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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)

/x/
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001

OR

/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM                TO               

Commission file number 1-10389

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

Delaware (State or other jurisdiction of incorporation or organization)	84-1127613 (I.R.S. Employer Identification No.)
12200 N. Pecos Street, Denver, Colorado (Address of principal executive offices)	80234-3439 (Zip Code)

(303) 452-5603
Registrant's telephone number, including area code

No changes
(Former name, former address and former fiscal year, if changed since last report).

    Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /x/  No / /

    On November 1, 2001, there were 32,669,888 shares of the registrant's Common Stock outstanding.

Western Gas Resources, Inc.
Form 10-Q

Table of Contents

PART I—Financial Information
Item 1.	Financial Statements
	Consolidated Balance Sheet—September 30, 2001 and December 31, 2000
	Consolidated Statement of Cash Flows—Nine Months Ended September 30, 2001 and 2000
	Consolidated Statement of Operations—Three and Nine Months Ended September 30, 2001 and 2000
	Consolidated Statement of Changes in Stockholders' Equity—Nine Months Ended September 30, 2001
	Notes to Consolidated Financial Statements
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosures About Market Risk
PART II—Other Information
Item 1.	Legal Proceedings
Item 4.	Submission of Matters to a Vote of Security Holders
Item 6.	Exhibits and Reports on Form 8-K
Signatures

PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Dollars in thousands, except share data)

			September 30, 2001			December 31, 2000
			(unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	18,297		$	12,927
	Trade accounts receivable, net			188,790			546,791
	Product inventory			59,796			44,822
	Parts inventory			3,060			3,489
	Assets from price risk management activities			87,972			—
	Assets held for sale			5,199			25,001
	Other			590			2,654
		Total current assets		363,704			635,684
Property and equipment:
	Gas gathering, processing, storage and transportation			888,191			856,982
	Oil and gas properties and equipment (successful efforts method)			181,353			139,084
	Construction in progress			91,825			58,319
				1,161,369			1,054,385
Less: Accumulated depreciation, depletion and amortization				(349,604	)		(306,651	)
		Total property and equipment, net		811,765			747,734
Other assets:
	Gas purchase contracts (net of accumulated amortization of $34,833 and $33,357, respectively)			33,323			34,798
	Assets from price risk management activities			16,672			—
	Other			12,695			13,206
		Total other assets		62,690			48,004
Total assets			$	1,238,159		$	1,431,422
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	236,230		$	581,563
	Accrued expenses			39,740			25,094
	Liabilities from price risk management activities			33,160			—
	Dividends payable			4,218			4,205
		Total current liabilities		313,348			610,862
Long-term debt				305,000			358,700
Liabilities from price risk management activities				—			—
Other long-term liabilities				2,427			2,646
Deferred income taxes payable, net				121,046			67,680
Total liabilities				741,821			1,039,888
Stockholders' equity:
	Preferred Stock; 10,000,000 shares authorized:
		$2.28 cumulative preferred stock, par value $.10; 1,400,000 shares issued ($35,000,000 aggregate liquidation preference)		140			140
		$2.625 cumulative convertible preferred stock, par value $.10; 2,760,000 issued ($138,000,000 aggregate liquidation preference)		276			276
	Common stock, par value $.10; 100,000,000 shares authorized; 32,663,530 and 32,361,131 shares issued, respectively			3,290			3,265
	Treasury stock, at cost; 25,016 common shares and 44,290 shares of $2.28 cumulative preferred stock			(1,907	)		(1,778	)
	Additional paid-in capital			404,909			400,157
	Retained earnings (deficit)			60,354			(11,820	)
	Accumulated other comprehensive income			30,160			2,178
	Notes receivable from key employees secured by common stock			(884	)		(884	)
		Total stockholders' equity		496,338			391,534
Total liabilities and stockholders' equity			$	1,238,159		$	1,431,422

The accompanying notes are an integral part of the consolidated financial statements.

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

		Nine Months Ended September 30,
		2001			2000
Reconciliation of net income to net cash provided by operating activities:
Net income		$	84,816		$	38,043
Add income items that do not affect cash:
	Depreciation, depletion and amortization		47,018			41,733
	Gain on the sale of property and equipment		(10,653	)		(9,436	)
	Distributions (less than) in excess of equity income, net		912			(858	)
	Foreign currency translation adjustments		(1,698	)		(470	)
	Deferred income taxes		36,326			22,320
	Other non-cash items, net		(24,212	)		2,611
			132,509			93,943
Adjustments to working capital to arrive at net cash provided by operating activities:
	(Increase) decrease in trade accounts receivable		353,634			(192,511	)
	Increase in product inventory		(14,974	)		(14,768	)
	Decrease in parts inventory		429			1,449
	Decrease in other current assets		2,064			7,005
	Decrease in other assets and liabilities, net		(126	)		—
	Increase (decrease) in accounts payable		(345,333	)		169,955
	Increase (decrease) in accrued expenses		16,336			(8,720	)
Net cash provided by operating activities			144,539			56,353
Cash flows from investing activities:
	Purchases of property and equipment		(114,683	)		(72,970	)
	Proceeds from the dispositions of property and equipment		38,075			26,462
	Contributions to equity investees		(783	)		13
Net cash used in investing activities			(77,391	)		(46,495	)
Cash flows from financing activities:
	Net proceeds from exercise of common stock options		4,777			2,039
	Repurchase of $2.28 Cumulative Preferred Stock		(129	)		—
	Proceeds from issuance of long-term debt		—			—
	Debt issue costs paid		(97	)		(7	)
	Payments on revolving credit facility		(355,000	)		(922,286	)
	Borrowings under revolving credit facility		301,300			949,836
	Prepayment of American General notes		—			(27,000	)
	Dividends paid		(12,629	)		(12,660	)
Net cash provided by financing activities			(61,778	)		(10,078	)
Net increase (decrease) in cash and cash equivalents			5,370			(220	)
Cash and cash equivalents at beginning of period			12,927			14,062
Cash and cash equivalents at end of period		$	18,297		$	13,842

The accompanying notes are an integral part of the consolidated financial statements.

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

(Dollars in thousands, except share and per share amounts)

			Three Months Ended September 30,						Nine Months Ended September 30,
			2001			2000			2001			2000
Revenues:
	Sale of residue gas		$	542,131		$	739,431		$	2,343,533		$	1,659,104
	Sale of natural gas liquids			94,865			155,136			338,834			412,743
	Processing, transportation and storage revenue			10,418			12,956			41,042			36,251
	Non-cash change in fair value of derivatives			21,112			—			23,288
	Other, net			2,359			2,313			8,488			8,706
		Total revenues		670,885			909,836			2,755,185			2,116,804
Costs and expenses:
	Product purchases			594,452			833,266			2,465,602			1,911,136
	Plant operating expense			18,875			18,515			54,152			50,877
	Oil and gas exploration and production expense			2,614			5,038			21,317			10,975
	Depreciation, depletion and amortization			17,257			14,201			47,018			41,733
	(Gain)/loss on fixed assets			570			(3,802	)		(10,653	)		(9,436	)
	Selling and administrative expense			7,715			8,500			23,739			23,989
	Interest expense			6,132			8,889			18,953			24,916
		Total costs and expenses		647,615			884,607			2,620,128			2,054,190
Income before income taxes				23,270			25,229			135,057			62,614
Provision for income taxes:
	Current			68			—			13,915			537
	Deferred			8,429			9,058			36,326			22,320
		Total provision for income taxes		8,497			9,058			50,241			22,857
Income before extraordinary items				14,773			16,171			84,816			39,757
Extraordinary charge for early extinguishment of debt, net of tax benefit of $700,000				—			(1,714	)		—			(1,714	)
Net income				14,773			14,457			84,816			38,043
Preferred stock requirements				(2,584	)		(2,610	)		(7,753	)		(7,829	)
Income attributable to common stock			$	12,189		$	11,847		$	77,063		$	30,214
Income per share of common stock			$	.37		$	.37		$	2.37		$	.94
Weighted average shares of common stock outstanding				32,657,637			32,263,430			32,547,397			32,208,697
Income per share of common stock—assuming dilution			$	.36		$	.36		$	2.23		$	.92
Weighted average shares of common stock outstanding—assuming dilution				33,572,836			32,945,023			36,992,899			32,745,413

The accompanying notes are an integral part of the consolidated financial statements.

WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(Unaudited)
(Dollars in thousands, except share amounts)

				Shares of $2.28 Cumulative Preferred Stock	Shares of $2.28 Cumulative Preferred Stock in Treasury	$2.625 Cumulative Convertible Preferred Stock	Shares of Common Stock	Shares of Common Stock in Treasury	$2.28 Cumulative Preferred Stock		$2.625 Cumulative Convertible Preferred Stock		Common Stock		Treasury Stock			Additional Paid-In Capital		Retained (Deficit) Earnings			Accumulated Other Comprehensive Income Net of Tax			Notes Receivable from Key Employees			Total Stockholders' Equity
Balance at December 31, 2000				1,400,000	39,190	2,760,000	32,361,131	25,016		140		276		3,265		(1,778	)		400,157		(11,820	)		2,178			(884	)		391,534
Comprehensive income:
	Net income, nine months ended September 30, 2001			—	—	—	—	—		—		—		—		—			—		84,816			—			—			84,816
		Cumulative effect of change in accounting principle—January 1, 2001		—	—	—	—	—		—		—		—		—			—		—			(22,527	)		—			(22,527	)
		Reclassification adjustment for settled contracts		—	—	—	—	—		—		—		—		—			—		—			19,370			—			19,370
		Changes in fair value of outstanding hedging positions		—	—	—	—	—		—		—		—		—			—		—			15,286			—			15,286
		Fair value of new hedge positions		—	—	—	—	—		—		—		—		—			—		—			17,551			—			17,551
			Ending accumulated derivative gain	—	—	—	—	—		—		—		—		—			—		—			29,680			—			29,680
	Translation adjustments			—	—	—	—	—		—		—		—		—			—		—			(1,698	)		—			(1,698	)
	Total comprehensive income, net of tax																													112,798
Stock options exercised				—	—	—	302,399	—		—		—		25		—			4,752		—			—			—			4,777
Tax benefit related to stock options				—	—	—	—	—		—		—		—		—			—		—			—			—			—
Loans forgiven				—	—	—	—	—		—		—		—		—			—		—			—			—			—
Dividends declared on common stock				—	—	—	—	—		—		—		—		—			—		(4,890	)		—			—			(4,890	)
Dividends declared on $2.28 cumulative preferred stock				—	—	—	—	—		—		—		—		—			—		(2,319	)		—			—			(2,319	)
Dividends declared on $2.625 cumulative convertible preferred stock				—	—	—	—	—		—		—		—		—			—		(5,433	)		—			—			(5,433	)
Repurchase of $2.28 cumulative preferred stock				—	5,100	—	—	—		—		—		—		(129	)		—		—			—			—			(129	)
Balance at September 30, 2001				1,400,000	44,290	2,760,000	32,652,057	25,016	$	140	$	276	$	3,290	$	(1,907	)	$	404,909	$	60,354		$	30,160		$	(884	)	$	496,338

The accompanying notes are an integral part of the consolidated financial statements.

WESTERN GAS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

GENERAL

    The interim consolidated financial statements presented herein should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2000. The interim consolidated financial statements as of September 30, 2001 and for the three and nine-month periods ended September 30, 2001 and 2000 included herein are unaudited but reflect, in the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to fairly present the results for such periods. The results of operations for the three and nine months ended September 30, 2001 are not necessarily indicative of the results of operations expected for the year ended December 31, 2001.

    Prior period amounts in the interim consolidated financial statements and notes have been reclassified as appropriate to conform to the presentation used in 2001.

EARNINGS PER SHARE OF COMMON STOCK

    Earnings per share of common stock is computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding. In addition, earnings per share of common stock—assuming dilution is computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding as adjusted for potential common shares. Income attributable to common stock is income less preferred stock dividends. We declared preferred stock dividends of $2.6 million and $7.8 million, respectively, for each of the three and nine-month periods ended September 30, 2001 and 2000. Common stock options and our $2.625 cumulative convertible preferred stock, which are potential common shares, had a dilutive effect on earnings and increased the weighted average number of shares of common stock outstanding by 915,199 and 681,593 for the three-month periods ended September 30, 2001 and 2000, respectively, and by 4,445,502 and 536,716 for the nine months ended September 30, 2001 and 2000, respectively. The numerators and the denominators for these periods were adjusted to reflect these potential shares in calculating fully diluted earnings per share.

    On November 9, 2001, we issued a notice of redemption at the liquidation preference totalling $20.0 million (plus accrued and unpaid dividends) of the remaining $33.9 million of our $2.28 cumulative preferred stock. The date fixed for redemption is December 10, 2001. This redemption will be funded with amounts available under our Revolving Credit Facility. The pro rata capitalized offering costs of $920,000 associated with the redeemed preferred stock will be reflected as a special dividend to preferred shareholders in the fourth quarter of 2001 and will accordingly reduce earnings available to common shareholders in that quarter by approximately $.03 per common share.

OTHER INFORMATION

    Bethel Treating Facility.  In December 2000, we signed an agreement with Anadarko Petroleum Corporation for the sale of all the outstanding stock of our wholly-owned subsidiary, Pinnacle Gas Treating, Inc. ("Pinnacle"), for $38.0 million. The only asset of this subsidiary was a 300 MMcf per day treating facility and 86 miles of associated gathering assets located in east Texas. The sale closed in January 2001 and resulted in a net pre-tax gain for financial reporting purposes of $11.2 million in the first quarter of 2001.

    Western Gas Resources-California, Inc.  In January 2000, we sold all the outstanding stock of our wholly-owned subsidiary, Western Gas Resources-California, Inc. ("WGR-California"), for

$14.9 million. The only asset of this subsidiary was a 162-mile pipeline in the Sacramento basin of California. We acquired the pipeline through the exercise of an option in a transaction that closed simultaneously with the sale of WGR-California. We recognized a pre-tax gain on the sale of approximately $5.3 million in the first quarter of 2000.

    The proceeds from these sales were used to reduce borrowings outstanding on the Revolving Credit Facility.

    Westana.  In February 2000, we acquired the remaining 50% interest in the Westana Gathering Company for a net purchase price of $9.8 million. The results from our ownership through February 2000 of a 50% equity interest in the Westana Gathering Company are reflected in revenues in Other, net on the Consolidated Statement of Operations. Beginning in March 2000, the results of these operations are fully consolidated and are included in Revenues and Costs and expenses. Additionally, in March 2000, our investment in the Westana Gathering Company was reclassified from Other assets to Property and equipment.

    Granger Complex.  In May 2001, we acquired the remaining 50% interest in a portion of the Bird Canyon gathering system serving the Granger Complex for a net purchase price of $5.9 million in cash and the settlement of previously disclosed litigation. In September 2001, we signed an agreement with Questar Gas Management Company for the sale of a 50% interest in a segment of the Bird Canyon gathering system along with associated field compression for $5.2 million. This sale closed in October 2001. These assets were reclassified on the Consolidated Balance Sheet to Assets held for sale at September 30, 2001, and a $400,000 pre-tax loss on the excess of the net book value over the sales price of these assets was recognized in the third quarter of 2001.

    Also in October 2001, both Questar and we contributed our respective interests in the Bird Canyon system along with additional field compression and gathering dedications for gas produced along the Pinedale anticline portion of the Hoback basin to a newly formed joint venture named Rendezvous Gas Services, L.L.C. Each company owns a 50% interest in Rendezvous, and we will serve as field operator of its systems. In the fourth quarter of 2001, Rendezvous will begin construction of additional gas pipeline and compression facilities with a capacity to transport approximately 275 MMcf per day of gas production from the Pinedale anticline. This gas will be delivered for blending or processing at either our Granger Complex or at a Questar processing facility. The total estimated construction cost of the new pipeline and compression facilities is $15.5 million, of which our share will be $7.8 million. Our 50% interest in Rendezvous will be accounted for under the equity method.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

    In June 1998, the Financial Accounting Standards Board, (the "FASB"), issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"), effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which was subsequently amended by SFAS No. 138, we were required, starting on January 1, 2001, to recognize the change in the market value of all derivatives as either assets or liabilities in the Consolidated Balance Sheet and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction. Also on January 1, 2001, we adopted mark-to-market accounting for the remainder of our marketing activities which, for various reasons, are not designated or qualified as hedges under SFAS No. 133. Upon the adoption of SFAS No. 133 and mark-to-market accounting on January 1, 2001, the

impact was a decrease in a component of stockholders' equity through Accumulated other comprehensive income of $22.5 million, an increase to Current assets of $52.6 million, an increase to Current liabilities of $86.9 million, an increase to Other long-term liabilities of $1.1 million and a decrease in Deferred income taxes payable of $12.9 million.

    Of the $22.5 million decrease to Accumulated other comprehensive income resulting from the January 1, 2001 adoption of SFAS No. 133, $19.4 million was reversed in the first nine months of 2001 with gains and losses from the underlying transactions recognized through Total revenues. An additional $2.6 million of this transition entry is currently anticipated to be recognized through Total revenues in the fourth quarter of 2001.

    The non-cash impact to our results of operations in the first nine months of 2001 resulting from the adoption of mark-to-market accounting for our marketing activities resulted in additional pre-tax income of $23.3 million.

ADOPTION OF STOCKHOLDER RIGHTS PLAN

    In the first quarter of 2001, we adopted a Stockholder Rights Plan under which rights were distributed as a dividend at the rate of one right for each share of our common stock held by stockholders of record as of the close of business on April 9, 2001. The Rights Plan was not adopted in response to any efforts to acquire control of our company. The Rights Plan, however, is designed to deter coercive takeover tactics including the accumulation of shares in the open market or through private transactions and to prevent an acquirer from gaining control of our company without offering a fair and adequate price to all of our stockholders.

