8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC  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 23, 2006

WESTERN GAS RESOURCES, INC.

(Exact Name of Registrant as Specified in Charter)

Delaware	1-10389	84-1127613
(State of Other Jurisdiction of Incorporation)	(Commission File Number)	(IRS Employer Identification No.)
1099 18th Street, Suite 1200, Denver, Colorado		80202
(Address of Principal Executive Offices)		(Zip Code)
(303) 452-5603
(Registrant’s telephone number, including area code)
N.A.
(Former Name or Former Address, if Changed Since Last Report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02.  Results of Operations and Financial Condition.

On February 23, 2006, Western Gas Resources, Inc. issued two press releases, the first announcing its results for the year ended December 31, 2005 and the second providing operational projections for 2006.  The press releases are furnished as Exhibits 99.1 and 99.2 to this Form 8-K.

Item 9.01.  Financial Statements and Exhibits.

(c)   Exhibits.

A list of exhibits filed herewith is contained on the Exhibit Index which immediately precedes such exhibits and is incorporated herein by reference.

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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 hereunto duly authorized.

	WESTERN GAS RESOURCES, INC.
	(Registrant)
Date:     February 23, 2006	By:	/s/ William J. Krysiak
		Name:  William J. Krysiak
		Title:  Executive Vice President and Chief Financial Officer

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EXHIBIT INDEX

Exhibit Number	Description
99.1	Press release issued on February 23, 2006, announcing year-end 2005 results for Western Gas Resources, Inc.
99.2	Press release issued on February 23, 2006, providing operational projections for 2006.

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EX-99.1

Exhibit 99.1

WESTERN GAS RESOURCES, INC.

ANNOUNCES SIXTY PERCENT INCREASE IN NET INCOME FOR 2005

DENVER, February 23, 2006. Western Gas Resources, Inc. (NYSE:WGR) today announced that for the year ended December 31, 2005, net income increased 60 percent to $203.8 million, or earnings of $2.67 per share of common stock, compared to net income for 2004 of $127.8 million, or earnings of $1.73 per share of common stock. Earnings per share of common stock for both periods are on a fully diluted basis. Net income for the year ended December 31, 2004 includes the effect of a one-time after-tax benefit for a change in accounting principle of $4.7 million, or $0.06 per diluted share.

For the year ended December 31, 2005, revenues were $3.96 billion, adjusted EBITDA (earnings before interest, taxes, depreciation and amortization) was $468.9 million and cash flow before working capital adjustments was $417.2 million.

For the fourth quarter of 2005, net income increased 125 percent to $135.7 million, or earnings of $1.76 per share of common stock, compared to net income of $60.2 million, or earnings of $0.80 per share of common stock, for the same period in 2004. Earnings per share for both periods are on a fully diluted basis. Net income in the fourth quarter of 2005 reflects a $55.6 million benefit from the non-cash mark-to-market of economic hedges of future sales of gas.

For the fourth quarter of 2005, revenues totaled $1.30 billion, adjusted EBITDA (earnings before interest, taxes, depreciation and amortization) was $257.1 million and cash flow before working capital adjustments was $150.4 million.  See the tables below for reconciliation of adjusted EBITDA and cash flow before working capital adjustments.

Volumes and prices. Net production increased 14 percent to 63 billion cubic feet equivalent (“Bcfe”) in 2005 compared to 2004 and averaged 172.6 million cubic feet equivalent per day (“MMcfed”). Natural gas equity production sold was 63.4 Bcfe in 2005, or 173.8 MMcfed.

Gas throughput volumes at the Company’s gathering and processing facilities increased 4.5 percent in 2005 compared to 2004 and averaged 1.42 billion cubic feet per day (“Bcfd”).

Total gas sales volumes marketed, including equity gas production, gas produced at the Company’s plants and gas purchased from third parties for resale, averaged 1.17 Bcfd in 2005. Average gas prices increased 33 percent to $7.46 per thousand cubic feet (“Mcf”) in 2005 compared to $5.59 per Mcf in 2004.

Total natural gas liquids (“NGLs”)sales volumes marketed averaged 1.86 million gallons per day (“MMGald”) in 2005. Average NGL prices increased 28 percent to $0.96 per gallon in 2005 compared to $0.75 per gallon in 2004.

The Company’s equity-hedging positions decreased operating profit by $13.7 million in the fourth quarter of 2005 and by $16.6 million for the full year of 2005. This compares to a decrease in operating profit due to equity hedging of $2.6 million in the fourth quarter of 2004 and $9.0 million for the full year of 2004.

