WESTERN GAS RESOURCES INC - 10-Q Quarterly Report

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Western Gas Resources, Inc. Form 10-Q Table of Contents

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002 OR
o	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 ý No o

Indicate by check mark whether registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ý No o

On November 1, 2002, there were 33,034,114 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, 2002 and December 31, 2001
		Consolidated Statement of Cash Flows—Nine Months Ended September 30, 2002 and 2001
		Consolidated Statement of Operations—Three and Nine Months EndedSeptember 30, 2002 and 2001
		Consolidated Statement of Changes in Stockholders' Equity—Nine Months Ended September 30, 2002
		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
	Item 4.	Controls and Procedures
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, 2002			December 31, 2001
			(unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	6,365		$	10,032
	Trade accounts receivable, net			256,608			231,724
	Product inventory			44,408			50,773
	Parts inventory			43			3,049
	Assets from price risk management activities			37,501			66,271
	Assets held for sale			3,250			—
	Other			18,173			4,114

		Total current assets		366,348			365,963
Property and equipment:
	Gas gathering, processing and transportation			900,172			912,003
	Oil and gas properties and equipment (successful efforts method)			231,077			193,656
	Construction in progress			108,015			106,385

				1,239,264			1,212,044
Less: Accumulated depreciation, depletion and amortization				(392,761	)		(363,737	)

		Total property and equipment, net		846,503			848,307

Other assets:
	Gas purchase contracts (net of accumulated amortization of $36,756 and $35,329, respectively)			31,399			32,826
	Assets from price risk management activities			1,316			2,934
	Other			25,283			17,912

	Total other assets			57,998			53,672

Total assets			$	1,270,849			1,267,942

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	233,409		$	260,208
	Accrued expenses			47,507			23,123
	Liabilities from price risk management activities			16,575			18,075
	Dividends payable			3,781			3,767

		Total current liabilities		301,272			305,173
Long-term debt				357,167			366,667
Liabilities from price risk management activities				2,338			1,720
Other long-term liabilities				1,856			2,284
Deferred income taxes payable, net				120,927			118,746

Total liabilities				783,560			794,590

Stockholders' equity:
	Preferred Stock; 10,000,000 shares authorized:
		$2.28 cumulative preferred stock, par value $.10; 591,136 issued and outstanding. ($15,885,650 aggregate liquidation preference)		59			59
		$2.625 cumulative convertible preferred stock, par value $.10; 2,760,000 issued and outstanding ($138,000,000 aggregate liquidation preference)		276			276
	Common stock, par value $.10; 100,000,000 shares authorized; 33,027,318 and 32,689,009 shares issued, respectively			3,326			3,293
	Treasury stock, at cost; 25,016 common shares and 44,290 $2.28 cumulative preferred shares in treasury			(1,907	)		(1,907	)
	Additional paid-in capital			393,906			387,505
	Retained earnings			89,941			66,128
	Accumulated other comprehensive income			1,983			18,882
	Notes receivable from key employees secured by common stock			(295	)		(884	)

		Total stockholders' equity		487,289			473,352

Total liabilities and stockholders' equity			$	1,270,849		$	1,267,942

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,
		2002			2001
Reconciliation of net income to net cash provided by operating activities:
Net income		$	35,153		$	84,816
Add income items that do not affect cash:
	Depreciation, depletion and amortization		54,002			47,018
	(Gain) loss on the sale of property and equipment		644			(10,653	)
	Distributions (less than) in excess of equity income, net		(1,727	)		912
	Foreign currency translation adjustments		429			(1,698	)
	Deferred income taxes		14,602			36,326
	Non-cash change in fair value of derivatives		2,733			(23,288	)
	Other non-cash items, net		1,992			(924	)
	Adjustments to working capital to arrive at net cash provided by operating activities:
	(Increase) decrease in trade accounts receivable		(23,276	)		353,634
	(Increase) decrease in product inventory		6,238			(14,974	)
	Decrease in parts inventory		—			429
	(Increase) decrease in other current assets		(15,892	)		2,064
	(Increase) decrease in other assets and liabilities, net		373			(126	)
	Decrease in accounts payable		(26,399	)		(345,333	)
	Increase in accrued expenses		23,993			16,336

Net cash provided by operating activities			72,865			144,539

Cash flows from investing activities:
	Purchases of property and equipment		(87,784	)		(114,683	)
	Proceeds from the dispositions of property and equipment		33,404			38,075
	Contributions to equity investments		(7,637	)		(783	)

Net cash used in investing activities			(62,017	)		(77,391	)

Cash flows from financing activities:
	Net proceeds from exercise of common stock options		6,434			4,777
	Repurchase of $2.28 cumulative preferred stock		—			(129	)
	Debt issue costs paid		(123	)		(97	)
	Payments on revolving credit facility		(732,780	)		(355,000	)
	Borrowings under revolving credit facility		723,280			301,300
	Dividends paid		(11,326	)		(12,629	)

Net cash used in financing activities			(14,515	)		(61,778	)

Net increase (decrease) in cash and cash equivalents			(3,667	)		5,370
Cash and cash equivalents at beginning of period			10,032			12,927

Cash and cash equivalents at end of period		$	6,365		$	18,297

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,
			2002			2001			2002			2001
Revenues:
	Sale of residue gas		$	510,764		$	545,656		$	1,566,551		$	2,350,246
	Sale of natural gas liquids			85,214			94,865			229,888			338,834
	Processing and transportation revenue			17,007			10,418			47,466			41,042
	Unrealized gain (loss) on marketing activities			396			21,112			(2,733	)		23,288
	Other, net			1,842			1,734			5,747			4,675

		Total revenues		615,223			673,785			1,846,919			2,758,085

Costs and expenses:
	Product purchases			529,911			594,452			1,602,806			2,465,602
	Plant operating expense			20,824			18,875			59,485			54,152
	Oil and gas exploration and production expense			7,553			5,514			24,084			24,217
	Depreciation, depletion and amortization			18,813			17,257			54,002			47,018
	(Gain) loss on sale of assets			562			570			644			(10,653	)
	Selling and administrative expense			8,061			7,715			28,639			23,739
	Interest expense			6,858			6,132			20,288			18,953

		Total costs and expenses		592,582			650,515			1,789,948			2,623,028

Income before income taxes				22,641			23,270			56,971			135,057
Provision for income taxes:
	Current			2,507			68			7,216			13,915
	Deferred			6,747			8,429			14,602			36,326