    Each right initially will entitle stockholders to buy one unit consisting of 1/100^th of a share of a new series of preferred stock for $180 per unit. The right generally will be exercisable only if a person or group acquires beneficial ownership of 15 percent or more of our then outstanding common stock or commences a tender or exchange offer upon consummation of which a person or group would beneficially own 15 percent or more of our then outstanding common stock. The rights will expire on March 22, 2011.

SUPPLEMENTARY CASH FLOW INFORMATION

    Interest paid was $18.5 million and $23.3 million for the nine months ended September 30, 2001 and 2000, respectively.

    We paid income taxes of $14.5 million during the nine months ended September 30, 2001. No income taxes were paid during the nine months ended September 30, 2000.

SEGMENT REPORTING

    We operate in four principal business segments, as follows: Gas Gathering and Processing, Exploration and Production, Marketing and Transportation. Management separately monitors these segments for performance against our internal forecast and are consistent with our internal financial reporting package. These segments have been identified based upon the differing products and services, regulatory environment and the expertise required for these operations.

    In our Gas Gathering and Processing segment, we connect producers' wells (including those of our Exploration and Production segment) to our gathering systems for delivery to our processing or treating

plants, process the natural gas to extract NGLs and treat the natural gas in order to meet pipeline specifications. Our Marketing segment sells the residue gas and NGLs extracted at our processing facilities.

    The activities of our Exploration and Production segment include the exploration and development of gas properties primarily in basins where our gathering and processing facilities are located. Our Marketing segment sells the majority of the production from these properties.

    Our Marketing segment buys and sells gas and NGLs nationwide and in Canada from or to a variety of customers. In addition, this segment also markets gas and NGLs produced by our gathering, processing and production assets. Our Canadian marketing operations, which are immaterial for separate presentation, are included in this segment. The Marketing segment also includes gains and losses associated with our equity gas and NGL hedging program of $10.6 million and $(10.6) million for the three months ended September 30, 2001 and 2000, respectively, and $(5.4) million and $(20.2) million for the nine months ended September 30, 2001 and 2000, respectively.

    The Transportation segment reflects the operations of our MIGC and MGTC pipelines. The majority of the revenue presented in this segment is derived from transportation of residue gas.

    The following table sets forth our segment information as of and for the three and nine months ended September 30, 2001 and 2000 (dollars in thousands). Due to our integrated operations, the use of allocations in the determination of business segment information is necessary. Inter-segment revenues are valued at prices comparable to those of unaffiliated customers.

	Gas Gathering and Processing		Exploration and Production		Marketing			Transmission			Corporate			Eliminating Entries			Total
Quarter ended September 30, 2001
Revenues from unaffiliated customers	$	26,878	$	970	$	611,152		$	1,167		$	11		$	—		$	640,178
Interest income		—		2		—			—			3,806			(3,195	)		613
Other, net		—		—		31,759			—			(1,665	)		—			30,094
Intersegment sales		130,817		17,213		18,245			4,279			14			(170,568	)		—
Total revenues		157,695		18,185		661,156			5,446			2,166			(173,763	)		670,885
Product purchases		115,362		1,621		641,736			(439	)		45			(163,873	)		594,452
Plant operating expense		16,661		65		(119	)		2,861			170			(763	)		18,875
Oil and gas exploration and production expense		—		10,259		—			—			—			(7,645	)		2,614
Gross profit	$	25,672	$	6,240	$	19,539		$	3,024		$	1,951		$	(1,482	)	$	54,944
Depreciation, depletion and amortization		9,915		5,829		41			419			1,053			—			17,257
Interest expense																		6,132
Loss on sale of assets																		570
Selling and administrative expense																		7,715
Income before income taxes																	$	23,270
Identifiable assets	$	585,158	$	171,596	$	80		$	47,565		$	62,154		$	—		$	866,553

	Gas Gathering and Processing		Exploration and Production			Marketing			Transmission			Corporate		Eliminating Entries			Total
Quarter ended September 30, 2000
Revenues from unaffiliated customers	$	26,338	$	783		$	903,127		$	1,844		$	28	$	—		$	932,120
Interest income		34		—			—			—			7,340		(7,158	)		216
Other, net		3		(38	)		(23,845	)		—			1,341		39			(22,500	)
Intersegment sales		200,016		21,440			43,823			3,775			14		(269,068	)		—
Total revenues		226,391		22,185			923,105			5,619			8,723		(276,187	)		909,836
Product purchases		174,832		1,217			922,802			(236	)		25		(265,374	)		833,266
Plant operating expense		16,145		104			28			2,356			278		(396	)		18,515
Oil and gas exploration and production expense		—		7,466			—			—			—		(2,428	)		5,038
Gross profit	$	35,414	$	13,398		$	275		$	3,499		$	8,420	$	(7,989	)	$	53,017
Depreciation, depletion and amortization		9,682		2,709			41			397			1,372		—			14,201
Interest expense																		8,889
Gain on sale of assets																		(3,802	)
Selling and administrative expense																		8,500
Income before income taxes																	$	25,229
Identifiable assets	$	542,703	$	116,432		$	62		$	46,909		$	39,971	$	—		$	746,077

	Gas Gathering and Processing		Exploration and Production			Marketing		Transmission			Corporate		Eliminating Entries			Total
Nine months ended September 30, 2001
Revenues from unaffiliated customers	$	57,078	$	1,798		$	2,669,805	$	6,151		$	314	$	—		$	2,735,146
Interest income		1		3			—		—			12,265		(11,014	)		1,255
Other, net		4		(1	)		17,991		2			788		—			18,784
Intersegment sales		668,620		98,780			38,856		12,937			41		(819,234	)		—
Total revenues		725,703		100,580			2,726,652		19,090			13,408		(830,248	)		2,755,185
Product purchases		571,105		6,230			2,689,416		(439	)		180		(800,890	)		2,465,602
Plant operating expense		48,933		163			—		6,693			96		(1,733	)		54,152
Oil and gas exploration and production expense		—		37,904			—		—			—		(16,587	)		21,317
Gross profit	$	105,665	$	56,283		$	37,236	$	12,836		$	13,132	$	(11,038	)	$	214,114
Depreciation, depletion and amortization		28,876		12,741			121		1,253			4,027		—			47,018
Interest expense																	18,953
Gain on sale of assets																	(10,653	)
Selling and administrative expense																	23,739
Income before income taxes																$	135,057
Identifiable assets	$	585,159	$	171,596		$	80	$	47,565		$	62,154	$	—		$	866,554

	Gas Gathering and Processing		Exploration and Production		Marketing			Transmission			Corporate			Eliminating Entries			Total
Nine months ended September 30, 2000
Revenues from unaffiliated customers	$	44,512	$	2,913	$	2,091,842		$	6,099		$	89		$	—		$	2,145,455
Interest income		68		2		27			—			19,597			(19,179	)		515
Other, net		1,675		3		(32,756	)		—			1,873			39			(29,166	)
Intersegment sales		520,359		49,347		83,104			12,494			31			(665,335	)		—
Total revenues		566,614		52,265		2,124,217			18,593			21,590			(684,475	)		2,116,804
Product purchases		421,085		2,749		2,142,760			(236	)		(65	)		(655,157	)		1,911,136
Plant operating expense		44,623		412		28			6,620			206			(1,012	)		50,877
Oil and gas exploration and production expense		31		20,068		—			—			—			(9,124	)		10,975
Gross profit	$	100,875	$	29,036	$	(571	)	$	12,209		$	21,449		$	(19,182	)	$	143,816
Depreciation, depletion and amortization		27,244		9,091		121			1,230			4,047			—			41,733
Interest expense																		24,916
Gain on sale of assets																		(9,436	)
Selling and administrative expense																		23,989
Income before income taxes																	$	62,614
Identifiable assets	$	542,703	$	116,432	$	62		$	46,909		$	39,971		$	—		$	746,077

LEGAL PROCEEDINGS

    Reference is made to "Part II—Other Information—Item 1. Legal Proceedings," of this Form 10-Q.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

    In June 2001, the FASB, issued SFAS No. 142, "Goodwill and Other Intangible Assets" and SFAS No. 143 "Accounting for Asset Retirement Obligations." As it applies to us, SFAS No. 142 is effective for fiscal years beginning after December 15, 2001. SFAS No. 142 changes the method in which goodwill and other intangible assets are recorded and amortized. SFAS No. 142 will not have an immediate impact on us as we do not currently have any goodwill recorded in our financial statements. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. SFAS No. 143 establishes accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. We have not yet determined the impact that the adoption of SFAS No. 143 will have on our earnings or financial position.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

    The following discussion and analysis relates to factors which have affected our consolidated financial condition and results of operations for the three and nine months ended September 30, 2001 and 2000. Prior year amounts have been reclassified as appropriate to conform to the presentation used in 2001. You should also refer to our interim consolidated financial statements and notes thereto included elsewhere in this document. This section, as well as other sections in this Form 10-Q, contain "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by the use of forward-looking terminology, such as "may," "intend," "will," "expect," "anticipate," "estimate," or "continue" or the negative thereof or other variations thereon or comparable terminology. In addition to the important factors referred to herein, numerous factors affecting the gas processing industry generally and in the specific markets for gas and NGLs in which we operate could cause actual results to differ materially from those in such forward-looking statements.