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Operations. The Company’s fully integrated operations include exploration, production, gathering, processing, treating, transportation and marketing of natural gas and NGLs.

Exploration and production realized segment-operating profit (EBITDA before general and administrative expenses) of $253.6 million for 2005 compared to $156.1 million for 2004. This 62 percent increase was primarily due to substantially higher natural gas prices and the 14 percent production volume growth from the Company’s operating areas including the Pinedale Anticline development, the Powder River Basin in Wyoming, and the properties in the San Juan Basin of New Mexico acquired in October 2004.

Gathering, processing and treating realized segment-operating profit of $237.6 million for 2005 compared to $168.9 million for 2004. This 41 percent increase is primarily due to higher commodity prices and to the increase in gathering and processing volumes.

Gas transportation realized segment-operating profit of $12.2 million for 2005 compared to $11.0 million for 2004. The transportation segment includes the results from the MIGC and MGTC regulated pipelines in the Powder River Basin.

Marketing realized segment-operating profit of $25.3 million for 2005 compared to $38.1 million for 2004. The 33 percent decrease in segment-operating profit was primarily due to non-cash mark-to-market losses from economic hedges of future sales of gas utilizing the Company’s storage and transportation capacity for the year ended December 31, 2005 compared to a gain for the year ended December 31, 2004. As the stored or transported natural gas is sold and the future sale derivatives are settled, the Company will realize the benefit of the storage and transportation transactions through earnings.

Capital Expenditures. Capital expenditures for 2005 totaled $457.3 million and consisted of the following: (i) $245.7 million related to exploration and production and lease acquisition activities; (ii) $194.3 million related to gathering, processing, treating and pipeline assets, including $12.7 million for maintaining existing facilities; and (iii) $17.3 million for miscellaneous items.

Balance Sheet. At December 31, 2005, Western had total assets of $2.33 billion, cash and cash equivalents in short-term investments of $27.2 million, total long-term debt outstanding of $430 million and a debt to capitalization ratio, net of cash and cash equivalents of 31 percent.

CEO comments. Peter Dea, President and Chief Executive Officer, commented, “Fourteen percent production volume growth, five percent processing volume growth, high commodity prices and our low-cost structure delivered our shareholders a record year in 2005 for earnings and cash flow. We expect this momentum to carry into 2006 with even higher production and throughput growth as we plan to participate in a record number of new wells in the Pinedale Anticline, while Big George coal continues to ramp up and our new 200 MMcfd Oklahoma processing plant commences operations in the second quarter.”

Other Information. Information about the Company’s significant projects, anticipated capital expenditures, equity production, proven reserves and operational guidance was provided in press releases issued by the Company on January 26, 2006, February 17, 2006 and February 23, 2006.

Earnings conference call. Western invites you to participate in its fourth quarter and year-end 2005 earnings conference call today February 23, 2006 at 9:30 a.m. (Mountain Time) by dialing (913) 981-4905. Please dial in five to ten minutes before the start of the call. A replay of the conference call will be available through midnight, March 1, 2006 by dialing (719) 457-0820, pass code 8124566. The live conference call may also be accessed on the Internet by logging onto Western’s Web site at www.westerngas.com. Select Investor Relations, then the Webcasts and Presentations 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 of the call will also be available on the Web site through March 31, 2006.

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

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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 production and gathering volumes, number of wells to be drilled, the performance of the Big George coal and the start-up of the new Oklahoma plant. 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 and NGL prices, the timeliness of federal and state permitting activity, government regulation or action, geological risk, environmental risk, weather, rig availability and other factors as discussed in the Company’s 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission.

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Financial Results:

(Dollars in thousands except share and per share amounts)