		Total provision for income taxes		9,254			8,497			21,818			50,241

Net income				13,387			14,773			35,153			84,816
Preferred stock requirements				(2,130	)		(2,584	)		(6,390	)		(7,753	)

Income attributable to common stock			$	11,257		$	12,189		$	28,763		$	77,063

Earnings per share of common stock			$	..34		$	..37		$	..87		$	2.37

Weighted average shares of common stock outstanding				33,010,914			32,657,637			32,921,846			32,547,397

Income attributable to common stock—fully diluted			$	11,257		$	12,189		$	28,763		$	82,497

Earnings per share of common stock—fully diluted			$	..34		$	..36		$	..86		$	2.23

Weighted average shares of common stock outstanding—fully diluted				33,589,743			33,572,836			33,580,658			36,992,899

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

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN 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 Earnings			Accumulated Other Comprehensive Income Net of Tax			Notes Receivable from Key Employees			Total Stockholders' Equity
Balance at December 31, 2001			591,136	44,290	2,760,000	32,689,009	25,016	$	59	$	276	$	3,293	$	(1,907	)	$	387,505	$	66,128		$	18,882		$	(884	)	$	473,352
Comprehensive income:
	Net income, nine months ended September 30, 2002		—	—	—	—	—		—		—		—		—			—		35,153			—			—			35,153
	Translation adjustments		—	—	—	—	—		—		—		—		—			—		—			429			—			429
	Reclassification adjustment for settled contracts		—	—	—	—	—		—		—		—		—			—		—			(13,499	)		—			(13,499	)
	Changes in fair value of outstanding hedging positions		—	—	—	—	—		—		—		—		—			—		—			(2,120	)		—			(2,120	)
	Reduction due to estimated ineffectiveness		—	—	—	—	—		—		—		—		—			—		—			(12	)		—			(12	)
	Fair value of new hedge positions		—	—	—	—	—		—		—		—		—			—		—			(1,697	)					(1,697	)

		Change in accumulated derivative comprehensive income	—	—	—	—	—		—		—		—		—			—		—			(17,328	)		—			(17,328	)

	Total comprehensive income, net of tax																												17,890

Stock options exercised			—	—	—	338,309	—		—		—		33		—			6,213		—			—			—			6,246
Effect of re-priced stock options			—	—	—	—	—		—		—		—		—			188		—			—			—			188
Loans forgiven			—	—	—	—	—		—		—		—		—			—		—			—			589			589
Dividends declared on common stock			—	—	—	—	—		—		—		—		—			—		(4,950	)		—			—			(4,950	)
Dividends declared on $2.28 cumulative preferred stock			—	—	—	—	—		—		—		—		—			—		(957	)		—			—			(957	)
Dividends declared on $2.625 cumulative convertible preferred stock			—	—	—	—	—		—		—		—		—			—		(5,433	)		—			—			(5,433	)
Repurchase of $2.28 cumulative preferred stock			—	—	—	—	—		—		—		—		—			—		—			—			—			—

Balance at September 30, 2002			591,136	44,290	2,760,000	33,027,318	25,016	$	59	$	276	$	3,326	$	(1,907	)	$	393,906	$	89,941		$	1,983		$	(295	)	$	487,289

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, 2001. The interim consolidated financial statements as of September 30, 2002 and for the three and nine-month periods ended September 30, 2002 and 2001 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, 2002 are not necessarily indicative of the results of operations expected for the year ended December 31, 2002.

Prior years' amounts in the interim consolidated financial statements and notes have been reclassified as appropriate to conform to the presentation used in 2002.

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 $2.1 million and $2.6 million for the three months ended September 30, 2002 and 2001, respectively, and $6.4 million and $7.8 million, respectively, for the nine month period ended September 30, 2002 and 2001. 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 578,829 and 915,199 for the three months ended September 30, 2002 and 2001, respectively, and by 658,812 and 4,445,502 for the nine months ended September 30, 2002 and 2001, respectively. The numerators and the denominators for these periods were adjusted to reflect these potential shares in calculating fully diluted earnings per share.

OTHER INFORMATION

Bethel Treating Facility. In December 2000, we signed an agreement 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 $12.1 million in the first quarter of 2001.

Westana. In February 2001, 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 2001 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 2001, the results of these operations are fully consolidated and are included in Revenues and Costs and expenses.

Granger Complex. In May 2001, we acquired the remaining 50% interest in a portion of a gathering system serving the Granger Complex for a net purchase price of $5.9 million in cash and the settlement of previously disclosed litigation.

Toca Processing Facility. In June 2002, we entered into an agreement for the sale of our Toca processing facility in Louisiana. This sale closed on September 24, 2002. The sale price was $32.2 million, subject to accounting adjustments, and resulted in a pre-tax loss of approximately $448,000. The purchase price included a natural gas processing plant with a capacity of 160 million cubic feet per day and a fractionator that can separate 14,200 barrels per day of mixed natural gas liquids into propane, normal butane, iso-butane and natural gasoline. The purchase also includes NGL storage as well as truck, rail and barge loading facilities, which support the complex. During the third quarter and nine months ended September 30, 2002, this facility generated net after-tax earnings of approximately $149,000, or $.01 per share of common stock, and $683,000, or $.02 per share of common stock, respectively. We believe the results from this facility are immaterial for separate presentation as a discontinued operation. Approximately $15.0 million of the proceeds received from this asset sale were initially used to reduce amounts outstanding on our Revolving Credit Facility. The remaining amount of $17.2 million is on deposit with a trustee in anticipation of the completion of a like-kind exchange transaction. This deposit is reflected on the Consolidated Balance Sheet under the caption Other current assets. We are uncertain as to our ability to identify a qualifying asset and complete the like-kind exchange. If a like-kind exchange transaction is not completed within the prescribed time period, this amount will also be used to reduce amounts outstanding on our Revolving Credit Facility.

Corporate Offices. In August 2002, we entered into a seven-year and nine-month agreement for the lease of approximately 85,000 square feet of office space in Denver, Colorado. The cumulative lease payments over the term of this agreement will total $12.0 million. Our corporate offices will be relocated to this space in the first quarter of 2003. We intend to sell the 52,000 square foot office building we currently occupy. The office building is reflected as an Asset held for sale at September 30, 2002.