Results of Operations

Three and nine months ended September 30, 2001 compared to the three and nine months ended September 30, 2000 (Dollars in thousands, except per share amounts and operating data).

	Three Months Ended September 30,						Nine Months Ended September 30,
					Percent Change						Percent Change
	2001		2000				2001		2000
Financial results:
Revenues	$	670,885	$	909,836	(26	)	$	2,755,185	$	2,116,804	30
Gross profit		37,117		42,618	(13	)		177,749		111,519	59
Net income		14,773		14,457	2			86,816		38,043	123
Income per share of common stock		.37		.37	—			2.37		.94	152
Income per share of common stock—assuming dilution		.36		.36	—			2.23		.92	142
Net cash provided by operating activities	$	17,725	$	34,317	(48	)	$	144,539	$	56,353	156
Operating data:
Average gas sales (MMcf/D)		2,130		1,970	8			1,880		1,810	4
Average NGL sales (MGal/D)		2,335		3,170	(26	)		2,315		3,040	(24	)
Average gas prices ($/Mcf)	$	2.77	$	4.08	(32	)	$	4.57	$	3.34	37
Average NGL prices ($/Gal)	$	.44	$	.53	(17	)	$	.53	$	.50	6

    Net income increased $300,000 and $46.8 million for the three and nine months ended September 30, 2001 compared to 2000. The increase in net income for the nine months ended September 30, 2001 is primarily attributable to significantly higher gas prices in 2001 compared to the same period in prior year, increased production from the Powder River basin coal bed methane development, and improved results from our marketing segment.

    Revenues from the sale of gas decreased $197.3 million to $542.1 million for the three months ended September 30, 2001 compared to the same period in 2000. This decrease was primarily due to a reduction in product prices in 2001, which was partially offset by an increase in sales of natural gas purchased from third parties. Average gas prices realized by us decreased $1.31 per Mcf to $2.77 per Mcf for the quarter ended September 30, 2001 compared to the same period in 2000. Included in the realized gas price were approximately $10.2 million of gains recognized in the three months ended September 30, 2001 related to futures positions on equity gas volumes, which are treated as hedges under SFAS No. 133. We have entered into additional futures positions for the majority of our equity gas for the fourth quarter of 2001 and throughout 2002. See further discussion in Item 3. Quantitative and Qualitative Disclosures about Market Risk—Risk Management Activities. Average gas sales

volumes increased 160 MMcf per day to 2,130 MMcf per day for the quarter ended September 30, 2001 compared to the same period in 2000.

    Revenues from the sale of gas increased $684.4 million to $2,343.5 million in the nine months ended September 30, 2001 compared to the same period in 2000. This increase was primarily due to an improvement in product prices and to a lesser extent from an increase in sales of natural gas purchased from third parties. Average gas prices realized by us increased $1.23 per Mcf to $4.57 per Mcf in the nine months ended September 30, 2001 compared to the same period in 2000. Included in the realized gas price were approximately $4.1 million of losses recognized in the nine months ended September 30, 2001 related to futures positions on equity gas volumes, which are treated as hedges under SFAS No. 133. We have entered into additional futures positions for the majority of our equity gas for the fourth quarter of 2001 and throughout 2002. See further discussion in Item 3. Quantitative and Qualitative Disclosures about Market Risk—Risk Management Activities. Average gas sales volumes increased 70 MMcf per day to 1,880 MMcf per day in the nine months ended September 30, 2001 compared to the same period in 2000.

    Revenues from the sale of NGLs decreased $60.3 million in the third quarter of 2001 compared to the same period in 2000. This decrease is due to a reduction in sales volume and a decrease in product prices. Average NGL prices realized by us decreased $.09 per gallon to $.44 per gallon in the third quarter of 2001 compared to the same period in 2000. Included in the realized NGL price were approximately $400,000 of gains recognized in the third quarter of 2001 related to futures positions on equity NGL volumes, which are treated as hedges under SFAS No. 133. We have entered into additional futures positions for a portion of our equity NGL production for the fourth quarter of 2001. See further discussion in Item 3. Quantitative and Qualitative Disclosures about Market Risk—Risk Management Activities. Average NGL sales volumes decreased 835 MGal per day to 2,335 MGal per day in the third quarter of 2001 compared to the same period in 2000. This decrease is primarily due to an intentional reduction in the sale of third-party product as these types of sales were generating minimal margins.

    Revenues from the sale of NGLs decreased approximately $73.9 million in the nine months ended September 30, 2001 compared to the same period in 2000. This decrease is due to a reduction in sales volume, which more than offset an increase in product prices. Average NGL prices realized by us increased $.03 per gallon to $.53 per gallon in the nine months ended September 30, 2001 compared to the same period in 2000. Included in the realized NGL price were approximately $1.2 million of losses recognized in the nine months ended September 30, 2001 related to futures positions on equity NGL volumes, which are treated as hedges under SFAS No. 133. We have entered into additional futures positions for a portion of our equity NGL production for the fourth quarter of 2001. See further discussion in Item 3. Quantitative and Qualitative Disclosures about Market Risk—Risk Management Activities. Average NGL sales volumes decreased 725 MGal per day to 2,315 MGal per day in the nine months ended September 30, 2001 compared to the same period in 2000. This decrease is primarily due to an intentional reduction in the sale of third-party product as these types of sales were generating minimal margins. Also contributing to the reduction in overall sales volume was a decrease in the sale of product produced at our facilities as we rejected ethane for a portion of the nine-month period.

    Product purchases decreased by $238.8 million for the quarter ended September 30, 2001 and increased $554.5 million for the nine months ended September 30, 2001 compared to the same periods in 2000, primarily as a result of the increase in commodity prices. Overall, combined product purchases as a percentage of sales of all products remained constant at 93% and 92% for the quarter and nine months ended September 30, 2001 and September 30, 2000, respectively.

    Marketing margins on residue gas averaged $0.04 per Mcf in the third quarter of 2001 and $0.09 per Mcf for the nine months ended September 30, 2001. This represents a significant increase as

compared to the $0.02 per Mcf margin realized during both the third quarter of 2000 and the nine months ended September 30, 2000. The increase in margin for the quarter and nine months ended September 30, 2001 primarily resulted from the mark-to-market of transactions utilizing a portion of our firm transportation capacity during the remainder of 2001 and the mark-to-market of storage transactions for the winter of 2001-2002. Under mark-to-market accounting, which we adopted on January 1, 2001, the margin to be realized over the term of the transaction is recorded in the month of origination. To the extent this amount includes margin to be recognized beyond the current quarter, it is included in the financial statement caption Non-cash change in fair value of derivatives. Marketing margins on NGLs averaged approximately $0.003 per gallon in the third quarter and $0.006 per gallon in the nine months ended September 30, 2001. This represents a decrease as compared to the $0.008 per gallon margin realized during both the third quarter of 2000 and the nine months ended September 30, 2000. This decrease has resulted in our decision to intentionally reduce the sale of third-party NGL products. There is no assurance, however, that these market conditions for our gas and NGL products and related margins will continue in the future, that we will be in a similar position to benefit from them or that we will continue to originate the same amount of transactions in future quarters. During 2001, we reserved a total of $1.0 million for doubtful accounts. This reserve is not included in the calculation of the marketing margins and is reported in Selling and administrative expenses.

    Plant operating expense increased $360,000 in the third quarter of 2001 and by $3.3 million in the nine months ended September 30, 2001 compared to the same periods in 2000. This increase is primarily due to additional leased compression in the Powder River basin coal bed development and higher fuel costs at our plant facilities.

    Oil and gas exploration and production expenses decreased by $2.4 million in the third quarter of 2001 and increased by $10.3 million in the nine months ended September 30, 2001 as compared to the same periods in 2000. The decrease in the third quarter of 2001 is primarily due to a reduction in severance taxes resulting from a decrease in product prices. The increase in the nine-month period is primarily as a result of our overall increasing operations in the Powder River basin coal bed methane development.

    Depreciation, depletion and amortization increased by $3.1 million and $5.3 million in the third quarter and the nine months ended September 30, 2001 as compared to the same periods in 2000, primarily as a result of our increasing operations in the Powder River basin coal bed methane development.

    Extraordinary charge for early extinguishment of debt decreased in the third quarter and the nine months ended September 30, 2001 as compared to the same periods in 2000 as a result of an after-tax charge of $1.7 million incurred in third quarter of 2000. In September 2000, we prepaid $27.0 million of outstanding indebtedness to insurance companies, originally due to be paid in November 2005, with funds available under our Revolving Credit Facility. In connection with this prepayment, we paid a pre-tax make-whole payment of approximately $2.0 million and expensed capitalized fees of approximately $752,000.

