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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 21, 2003 (February 20, 2003)

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

Delaware (State or other jurisdiction of incorporation)	1-10389 (Commission File Number)	84-1127613 (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") (NYSE:WGR) today provided projections related to its expected operational performance in 2003.

        These estimates have been prepared based on the Company's current expectations for natural gas and natural gas liquids (NGL) volumes, commodity pricing differentials, expenses, debt balances and other items resulting from the Company's 2003 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.    Total net natural gas production in 2003 is expected to increase to an average of approximately 146 million cubic feet of gas equivalent per day (MMcfed) or approximately 10 percent from 2002 levels with the majority of the increase to occur in the second half of the year. Natural gas production from the Powder River Basin coal bed methane ("CBM") development is expected to average approximately 126 MMcfd net in 2003. Natural gas production volumes from activities in the Greater Green River Basin are expected to average approximately 20 MMcfed net in 2003.

        In December 2002, net CBM production averaged 126 MMcfd, excluding prior period revisions for third party operated production, but declined during January 2003 to an average of 122 MMcfd. Average net production during the first two quarters is expected to be similar to December 2002. We expect net production increases over the two remaining quarters with an exit rate of 132 MMcfd. Several factors account for the recent hiatus in otherwise steep production growth, including operational and permitting delays, Hoe Creek underperformance and the timing of the EIS.

        Approximately 70 percent of the Company's gas production is sold primarily into the Mid-Continent market and the remainder is sold in the Rocky Mountain area. The Company expects to have virtually no net exposure to Rockies prices in 2003 for its equity production due to the Company's transportation contracts, equity hedges and derivative contracts for regional basis differences. The production business will realize the effect of the Company's equity natural gas hedging positions for 2003, as detailed in Table A, except those related to the Permian Basin. However, since the results of equity hedges is reported separately, gas price realizations must be adjusted for the appropriate regional price differences from the Henry Hub Index and further reduced by approximately 15 percent for fuel and shrink.

        In addition, in order to deliver its gas from the wellhead to these markets, the Company incurs gathering, compression and transportation expenses of approximately $0.65 per Mcfe. These costs must be deducted from the gas price realized to arrive at a wellhead gas price. Additional costs to be deducted from the wellhead price are production taxes, lease operating expenses (LOE) and other miscellaneous expenses. Production taxes are expected to average approximately 13 percent of wellhead prices. LOE expenses, which include production overhead, are expected to be approximately $0.46 per Mcfe. Other items, including delay rentals, impairment and unsuccessful well expense (expensed due to successful efforts accounting) are expected to average $0.08 per Mcfe.

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 1.3 Bcfd. Natural gas plant sales are expected to average approximately 560 MMcfd. Price realizations on these sales are dependent upon current basis

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differentials to the basins in which the Company operates and are generally below the NYMEX Henry Hub Index. The Company estimates that approximately 50 percent of plant gas is sold in the Rocky Mountain area and approximately 25 percent is sold in each of the Mid-Continent and Permian Basin areas. NGL plant sales are expected to be approximately 1,500 MGald. 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.

        The revenues from the Company's gathering, processing and treating facilities are derived from percent of proceeds, keep-whole and fee-based contracts. Gross operating margin (gross revenues less product purchase expenses) is dependent on commodity prices and is expected to average approximately $0.40 per Mcf of facility throughput. This estimate is based on an assumption of $4.00 per MMbtu for natural gas and $25.00 per barrel for crude oil (NYMEX-equivalent prices). Assuming higher commodity prices of $5.00 per MMbtu and $28.00 per barrel, gross operating margin would be estimated to be approximately $0.43 per Mcf of throughput. Assuming lower commodity prices of $3.00 per MMbtu and $20.00 per barrel, gross operating margin would be estimated to be approximately $0.35 per Mcf of throughput. The gross operating margins exclude the effect of equity hedges related to the gathering and processing business, which are currently in place for 2003. These hedging positions include the equity natural gas hedges related to the Permian Basin and all oil and NGL equity hedges, as detailed in Table A. Of the average gross operating margin, approximately $0.22 per Mcf is comprised of fee revenues and is not subject to changes in commodity prices.

        Plant operating expenses are projected to be approximately $0.18 to $0.19 per Mcf of throughput volumes and should be deducted from the gross operating margin to arrive at a net operating margin per Mcf of throughput volumes. The cost of gathering gas from the wellhead to the plant is included in plant operating expense rather than product purchase expense beginning in 2003.

        In addition to the above guidance information, the gathering and processing segment will realize income from its equity investments in the Fort Union Gas Gathering, L.L.C. and Rendezvous Gas Services, L.L.C. joint ventures, which should approximate $8 to $9 million for 2003. This amount will be included under income from equity investments on the income statement.