Officer Loans. In 1989, we loaned to our officers at that time, an amount sufficient to exercise their options under our stock option plans. The loans and accrued interest were to be forgiven if the officer remained employed by us for specified time periods and upon a resolution of the board of directors. In May and July 2002, we forgave loans related to 37,500 shares of Common Stock totaling $636,000. After giving effect to the forgiveness, loans related to 37,500 shares of Common Stock in the amount of $637,000 remain outstanding. Pursuant to the terms of agreements entered into in 2001, the remaining loans will be forgiven in December 2002 and May 2003.

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 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 that, for various reasons, are not designated or qualified as hedges under SFAS No. 133.

The net gain recognized in earnings through Sale of residue gas and Sale of natural gas liquids during the first nine months of 2002 from hedging activities was $19.2 million. This is net of a loss of $154,000 resulting from hedge ineffectiveness due to the use of crude oil swaps in hedging the variability in the sales price of normal butane. Overall, our hedges are expected to continue to be "highly effective" under SFAS No. 133 in the future and no gains or losses were reclassified into earnings as a result of the discontinuance of cash flow hedges.

The gains and losses currently reflected in Accumulated other comprehensive income will be reclassified to earnings based on the actual sales of the hedged gas or NGLs. Based on prices as of September 30, 2002, approximately $600,000 of gains in Accumulated other comprehensive income will be reclassified to earnings in the next twelve months with the remainder reclassified by the end of 2003.

SUPPLEMENTARY CASH FLOW INFORMATION

Interest paid was $17.2 million and $18.5 million for the nine months ended September 30, 2002 and 2001, respectively.

Estimated tax payments of $.6 million and $14.5 million were made during the nine months ended September 30, 2002 and 2001, respectively.

SEGMENT REPORTING

We operate in four principal business segments, as follows: Gas Gathering, Processing and Treating; Exploration and Production; Marketing; and Transportation. Management separately monitors these segments for performance against its internal forecast and these segments 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.

Gas Gathering, Processing and Treating. In this segment, we connect producers' wells (including those of the 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. In certain areas, where no processing is required, we gather and compress producers' gas and deliver it to pipelines. Except for volumes taken in kind by our producers, the Marketing segment sells the residue gas and NGLs extracted at most of our facilities. In this segment, we recognize revenue for our services at the time the service is performed.

Substantially all gas flowing through our gathering, processing and treating facilities is supplied under three types of contracts providing for the purchase, gathering, processing or treating of natural gas for periods ranging from one month to twenty years. The majority of these contracts have terms exceeding five years. Approximately 61% of our plant facilities' gross margins, or revenues at the plants less product purchases, for the month of September 2002 resulted from percentage-of-proceeds agreements in which we are typically responsible for the marketing of the gas and NGLs. We pay producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs. This type of contract allows the producers and us to share proportionally in price changes.

Approximately 24% of our plant facilities' gross margins for the month of September 2002 resulted from contracts that are primarily fee-based from which we receive a set fee for each Mcf of gas gathered and/or processed. This type of contract provides us with a steady revenue stream that is not dependent on commodity prices, except to the extent that low prices may cause a producer to delay drilling or curtail existing production. The proportion of fee-based contracts is expected to increase as the volumes gathered from the Powder River Basin coal bed methane development increase.

Approximately 15% of our plant facilities' gross margins for the month of September 2002 resulted from contracts that combine gathering, compression or processing fees with "keep whole" arrangements or wellhead purchases. Typically, we charge producers a gathering and compression fee based upon volume. In addition, we retain the NGLs recovered by the processing facility and keep the producers whole by returning to the producers at the tailgate of the plant an amount of residue gas equal on a Btu basis to the natural gas received at the plant inlet. The "keep whole" component of the contracts permits us to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, we are adversely affected when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream.

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

Marketing. Our Marketing segment buys and sells gas and NGLs in the United States and Canada from and to a variety of customers. The marketing of products purchased from third parties typically results in low operating margins relative to the sales price. In addition, this segment also markets gas and NGLs produced by our gathering, processing, treating and production assets. Also included in this segment are our Canadian marketing operations (which are immaterial for separate presentation). In this segment, revenues for sales of product are recognized at the time the gas or NGLs are delivered to the customer and are sensitive to changes in the market prices of the underlying commodities. We sell our products under agreements with varying terms and conditions in order to match seasonal and other changes in demand. The duration of our sales contracts have an average tenor of 15 months. We record revenues on our gas and NGL marketing activities on a gross sales versus sales net of purchases basis as we obtain title to all of the gas and NGLs that we buy including third-party purchases, and bear the risk of loss and credit exposure on these transactions. Additionally, for our marketing activities we utilize mark-to-market accounting. Under mark-to-market accounting, the expected margin to be realized over the term of the transaction is recorded in the month of origination. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods.

Transportation. 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 for our Marketing segment and other third parties. In this segment, we realize revenue on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline. Our firm capacity contracts range in duration from one month to six years.

Corporate. Included in the Corporate column are gains and (losses) associated with our equity gas and NGL hedging program of approximately $6.9 million and $10.6 million for the three months ended September 30, 2002 and September 30, 2001, respectively, and approximately $19.2 million and $(5.4) million for the nine months ended September 30, 2002 and 2001, respectively.

The following table sets forth our segment information as of and for the three and nine months ended September 30, 2002 and 2001 (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			Transportation		Corporate			Eliminating Entries			Total
Quarter ended September 30, 2002
Revenues from unaffiliated customers	$	15,875	$	1,426	$	588,881		$	1,088	$	1		$	—		$	607,271
Interest income		—		8		—			—		2,328			(2,280	)		56
Equity hedges		—		—		—			—		6,886			—			6,886
Other, net		531		9		(88	)		14		544			—			1,010
Inter-segment sales		153,125		26,434		8,141			3,716		14			(191,430	)		—

Total revenues		169,531		27,877		596,934			4,818		9,773			(193,710	)		615,223

Product purchases		124,482		1,425		587,107			998		(172	)		(183,929	)		529,911
Plant operating expense		19,516		70		79			762		501			(104	)		20,824
Oil and gas exploration and production expense		—		15,814		—			—		—			(8,261	)		7,553

Operating profit	$	25,533	$	10,568	$	9,748		$	3,058	$	9,444		$	(1,416	)	$	56,935

Depreciation, depletion and amortization		10,584		6,124		40			425		1,632			—			18,813
Interest expense																	6,858
Loss on sale of assets																	562
Selling and administrative expense																	8,061