Other Information

    Bethel Treating Facility.  In December 2000, we signed an agreement with Anadarko Petroleum Corporation for the sale of all the outstanding stock of our wholly owned subsidiary, Pinnacle for $38.0 million. The only asset of this subsidiary was a 300 MMcf per day treating facility and 86 miles of associated gathering assets located in east Texas. The sale closed in January 2001 and resulted in a net pre-tax gain for financial reporting purposes of $11.2 million in the first quarter of 2001.

    Western Gas Resources-California, Inc.  In January 2000, we sold all the outstanding stock of our wholly owned subsidiary, WGR-California for $14.9 million. The only asset of this subsidiary was a

162-mile pipeline in the Sacramento basin of California. We acquired the pipeline through the exercise of an option in a transaction that closed simultaneously with the sale of WGR-California. We recognized a pre-tax gain on the sale of approximately $5.3 million in the first quarter of 2000.

    The proceeds from these sales were used to reduce borrowings outstanding on the Revolving Credit Facility.

    Westana.  In February 2000, we acquired the remaining 50% interest in the Westana Gathering Company for a net purchase price of $9.8 million. The results from our ownership through February 2000 of a 50% equity interest in the Westana Gathering Company are reflected in revenues in Other, net on the Consolidated Statement of Operations. Beginning in March 2000, the results of these operations are fully consolidated and are included in Revenues and Costs and expenses. Additionally, in March 2000, our investment in the Westana Gathering Company was reclassified from Other assets to Property and equipment.

    Granger Complex.  In May 2001, we acquired the remaining 50% interest in a portion of the Bird Canyon gathering system serving the Granger Complex for a net purchase price of $5.9 million in cash and the settlement of previously disclosed litigation. In September 2001, we signed an agreement with Questar Gas Management Company for the sale of a 50% interest in a segment of the Bird Canyon gathering system along with associated field compression for $5.2 million. This sale closed in October 2001. These assets were reclassified on the Consolidated Balance Sheet to Assets held for sale at September 30, 2001 and a $400,000 pre-tax loss on the excess of the net book value over the sales price of these assets was recognized in the third quarter of 2001.

    Also in October 2001, both Questar and we contributed our respective interests in the Bird Canyon system along with additional field compression and gathering dedications for gas produced along the Pinedale anticline portion of the Hoback basin to a newly formed joint venture named Rendezvous Gas Services, L.L.C. Each company owns a 50% interest in Rendezvous, and we will serve as field operator of its systems. In the fourth quarter of 2001, Rendezvous will begin construction of additional gas pipeline and compression facilities with a capacity to transport approximately 275 MMcf per day of gas production from the Pinedale anticline. This gas will be delivered for blending or processing at either our Granger Complex or at a Questar processing facility. The total estimated construction cost of the new pipeline and compression facilities is $15.5 million, of which our share will be $7.8 million. Our 50% interest in Rendezvous will be accounted for under the equity method.

Business Strategy

    Improved product prices in 2000 and 2001 have strengthened our financial position, which will allow us to emphasize the growth aspects of our business strategy. Our long-term business plan is to increase our profitability by: (i) optimizing the efficiency and utilization of our existing operations; (ii) developing natural gas reserves and increasing production volumes on our existing acreage positions; and (iii) investing in projects or acquiring assets that complement and extend our core natural gas gathering, processing, exploration and production and marketing businesses.

    We are actively evaluating acquisitions of either assets or companies. These acquisitions can be related to gathering and processing or exploration and production with emphasis on properties located in the Rocky Mountains or Canada. Capital expenditures budgeted for existing operations in 2001 are estimated to be approximately $172.5 million. This includes approximately $96.7 million related to gathering, processing and pipeline assets and approximately $53.1 million for the acquisition of undeveloped acreage and development of gas reserves in the Powder River basin. In the first nine months of 2001, our capital expenditures totaled $115.5 million.

    We consistently seek to improve the profitability of our existing operations by increasing natural gas throughput levels through new well connections and expansion of our gathering systems, increasing

our efficiency through the modernization of equipment and consolidation of existing gathering and processing facilities, evaluating the economic performance of each of our operating facilities to ensure that a targeted rate of return is achieved and controlling operating and overhead expenses.

    We continually seek to increase reserves dedicated to our gathering and processing facilities. Our operations are located in some of the most actively drilled oil and gas producing basins in the United States. We enter into agreements under which we gather and process natural gas produced on acreage dedicated to us by third parties. We contract for production from new wells or undeveloped acreage in order to replace declines in existing reserves or increase reserves that are dedicated for gathering and processing at our facilities. At December 31, 2000, our estimated dedicated reserves totaled 2.7 Tcf. In 2000, including the reserves developed by us and associated with our partnerships and excluding the reserves and production associated with the facilities sold during this period, we connected new reserves to our facilities to replace approximately 222% of throughput. In order to obtain additional dedicated acreage and to secure contracts on favorable terms, we may participate to a limited extent with third-party producers in exploration and production activities to supply our facilities. For the same reason, we may also offer to sell ownership interests in our facilities to selected producers.

    We selectively participate in exploration and production activities largely to secure additional gas supply for our facilities. Beginning in 1997, we substantially increased our investment in the acquisition of undeveloped acreage and development of the Powder River basin coal bed methane. We have acquired drilling rights on approximately 524,000 net acres in the basin. At December 31, 2000 we had proved developed and undeveloped reserves of approximately 350 Bcf on a portion of this acreage. We also have participated in the development of properties in southwest Wyoming and Colorado. As of December 31, 2001, these properties had an additional 58 Bcf of proved developed and undeveloped reserves. This represents an increase of approximately 50% in our proved reserves from December 31, 1999. We currently estimate a net total of 2.2 Tcf of probable or possible reserves on an unrisked basis associated with undeveloped acreage in these areas. There can be no assurance, however, as to the ultimate recovery of these probable or possible reserves. We will also consider investing in other exploration and production prospects that we consider to be low risk and complementary to our other business segments.

    We will continue to invest in projects that complement and extend our core natural gas gathering, processing, exploration and production and marketing businesses including the consideration of expansion into additional geographic areas in the continental United States and Canada.

    In October 2001, Mr. Peter A. Dea was appointed President, Chief Executive Officer and Director effective November 1, 2001. Mr. Dea was most recently the Chairman of the Board and CEO of Barrett Resources Corporation. He had been employed with Barrett since 1994 in various executive positions, including Executive Vice President-Exploration. Prior to joining Barrett, Mr. Dea served as President of Nautilus Oil and Gas Company from 1992 to 1993. By amendment to our bylaws, the board of directors has been expanded from nine members to ten to allow for Mr. Dea's appointment to the board. Mr. Lanny Outlaw, our former Chief Executive Officer and President, retired on October 31, 2001. Mr. Outlaw intends to serve his remaining term on the board of directors, which expires in May 2003.

Liquidity and Capital Resources

    Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of debt and equity securities. In the past, these sources have been sufficient to meet our needs and finance the growth of our business. We can give no assurance that the historical sources of liquidity and capital resources will be available for future development and acquisition projects, and we may be required to seek alternative financing sources. Product prices, sales of inventory, the volumes of natural gas processed by

our facilities, the volume of natural gas produced from our producing properties, the margin on third-party product purchased for resale, as well as the timely collection of our receivables will all affect future net cash provided by operating activities. Additionally, our future growth will be dependent upon obtaining additions to dedicated plant reserves, acquisitions, new project development, marketing, efficient operation of our facilities and our ability to obtain financing at favorable terms.

    We believe that the amounts available to be borrowed under the Revolving Credit Facility, together with net cash provided by operating activities will provide us with sufficient funds to connect new reserves, maintain our existing facilities, complete our current capital expenditure program and make any scheduled debt principal payments and redeem a portion of our $2.28 cumulative preferred stock. Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital. Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or a combination of alternatives. While we believe that we would be able to secure additional financing, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing. We also believe that cash provided by operating activities and amounts available under the Revolving Credit Facility will be sufficient to meet our debt service and preferred stock dividend requirements for the remainder of 2001 and for 2002.

    During the past several years some of our plants have experienced declines in dedicated reserves, overall we have been successful in connecting additional reserves to more than offset the natural declines. Higher gas prices, improved technology, e.g. 3-D seismic and horizontal drilling, and increased pipeline capacity from the Rocky Mountain region have stimulated drilling in many of our operating areas. The overall level of drilling will depend upon, among other factors, the prices for oil and gas, the drilling budgets of third-party producers, the energy policy and regulation by governmental agencies and the availability of foreign oil and gas, none of which is within our control. There is no assurance that we will continue to be successful in replacing the dedicated reserves processed at our facilities.

    We have effective shelf registration statements filed with the Securities and Exchange Commission for an aggregate of $200 million of debt securities and preferred stock, along with the shares of common stock, if any, into which those securities are convertible, and $62 million of debt securities, preferred stock or common stock.

