Exhibit 99.2

WESTERN GAS RESOURCES, INC.

PROVIDES OPERATIONAL PROJECTIONS FOR 2006

DENVER, February 23, 2006. Western Gas Resources, Inc. (NYSE:WGR) today provided projections related to its expected operational performance in 2006.

These estimates have been prepared based on the Company’s current expectations for natural gas and natural gas liquids (“NGL”) volumes, commodity pricing differentials, costs and expenses, debt balances and other items resulting from the Company’s 2006 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 include the previously announced acquisition of properties in the Powder River Basin, but do not include other 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 2006 is expected to increase approximately 17 to 22 percent from 2005 levels. Natural gas production from the Powder River Basin coal bed methane (“CBM”) development is expected to average approximately 128 to 131 million cubic feet per day (“MMcfd”) net in 2006. Natural gas production volumes from activities in the Greater Green River Basin are expected to average approximately 58 to 61 million cubic feet equivalent per day (“MMcfed”) net in 2006. Natural gas production from other areas, including the San Juan Basin and Canada, are expected to average 16 to 19 MMcfed net in 2006.

Approximately 50 percent of the Company’s gas production is sold in the Rocky Mountain area. The remainder is sold in the Mid-Continent area or markets further east by utilizing the Company’s firm transportation capacity. 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 2006, as detailed in Table A, except those related to the Permian Basin.

In addition, in order to deliver its gas from the wellhead to these markets, the Company incurs gathering, compression and transportation expenses of an estimated $0.75 per thousand cubic feet equivalent (“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 expense (“LOE”) and other miscellaneous expenses. For 2006, production taxes are expected to average approximately 12 percent of wellhead prices. LOE, which includes production overhead and water handling costs, are expected to be approximately $0.96 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 $0.10 per Mcfe. The above guidance does not include potential dry hole expense from exploratory operations.

Gathering, Processing and Treating. Gas throughput volumes at the Company’s facilities for 2006 are expected to average approximately 1.59 billion cubic feet per day (“Bcfd”), a 12 percent increase from 1.42 Bcfd in 2005. Preliminary estimates for 2007 indicate gas throughput volumes of 1.75 Bcfd. Revenues from the Company’s gathering, processing and treating facilities are derived from percent of proceeds, fee-based and keep-whole contracts. Gross operating margin (gross revenue less product purchase expense) is dependent on commodity prices and is expected to average approximately $0.64 per thousand cubic feet (“Mcf”) of facility throughput. This estimate is based on an assumption of $7.50 per million British thermal units (“MMBtu”) for natural gas and $55.00 per barrel for crude oil (NYMEX-equivalent prices). Assuming higher commodity prices of $9.00 per MMBtu and $65.00 per barrel, gross operating margin would be estimated to be approximately $0.71 per Mcf of throughput. Assuming lower commodity prices of $6.00 per MMBtu and $45.00 per barrel, gross operating margin would be estimated to be approximately $0.57 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 2006. 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 $0.25 per Mcf is comprised of fee revenues.

Plant operating expense is projected to be approximately $0.22 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 are estimated to be approximately $11.7 million for 2006. 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 140 MMcfd and revenues are projected to be approximately $22.5 million for 2006. Operating income, after deducting pipeline operating expense and product purchase expense, is expected to be approximately $10.7 million.

Marketing. Marketed natural gas volumes (which include equity and third-party gas) are expected to be approximately 1.2 Bcfd. Gas marketing margins are projected to be $0.025 to $0.05 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 2.2 million gallons per day. NGL marketing margins and fees are projected to be approximately $0.009 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 price risk management activities.

At December 31, 2005, the Company held gas in its contracted storage facilities and in pipeline imbalances totaling approximately 16.1 Bcf. This inventoried gas was sold forward with derivatives that are marked to market. Assuming a similar volume of gas in storage at the end of any month in 2006 and a subsequent $1.00 increase in the forward price of gas in each of the anticipated months of withdrawal, the change in the non-cash mark-to-market value of these derivatives would reduce pre-tax earnings by $16.1 million. Similarly a $1.00 decrease in the forward price of gas in each of the anticipated months of withdrawal would increase pre-tax earnings by $16.1 million. As the inventoried natural gas is sold and the future sale derivatives are settled, the Company will realize the benefit of the storage transactions through earnings. The Company also holds firm transportation agreements for capacity on natural gas pipelines. The Company may periodically support all or a portion of the value of these firm transportation agreements through the use of derivates that are marked to

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market. The subsequent change in the non-cash mark-to-market of these derivatives in the various months prior to the settlement of these derivatives will also increase or decrease, as the case may be, the Company’s pre-tax earnings. As the derivatives associated with firm transportation capacity are settled and the associated transportation capacity becomes available for use, the Company will realize the benefit of its transportation positions through earnings.

Other Modeling Assumptions:

Other Expenses. General and administrative expenses are projected to be approximately $67 million for 2006, which includes $14 million for the expected effect of expensing stock compensation as required under Statement of Financial Accounting Standards No. 123, (SFAS 123(R)).  Because the Company adopted this Standard effective January 1, 2006, this expense was not recognized in previous years. These expenses are estimated to be related to the segments as follows: 42 percent for exploration and production, 41 percent for gathering and processing, five percent for transportation and 12 percent for marketing. Depreciation, depletion and amortization expense is expected to approximate $145 million as follows:  $84 million for exploration and production, $56 million for gathering and processing, $1 million for transportation and $4 million for corporate. Interest expense is projected to be approximately $28.5 million for 2006.

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

Common shares outstanding. As of December 31, 2005, there were 75,350,784 common shares outstanding.

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. As part of the Company’s price risk management strategy, the Company enters into hedges from time to time on its equity production. Table A outlines the Company’s equity hedge positions currently outstanding. For 2006, Western has hedged approximately 56 percent of its projected equity natural gas volumes and approximately four 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 2006. In order to determine the hedged gas price to the particular operating region, adjust the NYMEX - equivalent price for the basis differential. 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.

Product	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	40,000 MMBtu per day with a minimum price of $6.00 and an average maximum price of $10.13 per MMBtu.	Mid-Continent – 40,000 MMBtu per day with an average basis price of ($0.545).
	45,000 MMBtu per day with a minimum price of $9.00 and a maximum price of $17.25 per MMBtu.	Rockies – 10,000 MMBtu per day with an average basis price of ($1.48).
		Northwest Rockies – 10,000 MMBtu per day with an average basis price of ($1.41).

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		El Paso Permian – 7,500 MMBtu per day with an average basis price of ($0.97).
		El Paso San Juan – 7,500 MMBtu per day with an average basis price of ($1.38).
		Texas Oklahoma – 10,000 MMBtu per day with an average basis price of ($0.45).
Crude, Condensate, Natural Gasoline	25,000 barrels per month with a minimum price of $40.00 per barrel and a maximum price of $70.00 per barrel.	Not Applicable

Updates. This document will be maintained on Western’s web site and is included in a Form 8-K furnished to the SEC on February 23, 2006. 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 furnished to the SEC. That information will also 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 posted directly to the web site without announcement.

Company Description. Western is an independent natural gas explorer, producer, gatherer, processor, transporter and energy marketer. 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, and the rapidly growing Pinedale Anticline. The Company also 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, gathering and transportation 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, the timeliness of federal and state permitting activity, well performance, expenditure of capital, 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 or (303) 252-6090
	e-mail: rwirth@westerngas.com

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