Income before income taxes																$	22,641

Identifiable assets	$	573,605	$	220,502	$	82		$	43,378	$	52,015		$	—		$	889,582

	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
Equity hedges		—		—		—			—			10,647			—			10,647
Other, net		—		—		21,112			—			(1,665	)		—			30,094
Inter-segment revenues		130,817		17,213		18,245			4,279			14			(170,568	)		—

Total revenues		157,695		18,185		650,509			5,446			12,813			(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

Operating profit	$	25,672	$	6,240	$	8,892		$	3,024		$	12,598		$	(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			Transportation		Corporate			Eliminating Entries			Total
Nine months ended September 30, 2002
Revenues from unaffiliated customers	$	44,948	$	1,296	$	1,774,649		$	7,313	$	123		$	—		$	1,828,329
Interest income		—		32		10			—		6,223			(6,106	)		159
Equity hedges		—		—		—			—		19,167			—			19,167
Other, net		1,195		28		(3,522	)		28		1,535			—			(736	)
Inter-segment sales		435,065		75,344		17,567			11,573		41			(539,590	)		—

Total revenues		481,208		76,700		1,788,704			18,914		27,089			(545,696	)		1,846,919

Product purchases		357,306		5,029		1,757,265			998		(4	)		(517,788	)		1,602,806
Plant operating expense		53,312		203		211			6,211		499			(951	)		59,485
Oil and gas exploration and production expense		—		44,395		—			—		—			(20,311	)		24,084

Operating profit	$	70,590	$	27,073	$	31,228		$	11,705	$	26,594		$	(6,646	)	$	160,544

Depreciation, depletion and amortization		32,082		15,690		121			1,272		4,837			—			54,002
Interest expense																	20,288
Loss on sale of assets																	644
Selling and administrative expense																	28,639

Income before income taxes																$	56,971

Identifiable assets	$	573,605	$	220,502	$	82		$	43,378	$	52,015		$	—		$	889,582

	Gas Gathering and Processing		Exploration and Production			Marketing		Transportation			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
Equity hedges		—		—			—		—			(5,323	)		—			(5,323	)
Other, net		4		(1	)		23,314		2			788			—			18,784
Inter-segment revenues		668,620		98,780			38,856		12,937			41			(819,234	)		—

Total revenues		725,703		100,580			2,731,975		19,090			8,085			(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

Operating profit	$	105,665	$	56,283		$	42,559	$	12,836		$	7,809		$	(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	$	585,158	$	171,596		$	80	$	47,565		$	62,154		$	—		$	866,553

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In June 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement Obligations." 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 are in the process of determining our asset retirement costs in accordance with SFAS No. 143. We have not yet determined the impact that the adoption of SFAS No. 143 will have on our earnings or financial position.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FAS Statements No. 4, 44 and 64, Amendment of FAS Statement No. 13, and Technical Corrections," which is generally effective for transactions occurring after May 15, 2002. Through the rescission of FAS Statements 4 and 64, SFAS No. 145 eliminates the requirement that gains and losses from extinguishment of debt be aggregated and, if material, be classified as an extraordinary item net of any income tax effect. SFAS No. 145 made several other technical corrections to existing pronouncements that may change accounting practice. We do not believe SFAS No. 145 will have a material impact on our earnings or financial position.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. This statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force, or EITF, Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." We do not believe that SFAS No. 146 will have a material impact on our earnings or financial position.

At an October 25, 2002 special meeting of the EITF, a consensus was reached to rescind EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." This impact of this decision is to preclude mark-to-market accounting for all energy trading contracts not within the scope of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities. " The EITF also reached a consensus that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. The consensus regarding the rescission of Issue 98-10 is applicable for fiscal periods beginning after December 15, 2002. Energy trading contracts not within the scope of SFAS No. 133 purchased after October 25, 2002, but prior to the implementation of the consensus are not permitted to apply mark-to-market accounting. We do not believe that this action by the EITF will have a material impact on our earnings or financial position.

LEGAL PROCEEDINGS

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

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, 2002 and 2001. Prior year amounts have been reclassified as appropriate to conform to the presentation used in 2002. 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 or the oil and gas 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, 2002 compared to the three and nine months ended September 30, 2001
(Dollars in thousands, except per share amounts and operating data).

	Three Months Ended September 30,								Nine Months Ended September 30,
	Three Months Ended September 30,						Percent Change		Nine Months Ended September 30,						Percent Change
	2002			2001			Percent Change		2002			2001			Percent Change
Financial results:
Revenues	$	615,223		$	673,785		(9	)	$	1,846,919		$	2,758,085		(33	)
Gross profit		37,560			37,117		1			105,898			177,749		(40	)
Net income		13,387			14,773		(9	)		35,153			84,816		(59	)
Income per share of common stock		.34			.37		(8	)		.87			2.37		(63	)
Income per share of common stock—fully diluted		.34			.36		(6	)		.86			2.23		(61	)
Cash provided by operating activities	$	4,627		$	6,241		(26	)	$	72,865		$	144,539		(50	)
Cash provided by (used in) investing activities	$	1,956		$	(40,290	)	105		$	(62,017	)	$	(77,391	)	20
Cash used in financing activities	$	(27,946	)	$	(4,068	)	(587	)	$	(14,515	)	$	(61,778	)	77
Operating data:
Average gas sales (MMcf/D)		2,001			2,130		(6	)		2,098			1,880		12
Average NGL sales (MGal/D)		2,219			2,335		(5	)		2,098			2,315		(9	)
Average gas prices ($/Mcf)	$	2.77		$	2.77		—		$	2.73		$	4.57		(40	)
Average NGL prices ($/Gal)	$	.42		$	.44		(5	)	$	.40		$	.53		(25	)

Net income decreased $1.4 million and $49.7 million for the three and nine months ended September 30, 2002, respectively, compared to the same periods in 2001. The decrease in net income for the nine months ended September 30, 2002 is primarily attributable to significantly lower gas and NGL prices in this period as compared to the same period last year and lower margins per unit earned in our Marketing segment. These decreases more than offset increased production from the Powder River Basin coal bed methane development.