    Our sources and uses of funds for the nine months ended September 30, 2001 are summarized as follows (dollars in thousands):

Sources of funds:
	Borrowings under the Revolving Credit Facility		$	301,300
	Proceeds from the dispositions of property and equipment			38,075
	Net cash provided by operating activities			144,539
	Proceeds from exercise of common stock options			4,777
		Total sources of funds	$	488,691
Uses of funds:
	Payments related to long-term debt (including debt issue costs)		$	355,000
	Capital expenditures			114,683
	Dividends paid			12,629
	Other			1,009
		Total uses of funds	$	483,321

    Additional sources of liquidity available to us are our inventories of gas and NGLs in storage facilities. We held gas in storage and in imbalances of approximately 16.1 Bcf at an average cost of $3.37 per Mcf at September 30, 2001 compared to 13.9 Bcf at an average cost of $3.31 per Mcf at September 30, 2000 under storage contracts at various third-party facilities. These positions will be substantially liquidated within the next two quarters at prices prevailing at that time as adjusted by any associated derivative instruments. Under mark-to-market accounting, the profit to be earned on these transactions was recorded in the month of origination.

    We held NGLs in storage of 7,409 MGal, consisting primarily of propane and normal butane, at an average cost of $0.38 per gallon and 14,213 MGal at an average cost of $0.41 per gallon at September 30, 2001 and 2000, respectively, at various third-party storage facilities. These inventory positions will be substantially liquidated within the next two quarters at prices prevailing at that time as adjusted by any associated derivative instruments.

Preferred Stock Repurchase and Redemption Program

    Through the first nine months of 2001, we purchased in open market transactions a total of 5,100 shares of our $2.28 cumulative preferred stock for a total cost, including broker commissions, of approximately $129,000, or an average of $25.25 per share of preferred stock. These shares will be retired. On November 9, 2001, we issued a notice of redemption at the liquidation preference totaling $20.0 million (plus accrued and unpaid dividends) of the remaining $33.9 million of our $2.28 cumulative preferred stock. The date fixed for redemption is December 10, 2001. This redemption will be funded with amounts available under our Revolving Credit Facility. The pro rata capitalized offering costs of $1.0 million associated with the redeemed preferred stock will be reflected as a special dividend to preferred shareholders in the fourth quarter of 2001 and will accordingly reduce earnings available to common shareholders in that quarter by approximately $.03 per common share.

Capital Investment Program

    Primarily as a result of additional drilling behind our systems and in the Powder River basin, we have increased our capital budget for the year ending December 31, 2001 by approximately $36.7 million. We now expect capital expenditures related to existing operations to be approximately $172.5 million during 2001, consisting of the following: (i) approximately $96.7 million related to gathering, processing and pipeline assets, of which $14.7 million is for maintaining existing facilities; (ii) approximately $71.1 million related to exploration and production activities; and (iii) approximately $4.7 million for miscellaneous items. Overall, capital expenditures in the Powder River basin coal bed methane development and in southwest Wyoming operations represent 40% and 20%, respectively, of the total 2001 budget.

    As of September 30, 2001, we have expended $115.5 million, consisting of the following: (i) $62.7 million related to gathering, processing and pipeline assets, of which $4.9 million is for maintaining existing facilities; (ii) $50.6 million related to exploration and production activities; and (iii) $2.1 million for miscellaneous items.

Coal Bed Methane—We continue to develop our Powder River basin coal bed gas reserves and the associated gathering system in Wyoming. The Powder River basin coal bed methane area is currently one of the largest on-shore plays for the development of natural gas in the United States. In the first nine months of 2001, we continued to be the largest producer of natural gas (together with our partner), the largest gatherer of natural gas and the largest gas transporter out of the basin. At September 30, 2001, we held the drilling rights on approximately 524,000 net acres, in the basin. As of December 31, 2000, we had established proven developed and undeveloped reserves totaling 350 Bcf on a portion of this acreage. This represented a 50% increase in proved reserves as compared to December 31, 1999. As of June 30, 2001, we estimated that there was a net total of 2.1 Tcf of probable

and possible reserves on an unrisked basis associated with undeveloped acreage in this area. There can be no assurance, however, as to the ultimate recovery of these reserves.

    We participated in the drilling of 686 gross wells in the first ten months of 2001 and plan to participate in a total of 840 gross wells in 2001. The average drilling, completion and gathering cost for our coal bed methane gas wells is approximately $70,000 to $90,000 per well with proved reserves per well of approximately 330 MMcf. Our average finding and development costs in this area are estimated to be $.31 per Mcf. As deeper wells are drilled to the Big George coal, reserves per well are expected to increase as will the average cost per well. It is expected that the deeper Big George wells will result in a higher rate of return. Our share of production from wells in which we own an interest has increased from an average of approximately 50 MMcf per day at December 31, 1999 to 100 MMcf per day at October 31, 2001. We currently anticipate production rates of 108 net MMcf per day (270 gross MMcf per day) from this area by the end of 2001. Within the Hoe Creek area of the Powder River basin, approximately 150 gross wells have not responded to dewatering as expected and may not achieve our original estimate of production or reserves. All of the remaining areas under development in the Wyodak coal continue to produce at or above forecasted levels.

    We are currently evaluating eight pilot development areas in the Big George. Several of these pilots are in close proximity to leases operated by third-parties, which are currently producing growing volumes of natural gas. By the end of 2001, we expect to have drilled 250 gross wells in the pilot areas. Five of these pilot areas are currently in the de-watering phase. Our All Night Creek pilot is currently producing a total of 3.8 gross MMcf per day of gas from 53 wells.

    Future drilling on federal acreage will be delayed subject to completion of the Powder River Basin Oil & Gas Environmental Impact Statement. We anticipate the study to be completed in the third quarter of 2002. Our drilling plans for the remainder of 2001 are not expected to be substantially impacted by this study due to our large inventory of non-federal drilling locations and the issuance of drilling permits by the Bureau of Land Management for approximately 250 well locations to prevent drainage of federal acreage.

    Additionally, the Wyoming Department of Environmental Quality, DEQ, has revised some standards for surface water discharge that have allowed the issuance of most of the permits that apply to the Cheyenne and Belle Fourche drainage areas. The Wyoming and Montana DEQs have reached agreement on procedures for discharging and monitoring water into the Powder River drainage areas, in which most of our Big George prospects are located. The Wyoming DEQ has begun to release permits on a limited basis to the Powder River drainage area in order to evaluate the impact, if any, of the discharges. The majority of wells on our acreage producing from the Wyodak formation drain into the Cheyenne and Belle Fourche drainage areas. We can make no assurance that the conditions under which additional permits will be granted will not impact the level of drilling or the timing of production.

    In addition to the revenues earned from the production of our coal bed methane gas, we also earn fees for gathering and transporting the natural gas. During the third quarter of 2001, we were gathering 284 MMcf per day of our own production and of other third-party producers. Of that volume, approximately 135 MMcf per day was transported through our MIGC pipeline.

    Our capital budget in this area provides for expenditures of approximately $69.8 million during 2001. This capital budget includes approximately $53.5 million for drilling costs for our interest in approximately 840 wells, production equipment and undeveloped acreage and $16.3 million for compression. Depending upon future drilling success, we may need to make additional capital expenditures to continue expansion in this basin. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that we will incur this level of capital expenditure. In the first nine months of 2001, capital expenditures in this area totaled $53.6 million.

    In 1998, we joined with other industry participants to form Fort Union Gas Gathering, L.L.C., to construct a 106-mile long, 24-inch gathering pipeline and treater to gather and treat natural gas in the Powder River basin in northeast Wyoming. We own a 13% equity interest in Fort Union and are the construction manager and field operator. The gathering header has a capacity of approximately 435 MMcf per day and in June 2001 it had throughput of approximately 310 MMcf per day. The header delivers coal bed methane gas to a treating facility near Glenrock, Wyoming and accesses interstate pipelines serving gas markets in the Rocky Mountain and Midwest regions of the United States. In 1999, we entered into a ten-year agreement for firm gathering services on 60 MMcf per day of capacity at $.14 per Mcf on Fort Union. In the fourth quarter of 2000, we and the other participants in the Fort Union Gas Gathering, L.L.C. approved an expansion of the system. Construction of the 62-mile expansion was completed in the third quarter of 2001 and increased the system capacity by an additional 200 MMcf per day. The expansion costs totaled approximately $21.5 million and were project financed. We shall invest approximately $500,000 as an equity contribution to Fort Union in conjunction with the expansion. Also in connection with the expansion, we increased our commitment for firm gathering services by an additional 23 MMcf per day of capacity at $.14 per Mcf.

    Southwest Wyoming.  Our facilities in southwest Wyoming are comprised of the Granger and Lincoln Road facilities, or collectively the Granger Complex, and our Red Desert facility. These facilities have a combined operational capacity of 327 MMcf per day and processed an average of 160 MMcf per day in the first nine months of 2001. Our capital budget in this area provides for expenditures of approximately $37.7 million during 2001. This capital budget includes approximately $14.4 million for drilling costs and production equipment and approximately $23.3 million related to the gathering systems and plant facilities. Due to drilling and regulatory uncertainties that are beyond our control, there can be no assurance that we will incur this level of capital expenditure. During the first nine months of 2001, we expended $15.6 million in this area, which includes the purchase of the remaining 50% interest in the Bird Canyon gathering system serving the Granger Complex.