	Quarter Ended						Year Ended
	December 31,						December 31,
	2005			2004			2005			2004
Revenues:
Sale of gas	$	1,005,095		$	696,107		$	3,200,886		$	2,518,281
Sale of natural gas liquids	180,833			131,361			654,842			450,761
Gathering, processing and  transportation	27,732			24,555			106,366			90,874
Price risk management activities	79,448			31,490			(9,445		)	20,051
Other	2,007			458			6,009			3,201
Total Revenues	1,295,115			883,971			3,958,658			3,083,168
Costs and Expenses:
Product purchases	960,419			695,517			3,210,200			2,540,799
Plant and transportation  operating expense	29,963			27,703			115,524			95,868
Oil and gas exploration and  production costs	36,350			22,176			113,594			77,608
Depreciation, depletion and  amortization	36,444			28,523			128,783			95,536
Selling and administrative expense	14,083			14,740			60,113			52,246
(Gain) loss on sale of assets	296			(121		)	510			1,288
Loss from early extinguishment of debt	—			—			—			10,662
(Earnings) from equity investments	(3,115		)	(1,880		)	(10,133		)	(7,124		)
Interest expense	5,280			4,497			17,597			19,562
Total costs and expenses	1,079,720			791,155			3,636,188			2,886,445
Income before taxes	215,395			92,816			322,470			196,723
Provision for income taxes	79,656			32,605			118,661			73,678
Net income before cumulative effect of change in accounting principle	135,739			60,211			203,809			123,045
Cumulative effect of change in accounting principle, net of tax	—			—			—			4,714
Net Income	135,739			60,211			203,809			127,759
Preferred stock requirements	—			—			—			(835		)
Income attributable to common stock	$	135,739		$	60,211		$	203,809		$	126,924
Weighted average shares of common stock outstanding	74,883,010			74,001,545			74,409,704			72,419,980
Earnings per share of common stock	$	1.81		$	0.81		$	2.74		$	1.75
Weighted average shares of common stock outstanding - assuming dilution	76,974,049			75,243,839			76,200,131			73,494,747
Earnings per share of common stock - assuming dilution	$	1.76	(1)	$	0.80	(2)	$	2.67	(3)	$	1.73	(4)

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(1)Fully-diluted earnings per share for the quarter ended December 31, 2005 include, as potential common shares, the issuance of 2.1 million common shares from the possible exercise of stock options.

(2)Fully-diluted earnings per share for the quarter ended December 31, 2004 include, as potential common shares, the issuance of 1.2 million common shares from the possible exercise of stock options.

(3)Fully-diluted earnings per share for the year ended December 31, 2005 include, as potential common shares, the issuance of 1.8 million common shares from the possible exercise of stock options.

(4)Fully-diluted earnings per share for the year ended December 31, 2004 include, as potential common shares, the issuance of 1.1 million common shares from the possible exercise of stock options.

Condensed Consolidated Balance Sheet:

(Dollars in thousands)

	December 31,
	2005		2004
Assets:
Current assets	$	674,426	$	521,131
Property and equipment, net	1,558,321		1,225,909
Other assets	100,120		90,358
Total assets	$	2,332,867	$	1,837,398
Liabilities and Stockholders’ Equity:
Liabilities:
Current liabilities	$	609,658	$	474,787
Long-term debt	430,000		382,000
Other liabilities	393,415		295,842
Total liabilities	1,433,073		$	1,152,629
Stockholders’ equity	899,794		684,769
Total liabilities and stockholders’ equity	$	2,332,867	$	1,837,398

Reconciliation of Net Income to Adjusted EBITDA:

(Dollars in thousands)

	Quarter Ended				Year Ended
	December 31,				December 31,
	2005		2004		2005		2004
Net Income	$	135,739	$	60,211	$	203,809	$	127,759
Add:
Cumulative effect of change in accounting principle, net of tax	—		—		—		(4,714		)
Depreciation, depletion and amortization	36,444		28,523		128,783		95,536
Interest expense	5,280		4,497		17,597		19,562
Loss from early extinguishment of debt	—		—		—		10,662
Income taxes	79,656		32,605		118,661		73,678
Adjusted EBITDA	$	257,119	$	125,836	$	468,850	$	322,483

These data do not purport to reflect any measure of operations or cash flow. Adjusted EBITDA is not a measure determined pursuant to generally accepted accounting principles, or GAAP, nor is it an alternative to GAAP income. The Company is presenting this information, as it is a measure of financial performance used in the Company’s credit facilities to monitor the Company’s ability to perform under these facilities.

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Reconciliation of Net Income to

Cash Flow before Working Capital Adjustments:

(Dollars in thousands)

	Quarter Ended						Year Ended
	December 31,						December 31,
	2005			2004			2005			2004
Net Income	$	135,739		$	60,211		$	203,809		$	127,759
Add income items that do not affect operating cash flows:
Depreciation, depletion and amortization	36,444			28,523			128,783			95,536
Deferred income taxes	70,642			34,611			82,311			71,200
Distributions (less than) equity income, net	1,580			868			(1,081		)	127
(Gain) loss on sale of assets	296			(121		)	510			1,288
Non-cash change in fair value of derivatives	(95,073		)	(29,441		)	(1,808		)	(15,027		)
Compensation expense from common stock options and restricted stock	1,106			164			3,786			646
Cumulative effect of changes in accounting principles	—			—			—			(4,714		)
Other non-cash items, net	(308		)	(616		)	873			2,112
Cash flow before working capital adjustments	150,426			94,199			417,183			278,927
Net working capital adjustments	96,003			(10,055		)	(21,086		)	(69,768		)
Net cash provided by operating activities	$	246,429		$	84,144		$	396,097		$	209,159

Cash Flow before Working Capital Adjustments is not a measure determined pursuant to generally accepted accounting principles, or GAAP, nor is it an alternative to GAAP income. The Company is presenting this information as it is an important measure of financial performance used by equity analysts.