        Transportation.    Gas transportation and sales volumes are expected to be approximately 180 MMcfd and revenues are projected to be approximately $23 million for 2003. Operating income, after deducting pipeline operating expenses and product purchase expenses, is expected to be approximately $13 million.

        Marketing.    Marketed natural gas volumes (which include equity and third-party gas) are expected to be approximately 2.0 Bcfd. Gas marketing margins are projected to be approximately $0.015 to $0.02 per Mcf. Volatility of commodity prices and changes in regional price 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 be approximately 2,000 MGald. NGL marketing margins and fees are projected to be approximately $0.004 per gallon. These margin assumptions include the impact of mark-to-market accounting for the Company's marketing activities, which is reflected on the income statement under non-cash change in fair value of derivatives.

Other Modeling Assumptions:

        Other Revenues.    Miscellaneous income in the corporate segment, including corporate interest income, is expected to approximate $2.0 million in 2003. These revenues will be included in other, net on the income statement.

        Other Expenses.    General and administrative expenses are projected to be approximately $37 million for 2003. These expenses are estimated to be related to the segments as follows: 31 percent

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for exploration and production, 41 percent for gathering and processing, 8 percent for transportation and 20 percent for marketing. Depreciation, depletion and amortization expense is expected to approximate $85.4 million as follows: $28.1 million for exploration and production, $51.0 million for gathering and processing, $1.1 million for transportation, $0.2 million for marketing and $5.0 million for corporate. Interest expense is projected to be approximately $29.3 million for 2003.

        Adoption of SFAS-143—Accounting for Asset Retirement Obligations.    Income for 2003 will be reduced by a one-time entry in the first quarter for the cumulative effect of a change in accounting principle due to the adoption of SFAS No. 143—"Accounting for Asset Retirement Obligations". This accounting principle requires the accrual for estimated asset retirement obligations. The amount of the entry is yet to be determined.

        Income Tax.    The corporate income tax rate is projected to be 37 percent. Approximately 70 to 75 percent of current year income taxes are expected to be deferred.

        Common shares outstanding and preferred dividends.    As of December 31, 2002, there were 33,063,611 common shares outstanding. Preferred dividends, assuming preferred shares outstanding at December 31, 2002 remain outstanding for all of 2003, would be $7.2 million in 2003.

        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. Table A outlines the Company's equity hedge positions currently outstanding. For 2003, Western has hedged approximately 53 percent of its projected equity natural gas volumes and approximately 78 percent of its estimated equity volumes of crude, condensate and NGLs. The Company cannot predict the price that it will receive for its unhedged products or for products beyond the term of the hedges.

        Table A—Outstanding Equity Hedges and the Associated Basis for 2003.    In order to determine the hedged gas price to the particular operating region, adjust the NYMEX—equivalent price for the basis differential. The NYMEX or Mt. Belvieu—equivalent prices for NGLs do not include the cost of the hedges of approximately $930,000. There is no associated cost for the natural gas hedges. The natural gas equity hedges associated with the Permian differential and all NGL equity hedges are related to the gathering and processing business. The remaining natural gas hedges are related to the exploration and production business.

Table A—2003 Equity Gas and NGL Hedges

Product	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	52,000 MMbtu per day with an average price of $3.94 per MMbtu.	Mid-Continent—23,000 MMbtu per day average with an average basis price of ($0.16) 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.
	(all related to Mid-Continent volumes)	Rocky Mountain—44,000 MMbtu per day average with an average basis price of ($0.78) per MMbtu.
Crude, Condensate, Natural Gasoline	55,000 Barrels per month at an average price of $24.98 per barrel.	Not Applicable

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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	125,000 Barrels per month. Average minimum and maximum price of $0.25 per gallon and $0.37 per gallon, respectively.	Not Applicable

        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 20, 2003. 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.

        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. 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 natural gas and NGL production and sales volumes, commodity pricing and locational differentials, and other revenues and expenses. Although the Company believes that its expectations are based on reasonable assumptions, Western can give no assurances that its projections are accurate. 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, geological risk, environmental risk, weather, rig availability, transportation capacity, the ability of Western's partners to fund the necessary capital expenditures and the progress of ongoing litigation and related disputes with its co-developer in the Powder River Basin of Wyoming, and other factors as discussed in the Company's 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission.

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

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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 21, 2003	By:	/s/  WILLIAM J. KRYSIAK William J. Krysiak Executive Vice President/Chief Financial Officer (Principal Financial and Accounting Officer)

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ITEM 9. REGULATION FD DISCLOSURE

SIGNATURES