    In September 2001, we signed an agreement with Questar Gas Management Company for the sale of a 50% interest in a segment of the Bird Canyon gathering system along with associated field compression for $5.2 million. This sale closed in October 2001. Also in October 2001, both Questar and we contributed our respective interests in the Bird Canyon system along with additional field compression and gathering dedications for gas produced along the Pinedale anticline portion of the Hoback basin to a newly formed joint venture named Rendezvous Gas Services, L.L.C. Each company owns a 50% interest in Rendezvous and we will serve as field operator of its systems. In the fourth quarter of 2001, Rendezvous will begin construction of additional gas pipeline and compression facilities with a capacity to transport approximately 275 MMcf per day of gas production from the Pinedale anticline. This gas will be delivered for blending or processing at either our Granger Complex or at a Questar processing facility. The total estimated construction cost of the new pipeline and compression facilities is $15.5 million, of which our share will be $7.8 million.

    Under a 1997 agreement, we participate in approximately 246,000 gross acres, or approximately 36,000 net acres, in the Jonah and Hoback basins. Year to date through October 31, 2001, we participated in 36 gross wells, or 5 net wells, in these areas and we expect to participate in the drilling of four more gross wells, or one net well, in the remainder of 2001. The expected drilling and completion costs per gross well are approximately $2.4 million to $3.5 million and the average well depth in this area approximates 13,000 feet. Our average finding and development costs are estimated to be $0.57 per Mcf. We have established proven developed and undeveloped reserves totaling 52 Bcf at December 31, 2000. This represents a 73% increase as compared to December 31, 1999. As of June 30, 2001, we estimate a net total of 102 Bcf of probable and possible reserves on an unrisked basis associated with undeveloped acreage in this area. There can be no assurance, however, as to the ultimate recovery of these reserves.

Financing Facilities

    Revolving Credit Facility.  The Revolving Credit Facility is with a syndicate of banks and provides for a maximum borrowing commitment of $250 million consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A, and a $167 million Revolving Credit Facility, or Tranche B, which matures on April 30, 2004. At September 30, 2001, no amounts were outstanding under this facility. The Revolving Credit Facility bears interest at certain spreads over the Eurodollar rate, or the greater of the Federal Funds rate or the agent bank's prime rate. We have the option to determine which rate will be used. We also pay a facility fee on the commitment. The interest rate spreads and facility fee are adjusted based on our debt to capitalization ratio and range from .75% to 2.00%. At September 30, 2001, the interest rate payable on any borrowings under this facility would have been 3.6%. We are required to maintain a total debt to capitalization ratio of not more than 55%, and a senior debt to capitalization ratio of not more than 40% through December 31, 2001 and of not more than 35% thereafter. The agreement also requires a quarterly test of the ratio of EBITDA (excluding some non-recurring items) for the last four quarters, to interest and dividends on preferred stock for the same period. The ratio must exceed 1.80 to 1.0 through September 30, 2001 and increases periodically to 3.25 to 1.0 by December 31, 2002. This facility is guaranteed and secured via a pledge of the stock of some of our subsidiaries.

    Master Shelf Agreement.  In December 1991, we entered into a Master Shelf Agreement with The Prudential Insurance Company of America. Amounts outstanding under the Master Shelf Agreement at September 30, 2001 are as indicated in the following table (dollars in thousands):

Issue Date	Amount		Interest Rate		Final Maturity	Principal Payments Due
October 27, 1992	$	25,000	7.99	%	October 27, 2003	$8,333 on each of October 27, 2001 through 2003
December 27, 1993		25,000	7.23	%	December 27, 2003	single payment at maturity
October 27, 1994		25,000	9.05	%	October 27, 2001	single payment at maturity
October 27, 1994		25,000	9.24	%	October 27, 2004	single payment at maturity
July 28, 1995		50,000	7.61	%	July 28, 2007	$10,000 on each of July 28, 2003 through 2007
	$	150,000

    Under our agreement with Prudential, we are required to maintain a current ratio, as defined therein, of at least .9 to 1.0, a minimum tangible net worth equal to the sum of $300 million plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of the net proceeds of any equity offerings after January 1, 1999, a total debt to capitalization ratio of not more than 60% through December 31, 2001 and of not more than 55% thereafter and a senior debt to capitalization ratio of not more than 40% through March 2002 and not more than 35% thereafter. This agreement also requires an EBITDA to interest ratio of not less than 3.25 to 1.0 increasing to a ratio of not less than 3.75 to 1.0 by March 31, 2002 and an EBITDA to interest on senior debt ratio of not less than 5.00 to 1.0 increasing to a ratio of not less than 5.50 to 1.0 by March 31, 2002. EBITDA in these calculations excludes certain non-recurring items. In addition, this agreement contains a calculation limiting dividends under which approximately $87.5 million was available at September 30, 2001. We are currently paying an annual fee of 0.50% on the amounts outstanding on the Master Shelf Agreement. This fee will continue until we receive an implied investment grade rating on our senior secured debt from Moody's Investors Service or Standard & Poor's. Borrowings under the Master Shelf Agreement are guaranteed and secured via a pledge of the stock of some of our subsidiaries.

    In October 2001, we made scheduled principal repayments to Prudential totaling $33.3 million. These repayments were made with funds available under the Revolving Credit Facility.

    Senior Subordinated Notes.  In 1999, we sold $155.0 million of Senior Subordinated Notes in a private placement with a final maturity of 2009 due in a single payment which were subsequently exchanged for registered publicly tradable notes under the same terms and conditions. The Senior Subordinated Notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%. These notes contain maintenance covenants that include limitations on debt incurrence, restricted payments, liens and sales of assets. Under the calculation limiting restricted payments, including common dividends, approximately $60.0 million was available at September 30, 2001. The Senior Subordinated Notes are unsecured and are guaranteed on a subordinated basis by some of our subsidiaries. We incurred approximately $5.0 million in offering commissions and expenses that have been capitalized and are being amortized over the term of the notes.

    Covenant Compliance.  We were in compliance with all covenants in our debt agreements at September 30, 2001. Taking into account all the covenants contained in these agreements, we had approximately $250 million of available borrowing capacity at September 30, 2001.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk Management Activities

    Our commodity price risk management program has two primary objectives. The first goal is to preserve and enhance the value of our equity volumes of gas and NGLs with regard to the impact of commodity price movements on cash flow, net income and earnings per share in relation to those anticipated by our operating budget. The second goal is to manage price risk related to our gas, crude oil and NGL marketing activities to protect profit margins. This risk relates to hedging fixed price purchase and sale commitments, preserving the value of storage inventories, reducing exposure to physical market price volatility and providing risk management services to a variety of customers.

    We utilize a combination of fixed price forward contracts, exchange-traded futures and options, as well as fixed index swaps, basis swaps and options traded in the over-the-counter, or OTC, market to accomplish these objectives. These instruments allow us to preserve value and protect margins because corresponding losses or gains in the value of the financial instruments offset gains or losses in the physical market.

    We use futures, swaps and options to reduce price risk and basis risk. Basis is the difference in price between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations.

    We enter into futures transactions on the New York Mercantile Exchange, or NYMEX, and the Kansas City Board of Trade and through OTC swaps and options with various counter parties, consisting primarily of financial institutions and other natural gas companies. We conduct our standard credit review of OTC counter parties and have agreements with these parties that contain collateral requirements. We generally use standardized swap agreements that allow for offset of positive and negative exposures. OTC exposure is marked-to-market daily for the credit review process. Our OTC credit risk exposure is partially limited by our ability to require a margin deposit from our major counter parties based upon the mark-to-market value of their net exposure. We are subject to margin deposit requirements under these same agreements. In addition, we are subject to similar margin deposit requirements for our NYMEX counter parties related to our net exposures.

    The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) equity volumes are less than expected, (ii) our customers fail to purchase or deliver the contracted quantities of natural gas or NGLs, or (iii) our OTC counter parties fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in these prices.

    For the fourth quarter of 2001, we have entered into hedging positions for approximately 82,000 MMbtus per day of our equity gas volumes at an average of $4.32 per MMbtu. These positions represent approximately 68 percent of our projected equity gas volumes in the quarter. For 2002, we have hedged approximately 80,000 MMbtus per day, or 57 percent of our projected 2002 equity gas production, with collar structures providing for an average minimum price of $3.81 per MMbtu and an average maximum price of $5.87 per MMbtu. These prices are NYMEX-equivalents.

    For the fourth quarter of 2001, we have purchased puts for 125,000 barrels per month of NYMEX monthly average settlement of $23.96 per barrel to hedge a portion of our equity production of natural gasoline, condensates, butanes and crude oil.

    For the fourth quarter of 2001, we have purchased puts for 125,000 barrels per month of OPIS Mt. Belvieu monthly average settlement of $.434 per gallon to hedge a portion of our equity production of propane.

    For the fourth quarter of 2001, we have purchased puts for 60,000 barrels per month of OPIS Mt. Belvieu monthly average settlement of $.3175 per gallon of purity ethane to hedge a portion of our equity production of ethane.

    We do not hold any crude oil or NGL futures, swaps or options for settlement beyond 2001.