Operating Results:

(Dollars in thousands except per MMcfed, per MMcfd and per Mgal amounts)

	Quarter						Year
	Ended December 31,						Ended December 31,
	2005			2004			2005			2004
Exploration and Production:
Average gas production - net volumes sold (MMcfed)	187			163			174			153
Average gas price ($/Mcfe) (1)	$	8.50		$	5.16		$	6.41		$	4.69
Gathering and transportation expense ($/Mcfe)	$	0.92		$	0.68		$	0.83		$	0.72
Average wellhead gas price ($/Mcfe) (2)	$	7.58		$	4.48		$	5.58		$	3.97
Production taxes ($/Mcfe)	$	0.96		$	0.55		$	0.70		$	0.50
LOE ($/Mcfe) (3)	$	0.80		$	0.80		$	0.82		$	0.68
Other expense ($/Mcfe) (4)	$	0.11		$	0.07		$	0.13		$	0.12
Effect of equity hedges	$	(9,651	)	$	3,279		$	(7,375	)	$	6,720
Non-cash change in fair value of derivatives	$	6,663		—			$	11,103		—
Segment-operating profit	$	95,479		$	49,324		$	253,557		$	156,141
Depreciation, depletion and amortization	$	21,689		$	15,800		$	72,574		$	47,911
Gas Gathering and Processing:
Gas throughput volumes (MMcfd)	1,448			1,360			1,422			1,361
Gross operating margin ($/Mcf) (5)	$	0.72		$	0.61		$	0.67		$	0.54
Plant operating expense ($/Mcf) (5)	$	0.22		$	0.22		$	0.22		$	0.19
Effect of equity hedges	$	(4,012	)	$	(5,869	)	$	(9,223	)	$	(15,688	)
Income from equity investments	$	3,115		$	1,880		$	10,133		$	7,124
Non-cash change in fair value of derivatives	$	104		$	44		$	23		$	(12	)
Segment-operating profit	$	64,631		$	46,002		$	237,609		$	168,877
Depreciation, depletion and amortization	$	12,204		$	10,604		$	46,722		$	38,585
Gas Transportation:
Gas transportation volumes (MMcfd)	145			154			144			155
Transportation and sales revenue	$	6,175		$	5,773		$	22,980		$	22,683
Operating and product purchase expense	$	3,252		$	2,467		$	10,791		$	11,709
Segment-operating profit	$	2,920		$	3,306		$	12,189		$	10,974
Depreciation, depletion and amortization	$	493		$	416		$	1,829		$	1,655
Marketing:
Average gas sales (MMcfd)	1,071			1,213			1,171			1,225
Average gas price ($/Mcf)	$	10.17		$	6.19		$	7.46		$	5.59
Average gas sales margin ($/Mcf) (8)	$	0.184		$	0.094		$	0.066		$	0.037
Average NGL sales (Mgald)	1,801			1,569			1,862			1,641
Average NGL price ($/Gal)	$	1.09		$	0.91		$	0.96		$	0.75
Average NGL sales margin ($/Gal)	$	0.011		$	0.013		$	0.009		$	0.011
Non-cash change in fair value of derivatives	$	88,306		$	29,397		$	(9,318	)	$	15,039
Segment-operating profit	$	108,340		$	41,649		$	25,311		$	38,077
Depreciation, depletion and amortization	$	35		$	36		$	141		$	123

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(1)Net of fuel and shrink.

(2)Net of fuel, shrink, gathering and transportation. Excludes effect of hedging.

(3)Includes production overhead.

(4)Includes exploratory expense, delay rentals, impairment and unsuccessful well expense.

(5)Represents average gas sales price adjusted for appropriate regional differential.

(6)Represents average NGL sales price adjusted for appropriate transportation and fractionation charges.

(7)Per Mcf of throughput. Gross operating margin is gross revenues less product purchases and joint interest and excludes effect of hedging.

(8)Excludes non-cash change in fair value of derivatives.

Investor Contact:	Ron Wirth, Director of Investor Relations
	(800) 933-5603 or (303) 252-6090
	e-mail: rwirth@westerngas.com

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EX-99.2

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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