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Exhibit 99.1

WESTERN GAS RESOURCES, INC.
PROVIDES OPERATIONAL PROJECTIONS FOR 2004

        DENVER, February 13, 2004. Western Gas Resources, Inc. ("Western" or the "Company") (NYSE:WGR) today provided projections related to its expected operational performance in 2004.

        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 2004 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 equivalent natural gas production in 2004 is expected to increase to an average of approximately 164 million cubic feet of gas equivalent per day (MMcfed) or approximately 13 percent from 2003 levels with the majority of the increase to occur in the second half of the year. Preliminary estimates for 2005 indicate production growth to approximate 20 percent from 2004 estimates. Natural gas production from the Powder River Basin coal bed methane ("CBM") development is expected to average approximately 120 MMcfd net in 2004. Natural gas production volumes from activities in the Greater Green River Basin are expected to average approximately 44 MMcfed net in 2004. Production estimates for the Power River Basin in 2005 are expected to grow 10 to 15 percent and in the Green River Basin to increase by 25 percent. The 2005 estimates are preliminary and are based on participating in a certain number of wells in each area.

        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. 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. The production segment will realize the effect of the Company's equity natural gas hedging positions for 2004, as detailed in Table A, except those related to the Permian Basin. The results of the equity hedges are reported separately.

        In addition, in order to deliver its gas from the wellhead to these markets, the Company incurs gathering, compression and transportation expenses of $0.65 to 0.68 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, which include production overhead, are expected to be approximately $0.45 per Mcfe. Other items, including geological and geophysical expense, delay rentals and miscellaneous field expense (expensed due to successful efforts accounting) are expected to average $0.13 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 1.41 Bcfd, a four percent increase from 1.36 Bcfd in 2003. Preliminary estimates for 2005 indicate gas throughput volumes of 1.55 Bcfd. Natural gas plant sales are expected to average approximately 418 MMcfd. Equity gas volumes from the Company's Powder River Basin CBM development will no longer be included in the natural gas plant sales volumes as reported but will continue to be included in the gas gathering volumes and the total marketed natural gas volumes. Price realizations on these sales are dependent upon current basis differentials to the basins in which the Company operates and are generally below the NYMEX Henry Hub Index. The Company estimates that approximately 56 percent of plant gas is sold in the Rocky Mountain area, approximately 27 percent is sold in the Mid-Continent and approximately 17 percent of plant gas is

sold in the Permian Basin area. NGL plant sales are expected to approximate 1,462 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.

        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 revenue less product purchase expense) is dependent on commodity prices and is expected to average approximately $0.43 per Mcf of facility throughput. This estimate is based on an assumption of $4.75 per MMbtu for natural gas and $27.00 per barrel for crude oil (NYMEX-equivalent prices). Assuming higher commodity prices of $5.50 per MMbtu and $30.00 per barrel, gross operating margin would be estimated to be approximately $0.46 per Mcf of throughput. Assuming lower commodity prices of $4.00 per MMbtu and $24.00 per barrel, gross operating margin would be estimated to be approximately $0.39 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 2004. 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 expense is projected to be approximately $0.17 per Mcf of gas throughput volumes and should be deducted from the gross operating margin to arrive at a net operating margin per Mcf of gas throughput volumes.

        In addition to the above guidance information, the gathering and processing segment will also realize pre-tax 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 $9 to $10 million for 2004. 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 150 MMcfd and revenues are projected to be approximately $21.9 million for 2004. Operating income, after deducting pipeline operating expense and product purchase expense, is expected to be approximately $12.1 million.

        Marketing.    Marketed natural gas volumes (which include equity and third-party gas) are expected to be approximately 1.4 Bcfd. Gas marketing margins are projected to be approximately $0.025 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 1,825 MGald. NGL marketing margins and fees are projected to be approximately $0.006 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 2004. These revenues will be included in other, net on the income statement.

        Other Expenses.    General and administrative expenses are projected to be approximately $40.0 million for 2004. These expenses are estimated to be related to the segments as follows: 31 percent for exploration and production, 42 percent for gathering and processing, 7 percent for transportation and 20 percent for marketing. Depreciation, depletion and amortization expense is expected to approximate $82.6 million as follows: $40.1 million for exploration and production,

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$36.2 million for gathering and processing, $1.1 million for transportation and $5.2 million for corporate. Interest expense is projected to be approximately $22.3 million for 2004.

        Income Tax.    The corporate income tax rate is projected to be 37 percent. Approximately 60 to 65 percent of current year income taxes are expected to be deferred.

        Common shares outstanding and preferred dividends.    As of December 31, 2003, there were 34,135,901 common shares outstanding. On January 21, 2004 an additional 989,622 common stock shares were issued resulting from a partial conversion of preferred stock. Preferred dividends, assuming preferred shares outstanding at January 21, 2004 following the partial redemption, would be $3.3 million in 2004.

        Capital Expenditures for 2004.    The Company anticipates capital expenditures of approximately $243.5 million in 2004, primarily for growth and expansion projects in its Rocky Mountain upstream and midstream operations. The 2004 budget represents a nine percent increase from the estimated $223 million expended in 2003. The Rocky Mountain region will utilize 87 percent or $211.8 million of the 2004 budget. Western plans to invest approximately $101.7 million, or 42 percent of its total program, in the Powder River Basin CBM development. Approximately $70.1 million will be spent on drilling 800 gross wells and for lease acquisitions and $31.6 million for gathering and compression.

        The Greater Green River Basin is another significant area for capital investment. Western expects to invest approximately $98.3 million, or 40 percent of the total program, in this area. The Company will spend approximately $57.6 million to participate in 104 gross wells, 90 of which are in the rapidly developing Pinedale Anticline area, and $40.7 million to expand gathering and compression services. Exclusive of the Rocky Mountain region, the remaining $31.7 million of Western's 2004 capital spending program is expected to be spent as follows: $20.9 million for well connections, expansions, maintenance and upgrade projects in its other operating areas, $7.8 million for capitalized interest and overhead and $3.0 million for administrative expenditures.

        Reserves.    Net proved reserves at year-end 2003 totaled 685 Bcfe. Net probable and possible reserves on Western's leasehold increased to 2.13 Tcf at year-end 2003, including 1.94 Tcf in the Powder River Basin and 198 Bcf in the Greater Green River Basin. Potential unbooked reserves could increase to approximately 2.64 Tcf if twenty-acre spacing proved successful across the Company's Pinedale Anticline leasehold.

        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 2004, Western has hedged approximately 49 percent of its projected equity natural gas volumes and approximately 55 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 2004.    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 $1.2 million. 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.

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Table A—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) per MMBtu. 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

        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 13, 2004. 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, potential reserves and other revenues and expenses. Although the Company believes that its expectations are based on reasonable assumptions, Western can give no

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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 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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WESTERN GAS RESOURCES, INC. PROVIDES OPERATIONAL PROJECTIONS FOR 2004