Revenues from the sale of gas decreased $34.9 million to $510.8 million for the three months ended September 30, 2002 compared to the same period in 2001. This decrease was due to a decline in the volume of product sold in 2002. Average gas prices realized by us remained constant at $2.77 per Mcf for the quarters ended September 30, 2002 and 2001. Included in the realized gas price were approximately $8.6 million of gains recognized in the three months ended September 30, 2002 related to futures positions on equity gas volumes. We have entered into additional futures positions for the majority of our equity gas for the remainder of 2002 and 2003. Average gas sales volumes decreased by 130 MMcf per day for the quarter ended September 30, 2002 compared to the same period in 2001. This decrease was primarily due to a decrease in the volume of third-party product sold which was partially offset by an increase in gas produced from our Powder River Basin development.

Revenues from the sale of gas decreased $783.7 million to $1,566.6 million in the nine months ended September 30, 2002 compared to the same period in 2001. This decrease was primarily due to a decline in product prices, which more than offset an increase in sales volume in the nine months ended September 30, 2002. Average gas prices realized by us decreased $1.84 per Mcf to $2.73 per Mcf in the nine months ended September 30, 2002 compared to the same period in 2001. Included in the realized gas price were approximately $24.9million of gains recognized in the nine months ended September 30, 2002 related to futures positions on equity gas volumes. Average gas sales volumes increased approximately 220 MMcf per day to 2,098 MMcf per day in the nine months ended September 30, 2002 compared to the same period in 2001 primarily due to an increase in the sale of third-party product and to a lesser extent an increase in gas produced from our Powder River Basin development.

Revenues from the sale of NGLs decreased $9.7 million to $85.2 million in the third quarter of 2002 compared to the same period in 2001. This decrease is due to a decline in product prices and to a reduction in sales volume. Average NGL prices realized by us decreased $0.02 per gallon to $0.41 per gallon in the third quarter of 2002 compared to the same period in 2001. Included in the realized NGL price was approximately $1.7 million of losses recognized in the third quarter of 2002 related to futures positions on equity NGL volumes. We have entered into additional futures positions for a portion of our equity NGL production for the remainder of 2002 and 2003. Average NGL sales volumes decreased 116 MGal per day to 2,219 MGal per day in the third quarter of 2002 compared to the same period in 2001.

Revenues from the sale of NGLs decreased approximately $108.9 million to $229.9 million in the nine months ended September 30, 2002 compared to the same period in 2001. This decrease is due to a reduction in product prices and to a a reduction in sales volume. Average NGL prices realized by us decreased $0.13 per gallon to $0.40 per gallon in the nine months ended September 30, 2002 compared to the same period in 2001. Included in the realized NGL price were approximately $5.7 million of losses recognized in the nine months ended September 30, 2002 related to futures positions on equity NGL volumes. Average NGL sales volumes decreased 217 MGal per day to 2,098 MGal per day in the nine months ended September 30, 2002 compared to the same period in 2001.

Product purchases decreased by $64.5 million and $862.8 million for the quarter and nine months ended September 30, 2002 compared to the same period in 2001. Overall, combined product purchases as a percentage of sales of all products decreased to 89% for the quarter and nine months ended September 30, 2002 from 93% and 92% for the same periods in 2001, respectively. The decrease in the product purchase percentage for the third quarter resulted from reduced sales of third-party product and an increase of sale of our production from the Powder River Basin development. The decrease in the product purchase percentage for the nine months ended September 30, 2002 versus the comparable period of 2001 resulted from a decrease in product prices and an increase of sale of our production from the Powder River Basin development.

Marketing margins on residue gas averaged $0.04 per Mcf for the quarters ended September 30, 2002 and 2001. Marketing margins on residue gas averaged $0.05 and $0.09 per Mcf in the nine months ended September 30, 2002 and 2001, respectively. The decrease in margin for the nine months ended September 30, 2002 compared to the 2001 period primarily resulted from reduced margins associated with the mark-to-market of transactions in the current periods versus the comparable prior periods. Under the mark-to-market accounting required for derivative transactions, the margin anticipated 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 Unrealized gain (loss) on marketing activities.

Marketing margins on NGLs averaged approximately $0.009 per gallon in the third quarter of 2002 and $0.008 per gallon in the nine months ended September 30, 2002. This represents an increase as compared to the $0.003 per gallon realized in the third quarter of 2001 and $0.006 per gallon realized in the nine months ended September 30, 2001. This is due to more favorable market conditions present in 2002 as compared to 2001.

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.

In the nine months ended September 30, 2002, we accrued a total of $1.6 million for doubtful accounts, primarily due to the bankruptcy filing of a large mid-western co-op during this period. During the third quarter of 2002 we did not increase our accrual. These accruals are not included in the calculation of the marketing margins and are reported in Selling and administrative expenses.

Plant operating expense increased $1.9 million in the third quarter of 2002 and increased by $5.3 million in the nine months ended September 30, 2002 compared to the same periods in 2001. This increase is primarily due to additional leased compression, repair and maintenance and labor costs in the Powder River Basin coal bed development and higher property tax expenses at our plant facilities.

Oil and gas exploration and production expenses increased by $2.0 million in the third quarter of 2002 and remained relatively constant in the nine months ended September 30, 2002, respectively, as compared to the same periods in 2001. Overall, lease operating expense, or LOE, averaged $0.41 per Mcf in the third quarter of 2002 and $0.44 per Mcf in the nine months ended September 30, 2002. LOE in the Powder River Basin coal bed development averaged $0.44 per Mcf in the third quarter and $0.47 per Mcf in the nine months ended September 30, 2002. The increases are substantially due to higher utility charges, increased use of leased generators, increased labor charges and prior period adjustments for operating supplies, utilities and technical supervision billed to us by the well operator. The increased LOE in the nine-month period in 2002 were substantially offset by lower severance taxes resulting from the significant reduction in residue gas prices in 2002 as compared to 2001.

Selling and administrative expenses increased by $346,000 and $4.9 million in the third quarter and nine months ended September 30, 2002, respectively, as compared to the same periods in 2001, due to higher health insurance costs, increased reserves for doubtful accounts and higher compensation expenses.

Depreciation, depletion and amortization increased by $1.6 million and $7.0 million in the third quarter and the nine months ended September 30, 2002, respectively, as compared to the same periods in 2001 primarily as a result of our increasing operations in the Powder River Basin coal bed methane development.

