    Other, net revenues are projected to be approximately $6 million for 2002. Among other items, these revenues include revenue from net equity interests in joint ventures, the largest of which are Fort Union Gas Gathering, L.L.C. and Rendezvous Gas Services, L.L.C. Also included in Other, net Revenues are miscellaneous income items such as corporate interest income.

        Other Expenses.    General and administrative expenses are projected to be approximately $32 million for 2002. Depreciation, depletion and amortization expense is expected to approximate $73 million, and interest expense is projected to be approximately $26 million for 2002.

        Income Tax.    The corporate income tax rate is projected to be 36.5 percent. Approximately 75 to 80 percent of current year income taxes are expected to be deferred.

        Common shares outstanding and preferred dividends.    As of December 31, 2001, there were 32,689,009 common shares outstanding. Preferred dividends, assuming preferred shares outstanding at December 31, 2001 remain outstanding for all of 2002, would be $8.5 million in 2002.

        Product Prices.    Prices for natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors that are beyond the Company's control. To an extent the Company can manage this price risk through hedges of its equity production and as a result, from time to time, the Company enters into hedges. The following table outlines the Company's hedge positions currently outstanding. For 2002, Western has hedged approximately 58 percent of its projected equity natural gas volumes and approximately 59 percent of its estimated equity volumes of crude, condensate and NGLs. The prices reflected in the table are NYMEX equivalents and do not include the cost of the hedges, which approximate $3.0 million. The Company cannot predict the price that it will receive for its un-hedged products or for products beyond the term of the hedges.

Table A—Outstanding Equity Hedges for 2002

	1st Half of 2002	2nd Half of 2002
Natural gas	80,000 MMbtu per day with an average minimum and maximum price of $3.81 and $5.87 per MMbtu, respectively.
Crude, Condensate, Natural Gasoline and Butanes	75,000 Barrels per month Fixed price of $20.20 per barrel	75,000 Barrels per month Fixed price of $20.20 per Barrel with right to participate in price increases above $22.50 per barrel
	55,000 Barrels per month Fixed price of $21.15 per barrel	55,000 Barrels per month Floor at $20.00 per barrel
Propane	75,000 Barrels per month Fixed price of $0.32 per gallon	120,000 Barrels per month Floor at $0.32 per gallon
Ethane	50,000 Barrels per month Fixed price of $0.21 per gallon	50,000 Barrels per month Floor at $0.21 per gallon
	20,000 Barrels per month Sold at $0.21 per gallon	20,000 Barrels per month Sold at $0.21 per gallon with right to participate in price increases above $0.25 per gallon

        Updates.    This document will be maintained on Western's web site and is included in a Form 8-K filed with the SEC and the NYSE on February 28, 2002. Although the Company is not undertaking any duty or requirement to update the information contained in this report, if the Company decides to provide to any third party updated information that the Company believes may be material, the Company first will include that information in a Form 8-K filed with the SEC and the NYSE. That information will then be posted on Western's web site. Revisions that may be material could include the addition of information for a new financial reporting period or changes of five percent or more in the Company's production quantities, earnings or cash flow estimates, exclusive of commodity price changes. Minor revisions or updates to this information that the Company does not believe are material may be made directly to the document maintained on the web site without announcement.

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: February 28, 2002	By:	/s/  WILLIAM J. KRYSIAK William J. Krysiak Vice President—Finance (Principal Financial and Accounting Officer)

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ITEM 9. REGULATION FD DISCLOSURE

SIGNATURES