    Foreign Currency Derivative Market Risk.  As a normal part of our business, we enter into physical gas transactions which are payable in Canadian dollars. We enter into forward purchases and sales of Canadian dollars from time to time to fix the cost of our future Canadian dollar denominated natural gas purchase, sale, storage and transportation obligations. This is done to protect marketing margins from adverse changes in the U.S. and Canadian dollar exchange rate between the time the commitment for the payment obligation is made and the actual payment date of such obligation. As of September 30, 2001, the net notional value of such contracts was approximately $21.6 million in Canadian dollars, which approximates its fair market value.

    Accounting for Derivative Instruments and Hedging Activities.  In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"), effective for us beginning on January 1, 2001. Under SFAS No. 133, which was subsequently amended by SFAS No. 138, we are required to recognize the change in the market value of all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction. Also on January 1, 2001, we adopted mark-to-market accounting for the remainder of our marketing activities which, for various reasons, are not designated or qualified as hedges under SFAS No. 133. Upon the adoption of SFAS No. 133 and mark-to-market accounting on January 1, 2001, the impact was a decrease in a component of stockholders' equity through Accumulated other comprehensive income of $22.5 million, an increase to Current assets of $52.6 million, an increase to Current liabilities of $86.9 million, an increase to Other long-term liabilities of $1.1 million and a decrease in Deferred income taxes payable of $12.9 million.

    Of the $22.5 million decrease to Accumulated other comprehensive income resulting from the January 1, 2001 adoption of SFAS No. 133, $19.4 million was reversed in the first nine months of 2001 with gains and losses from the underlying transactions recognized through operating income. An additional $2.6 million of this transition entry is currently anticipated to be recognized through operating income in the fourth quarter of 2001.

    The non-cash impact to our results of operations in the first nine months of 2001 resulting from the adoption of mark-to-market accounting for our marketing activities resulted in additional pre-tax income of $23.3 million.

Principal Facilities

    The following tables provide information concerning our principal facilities at September 30, 2001. We also own and operate several smaller treating, processing and transportation facilities located in the same areas as our other facilities.

						Average for the Nine Months Ended September 30, 2001
				Gas Gathering System Miles(2)	Gas Throughput Capacity (MMcf/D)(3)
Plant Facilities(1)			Year Placed In Service			Gas Throughput (MMcf/D)(4)	Gas Production (MMcf/D)(5)	NGL Production (MGal/D)(5)
Texas
	Gomez Treating		1971	385	280	101	92	—
	Midkiff/Benedum		1949	2,173	165	147	96	888
	Mitchell Puckett Gathering		1972	90	120	76	49	—
Louisiana
	Toca(7)(8)		1958	—	160	135	129	108
Wyoming
	Coal Bed Methane Gathering		1990	444	223	268	247	—
	Fort Union Gas Gathering		2000	106	450	289	289	—
	Granger(7)(9)(10)(14)		1987	482	235	154	131	286
	Hilight Complex(7)		1969	626	80	63	57	72
	Kitty/Amos Draw(7)		1969	314	17	9	6	37
	Lincoln Road(10)		1988	149	50	18	16	31
	Newcastle(7)		1981	146	5	3	2	19
	Red Desert(7)		1979	111	42	15	13	27
	Reno Junction(9)		1991	—	—	—	—	95
Oklahoma
	Chaney Dell		1966	2,054	130	71	56	221
	Westana		1981	871	45	63	58	23
New Mexico
	San Juan River(6)		1955	140	60	24	20	17
Utah
	Four Corners Gathering		1988	104	15	2	2	6
		Total		8,195	2,077	1,438	1,263	1,830

				Average for the Nine Months Ended September 30, 2001
Transportation Facilities(1)		Year Placed In Service	Transportation Miles(2)	Pipeline Capacity (MMcf/D)(2)	Gas Throughput (MMcf/D)(4)
MIGC(11)(13)		1970	245	130	183
MGTC(12)		1963	252	18	8
	Total		497	148	191

(1)

Our interest in all facilities is 100% except for Midkiff/Benedum (73%), Newcastle (50%) and Fort Union Gas Gathering (13%). We operate all facilities and all data includes our interests and the interests of other joint interest owners and producers of gas volumes dedicated to the facility. Unless otherwise indicated, all facilities shown in the table are gathering and processing facilities.

(2)

Gas gathering system miles, interconnect and transportation miles, and pipeline capacity are as of September 30, 2001.

(3)

Gas throughput capacity is as of September 30, 2001 and represents capacity in accordance with design specifications unless other constraints exist, including permitting or field compression limits.

(4)

Aggregate wellhead natural gas volumes collected by a gathering system or volumes transported by a pipeline.

(5)

Volumes of gas and NGLs are allocated to a facility when a well is connected to that facility; volumes exclude NGLs fractionated for third parties.

(6)

Sour gas facility (capable of processing or treating gas containing hydrogen sulfide and/or carbon dioxide).

(7)

Fractionation facility (capable of fractionating raw NGLs into end-use products).

(8)

Straddle plant, or a plant located near a transportation pipeline that processes gas dedicated to or gathered by a pipeline company or another third party.

(9)

NGL production includes conversion of third-party feedstock to iso-butane.

(10)

We are currently processing all gas gathered through the Lincoln Road gathering system at our Granger facility.

(11)

MIGC is an interstate pipeline located in Wyoming and is regulated by the Federal Energy Regulatory Commission.

(12)

MGTC is a public utility located in Wyoming and is regulated by the Wyoming Public Service Commission.

(13)

Pipeline capacity represents capacity at the Powder River junction only and does not include northern delivery points.

(14)

A 50% interest in the Bird Canyon gathering system servicing the Granger facility was sold in October 2001. Also in October 2001, the remaining 50% interest in this system was contributed to a newly formed joint venture, Rendezvous Gas Services, L.L.C.

PART II—OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Western Gas Resources, Inc., v. Amerada Hess Corporation, District Court, Denver County, Colorado, Civil Action No. 00-CV-1433. We were a defendant in prior litigation, styled as Berco Resources, Inc. v. Amerada Hess Corporation and Western Gas Resources, Inc., United States District Court, District of Colorado, Civil Action No. 97-WM-1332, which was settled in 2000 for an amount which did not have a material impact on our financial position or results of operations. We are seeking reimbursement from Amerada Hess under a contractual indemnity. We amended our original complaint and requested a jury trial in this case. Amerada Hess filed a new complaint based upon the same factual issues as the original complaint and these cases were consolidated and are set for trial in June 2002. Both parties have filed cross motions for summary judgment.

Barrett Resources Corporation and Lance Oil & Gas Company, Inc. (together the Plaintiffs) v. Westport Oil and Gas Company, Inc., (Defendant) Civil Action No. 00CV6973, District Court, City and County of Denver, Colorado. On September 15, 2000, Plaintiffs, including our subsidiary Lance Oil & Gas Company, filed a complaint for damages and declaratory relief related to a dispute arising under a Farmout Agreement between the parties dated September 26, 1995, as amended. The dispute centers on Plaintiffs' alleged delay of drilling of wells on a portion of the acreage covered by the Farmout Agreement. In October 2000, Defendant counterclaimed that the Farmout Agreement was terminated due to Plaintiffs' alleged delay of drilling. In July 2001, Plaintiffs notified Defendant of the commencement of drilling eleven wells on the acreage covered by the Farmout Agreement. In August 2001, Defendant filed supplemental counterclaims which included claims for trespass, conversion, accounting and constructive trust on the eleven wells drilled by Plaintiff and compensatory and exemplary damages in connection with these wells. A trial for this case is set for December 3, 2001 and the parties are currently proceeding with discovery. We intend to vigorously defend against the counterclaims but cannot express an opinion as to the outcome of this litigation. We believe that any unfavorable outcome will not have a material adverse effect on our financial position or results of operations.

    Other.  We are involved in various other litigation and administrative proceedings arising in the normal course of our business. In the opinion of management, any liabilities that may result from these claims will not, individually or in the aggregate, have a material adverse effect on our financial position or results of operations.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

    None.

Item 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)

Exhibits:

3.3	Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on October 12, 2001.
10.7	Revised 2001 Employment Agreement by and between Western Gas Resources, Inc. and officers.
10.27	Consultation Agreement by and between Western Gas Resources, Inc. and Larry F. Outlaw dated November 1, 2001.
10.28	Employment Agreement by and between Western Gas Resources, Inc. and Peter A. Dea, with Exhibits thereto dated October 15, 2001.

(b)

Reports on Form 8-K:

    A report was filed on October 17, 2001 announcing the appointment of Mr. Peter A. Dea to the position of President, Chief Executive Officer and Director effective November 1, 2001 and the promotion of William J. Krysiak to the position of Chief Financial Officer effective October 15, 2001.

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: November 12, 2001	By:	/s/ PETER A. DEA Peter A. Dea Chief Executive Officer and President
Date: November 12, 2001	By:	/s/ WILLIAM J. KRYSIAK William J. Krysiak Chief Financial Officer (Principal Financial and Accounting Officer)