The provision for income taxes increased to an effective rate of approximately 41% in the third quarter of 2002 and to 38% in the nine months ended September 30, 2002 from 36.5% for the comparable periods in 2001. This increase is due to increased sales of third-party product in states with higher corporate tax rates and in Canada. We expect that this increase in our effective tax rate will continue in future quarters, although to a lesser extent.

Cash Flow Information

Cash flows from operating activities decreased by $71.7 million in the first nine months of 2002 compared to the same period in 2001. This reduction was primarily due to a decrease in net income in the first nine months of 2002 compared to the prior year and the timing of cash receipts and payables.

Cash flows used in investing activities decreased by $15.4 million in the first nine months of 2002 compared to the same period in 2001. This decrease was primarily due to a reduction in capital expenditures.

Cash flows used in financing activities decreased by $47.3 million in the first nine months of 2002 compared to the same period in 2001. This decrease was due to the application of a portion of the proceeds received in the sale of our Toca Processing facility in the third quarter of 2002 to reduce the amounts outstanding under our Revolving Credit Facility.

Other Information

Transactions with Officers. In October 2002, we granted options for a total of 169,500 shares to our ten executive officers. The options were granted at an option price of $32.95 per share. In accordance with the terms of the stock option plan, the option price is the average closing price for our common stock for the ten trading days prior to the grant.

In June 2001, the Compensation and Nominating Committee recommended, and the board approved, retention bonuses totaling $820,000 to nine of our executive officers. These bonuses were contingent upon the officer not voluntarily terminating employment for one year following the hiring of a new Chief Executive Officer and President. These bonuses were paid on November 1, 2002.

In 1989, we loaned to our officers at that time, an amount sufficient to exercise their options under our stock option plans. The loans and accrued interest were to be forgiven if the officer remained employed by us for specified time periods and upon a resolution of the board of directors. In May and July 2002, we forgave loans related to 37,500 shares of Common Stock totaling $636,000. After giving effect to the forgiveness, loans related to 37,500 shares of Common Stock in the amount of $637,000 remain outstanding. Pursuant to the terms of agreements entered into in 2001, the remaining loans will be forgiven in December 2002 and May 2003.

Business Strategy

Maximizing the value of our existing core assets and locating new growth projects in the Rocky Mountain region are the focal points of our business strategy. Our core assets are our fully integrated upstream and midstream assets in the Powder River and Green River Basins in Wyoming and our midstream operations in west Texas and Oklahoma. Our long-term business plan is to increase shareholder value by: (i) doubling proven reserves and equity production of natural gas over the course of the next three to five years; (ii) meeting or exceeding throughput projections in our midstream operations; and (iii) optimizing annual returns.

Double Proven Natural Gas Reserves and Equity Production of Natural Gas. In order to achieve this goal, we will focus on continued development of our leasehold positions in the Powder River Basin coal bed methane, CBM, and development in the Green River Basin and in the Sand Wash Basin. We have acquired drilling rights on approximately 821,000 net acres in these and other Rocky Mountain basins. At December 31, 2001, we had proved developed and undeveloped reserves of approximately 476 billion cubic feet equivalent, Bcfe, on a portion of this acreage position. In total this represents an increase of approximately 15% in our proved reserves from December 31, 2000. Reserve life, determined by dividing our proved reserves by our 2001 production, is over 13 years. Our production during the first nine months of 2002 as compared to the same period in 2001 increased by 33% to 34.7 Bcfe. In the full year of 2001, we replaced 275% of that year's production. All our 2001 reserve growth and our production growth in the first nine months of 2002 was achieved organically through the drill bit. As of December 31, 2001, we estimated that there was a net total of 2.1 trillion cubic feet, Tcf, of probable and possible reserves associated with our undeveloped acreage in these areas. In the Powder River Basin, this potential lies in over 10,000 well locations in the Big George, Wyodak and related coals if the play is fully successful. In the Green River Basin, our reserve potential lies in the development of 80-acre and 40-acre locations on our leasehold on the Pinedale Anticline, which target sandstone reservoirs in the Lance and Mesa Verde formations.

We are also actively seeking to add another core project that is focused on Rocky Mountain natural gas. We will utilize our expertise in exploration and low-risk development of tight-gas sands and coal bed methane plays to evaluate acquisitions of either additional leaseholds, proven and undeveloped reserves or companies with operations focused in this area. The addition of another core project will ideally result in additional investment opportunities in our midstream operations.

Meet or Exceed Throughput Projections in our Midstream Operations. To achieve this goal, we must continue our efforts to add to natural gas throughput levels through new well connections and expansion of gathering systems and to increase our efficiency by modernization of equipment and the consolidation of existing facilities. We also seek new growth opportunities for gathering and processing through our development of new gas reserves.

Our midstream 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, process or treat natural gas produced on acreage dedicated to us by third parties or produced by us. We contract for production from newly developed acreage in order to replace declines in existing reserves or increase reserves that are dedicated for gathering, processing or treating at our facilities. However, we anticipate over time that some of our facilities will experience declines in throughput volumes. At December 31, 2001, the estimated reserves dedicated to our midstream facilities totaled 3.2 Tcf. This includes our estimate of future third-party production and our proven reserves, but does not include our 2.1 Tcf of probable and possible reserves. The estimated third-party reserves dedicated to our facilities are based upon our interpretation of publicly available well and production information and are not the result of audited reserve reports prepared for us. In 2001, 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 190% of throughput. In the first nine months of 2002, we spent approximately $31.5 million on additional well connections and compression and gathering system expansions. We will also evaluate investments in expansions or acquisitions of assets that complement and extend our core natural gas gathering, processing, treating and marketing businesses and new growth projects in the Rocky Mountain region.

Optimize Annual Returns. To optimize our annual returns, we will focus our efforts in our primary operating areas of the Powder River and Green River Basins in Wyoming, the Anadarko Basin in Oklahoma and the Permian Basin in west Texas. We review the economic performance and growth opportunities of each of our assets to ensure that a satisfactory rate of return is achievable. If an asset is not generating targeted returns or is outside our core operating areas, we explore various options, such as integration with other Western-owned facilities or consolidation with third-party-owned facilities, dismantlement, asset trades or sale. Additionally, we routinely evaluate our business for methods to reduce our operating and administrative costs, including the implementation of automation and information technology.

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 through 2002 and 2003. We have from time to time renegotiated the Revolving Credit Facility to extend the maturities of the facility. Depending on the timing and the amount of our future projects, and our ability to renegotiate the facility, 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 preferred stock dividend requirements for 2002 and 2003.

During the past several years, although 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. In the first three quarters of 2002, gas prices in the Rocky Mountain region deteriorated as a result of limited transportation capacity out of the region. In some cases, producers have curtailed existing production or delayed their drilling programs due to lower prices. The overall level of drilling will depend upon, among other factors, the prices for oil and gas, the drilling budgets of third-party producers, availability of transportation capacity to market centers, the energy and environmental 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. Any prolonged reduction in prices for natural gas and NGLs may depress the levels of exploration, development and production by third parties and us. Lower levels of these activities could result in a corresponding decline in the demand for our gathering, processing and treating services. A reduction in any of these activities could have a material adverse effect on our financial condition and results of operations.

We have effective shelf registration statements filed with the Securities and Exchange Commission, or SEC, 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, 2002 are summarized as follows (dollars in thousands):

Sources of funds:
	Borrowings under the Revolving Credit Facility		$	723,280
	Proceeds from the dispositions of property and equipment			33,404
	Net cash provided by operating activities			72,865
	Proceeds from exercise of common stock options			6,434

		Total sources of funds	$	835,983

Uses of funds:
	Payments related to long-term debt (including debt issue costs)		$	732,780
	Capital expenditures			87,784
	Dividends paid			11,326
	Contributions to equity investees			7,637
	Other			123

		Total uses of funds	$	839,650

Redemption of Preferred Stock. In November 2002, we intend to issue a notice of redemption of all of the remaining shares of our $2.28 cumulative preferred stock currently outstanding, at a liquidation preference of $25.00 per share plus accrued and unpaid dividends, for a total of $14.0 million. The date fixed for redemption will be at least thirty days from notice of redemption. This redemption will be funded with amounts available under our Revolving Credit Facility. The capitalized offering costs of $639,000 associated with the redeemed preferred stock will be reflected as a special dividend to preferred shareholders in the fourth quarter of 2002 and will accordingly reduce earnings available to common shareholders in that quarter by approximately $0.02 per common share.

Inventories and Storage Capacity. Access to storage capacity is a significant element of our marketing strategy. We customarily store gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and to capture seasonal price differentials. As of September 30, 2002, we had contracts in place for approximately 14.3 Bcf of storage capacity at various third-party facilities. The fees associated with these contracts during 2002 will average $0.39 per Mcf of annual capacity. The associated contract periods have an average term of two years. At September 30, 2002, we held gas in our contracted storage facilities and in imbalances of approximately 19.7 Bcf at an average cost of $2.34 per Mcf compared to 16.1 Bcf at an average cost of $3.37 per Mcf at September 30, 2001. These positions are for storage withdrawals within the next eighteen months. We have also entered into a precedent agreement for 2.4 Bcf of annual capacity, for a term of ten years, for storage in a facility, which is not yet completed. We anticipate the completion of the construction of this facility in 2004. When the facility is completed, we will enter into a storage agreement.

From time to time, we lease NGL storage space at major trading locations in order to store products for resale during periods when prices are favorable and to facilitate the distribution of products. At September 30, 2002, we held NGLs in storage at various third-party facilities of 4,005 MGal, consisting primarily of propane and normal butane, at an average cost of $0.31 per gallon compared to 7,409 MGal at an average cost of $0.38 per gallon at September 30, 2001.

We acquire derivatives to minimize our exposure to price movements related to our inventories and storage capacity. Under mark-to-market accounting, our inventories in these storage facilities and the related derivatives are marked to market and the expected profit to be earned on these transactions is recorded in the month of origination.

Firm Transportation Capacity. Access to firm transportation is also a significant element of our business strategy. Firm transportation ensures that our equity production has access to downstream markets and allows us to capture incremental profit when pricing differentials between physical locations occur. As of September 30, 2002, we had contracts for approximately 674 MMcf per day of firm transportation. This amount represents our total contracted amount on many individual pipelines. In many cases it is necessary to utilize sequential pipelines to deliver gas into a specific sales market. In total, we have the capacity to transport 166 MMcf per day of gas from the Rocky Mountain area to the Mid-Continent. This utilizes a total of approximately 461 MMcf per day of firm capacity on four separate pipelines. Our remaining firm capacity consists of 115 MMcf per day to markets within the Rocky Mountains and 98 MMcf per day contracted in various other markets throughout the country.

A portion of this firm transportation capacity was contracted for use in our marketing operation. For example, our Marketing segment purchases gas in the Rocky Mountain region, transports this gas utilizing its 50 MMcf per day of our firm transportation capacity to the Mid-Continent, and resells the gas to various markets. During the first nine months of 2002, these types of transactions have been very profitable as the price difference, or basis, between the Rocky Mountain and Mid-Continent regions has exceeded the cost of transportation. To the extent these transportation contracts were acquired for our Marketing segment, they are derivative contracts as defined by SFAS No. 133 and are marked to market. We are currently analyzing the impact of the expiration on October 1, 2002, of the FERC's policy on capacity release. The expiration of this policy may have an impact on our ability to treat these transportation agreements as derivative contracts under SFAS No. 133 beginning in the fourth quarter of 2002. We are currently unable to quantify the impact, if any, of this matter on our results of operation and financial position.

The fixed fees associated with our contracts for firm transportation capacity during 2002 will average approximately $0.16 per Mcf per day, and the associated contract period's range from three months to fourteen years. Under firm transportation contracts, we are required to pay the fees associated with these contracts whether or not the transportation is used.

Operating Leases. Primarily to support our growing development in the Powder River coal bed development, we have entered into operating leases for compression equipment. Payments made on these leases are a component of operating expenses and are reflected on the Consolidated Statement of Operations and, as operating leases, are not reflected on our Consolidated Balance Sheet. As of September 30, 2002, we had leased a total of 120 compression units. These leases have terms ranging from two to ten years with return or fair market purchase options available at various times during the lease. If we were to exercise the early buyout options on all of the leased equipment, these purchase options would require the capital expenditure of approximately $32.3 million between the years of 2007 and 2011. At September 30, 2002, we had 9 compressor units under an interim leasing agreement. These compressors will be added to the existing lease arrangements when the equipment is installed and in service.

In August 2002, we entered into a seven year and nine month agreement for the lease of approximately 85,000 square feet of office space in Denver, Colorado. The cumulative lease payments over the term of this agreement, which begins upon occupancy, will total approximately $12.0 million. Our corporate offices will be relocated to this space in the first quarter of 2003.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 30, 2002 is as follows (dollars in thousands):

			Payments by Period
Type of Obligation	Total Obligation		Due in 2002		Due in 2003 - 2004		Due in 2005 - 2006		Due Thereafter
Long-term Debt	$	357,167	$	8,333	$	163,834	$	20,000	$	165,000
Guarantee of Fort Union Project Financing		6,478		179		1,556		1,795		2,948
Operating Leases		54,608		2,590		16,924		16,005		19,089
Firm Transportation Capacity Agreements		178,725		6,784		38,529		36,860		96,552
Firm Storage Capacity Agreements		26,621		1,156		7,936		3,875		13,654

Total Contractual Cash Obligations	$	623,599	$	19,042	$	228,779	$	78,535	$	297,243

Capital Investment Program. Capital expenditures related to existing operations totaled approximately $95.4 million during the first nine months of 2002, consisting of the following: (i) approximately $37.9 million related to gathering, processing, treating and pipeline assets, including $4.4 million for maintaining existing facilities; (ii) approximately $55.7 million related to exploration and production and lease acquisition activities; and (iii) approximately $1.8 million for miscellaneous items. Overall, capital expenditures in the Powder River Basin coal bed methane development and in the Green River Basin in southwest Wyoming operations represented 57% and 20%, respectively, of the total capital expenditures in the first nine months of 2002.

We expect capital expenditures related to existing operations to be approximately $143.5 million during 2002. The 2002 budget represents an approximate 13% decrease from the amount expended in 2001 due to an expectation of lower commodity prices. The 2002 capital budget consists of the following: (i) approximately $71.7 million related to gathering, processing, treating and pipeline assets, including $6.4 million for maintaining existing facilities; (ii) approximately $68.9 million related to exploration and production and lease acquisition activities; and (iii) approximately $2.9 million for miscellaneous items. Overall, capital expenditures in the Powder River Basin coal bed methane development and in southwest Wyoming operations represent 52% and 24%, respectively, of the total 2002 budget. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2002 will not change. We anticipate that funds for the 2002 capital budget will be provided primarily by internally generated cash flow. This budget may be increased to provide for acquisitions if approved by our board of directors.

Powder River Basin Coal Bed Methane. We continue to develop our Powder River Basin coal bed methane reserves and expand the associated gathering system in northeast 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. Within this area, in the first nine months of 2002, we continued, together with our co-developer, to be the largest producer of natural gas; the largest gatherer of natural gas; and the largest gas transporter out of this basin. At September 30, 2002, we held the drilling rights on approximately 515,000 net acres in this basin. As of December 31, 2001, we had established proven developed and undeveloped reserves totaling 393 Bcfe on a portion of this acreage. This represented a 12% increase in proved reserves as compared to December 31, 2000. As of December 31, 2001, we estimated that there was a net total of 1.9 Tcf of probable and possible reserves associated with our undeveloped acreage in this area. There can be no assurance, however, as to the ultimate recovery of these reserves due to geologic, regulatory, commodity price and lease expiration risks.

We plan to participate in over 900 gross wells in 2002, of which 834 were drilled in the first nine months. The average drilling and completion cost for our coal bed methane gas wells is approximately $90,000 per well with average reserves per successful well of approximately 278 MMcf. Our average finding and development costs in this area are estimated to be approximately $0.42 per Mcf in 2002. As deeper wells are drilled to the Big George coal, reserves per well are expected to increase as will the average cost per well. Our share of production from wells in which we own an interest has increased from an average of approximately 85 MMcfe per day in the nine months ended September 30, 2001 to 114 MMcfe per day in the nine months ended September 30, 2002. As of September 30, 2002, we were producing an average of 128 MMcf per day, net to our interest. We currently anticipate production rates of 129 net MMcf per day (337 gross MMcf per day) from this area by the end of 2002. As of September 30, 2002, we had approximately 1,200 wells that have been drilled but have not yet produced a total of 10 MMcf and are not producing more than 10 Mcf per day. Of this total, approximately 200 wells are under performing relative to our expectations based upon their location and the performance of other wells in the area 159 of which are de-watering in the Hoe Creek area. Core data from the Hoe Creek area indicates that the coal is under saturated with gas relative to our previous reserve assumptions, and may therefore require more extensive de-watering and result in lower recoverable reserves per well. While we have not updated our 2001 reserve analysis, based on our experience thus far in 2002, we anticipate that the Hoe Creek wells and some of the other wells may not achieve our original estimate of production or reserves.

Industry wide, production from the Big George coal has increased substantially in the last year and at September 30, 2002 production rates totaled approximately 42 MMcf per day from seven separate pilots. We are currently evaluating twelve pilot areas and one development area in the Big George. By the end of 2002, we expect to have drilled approximately 425 gross wells in the Big George coal area. We have marketable production quantities in two of these areas, All Night Creek and Pleasantville. As of October 31, 2002, these areas were producing a combined 14.2 gross MMcf per day of gas from 82 wells with an additional 94 wells in either the de-watering stage or awaiting connection to our gathering system. At December 31, 2001, we had proven reserves of 26 Bcfe in the Big George coal.

Future drilling on the majority of our federal acreage will continue to be delayed subject to completion of the Powder River Basin Oil & Gas Environmental Impact Statement, or EIS. The comment period for the draft EIS ended on May 15, 2002. Although the Environmental Protection Agency, or EPA, has submitted a negative comment letter with respect to the draft EIS, the Bureau of Land Management, or BLM, and EPA engaged in discussions and reached agreement on all major issues. The EPA has recommended that the BLM postpone the issuance of the Record of Decision for the Powder River Basin EIS until completion of a common model for the evaluation of the impact of potential air emissions for Wyoming and Montana. The BLM has agreed to this postponement and have indicated that the Powder River Basin EIS will be completed late in the first quarter of 2003, however, we can make no assurance the EIS will be completed within this time period. Our drilling plans for 2002 have not been substantially impacted by this study. A significant portion of the wells we plan to drill in 2003 would require federal permits to be issued pursuant to the completion of the EIS, however any limitation on drilling in 2003 is not anticipated to impact the growth rate of our production volumes until late in 2003.

Additionally, the Wyoming Department of Environmental Quality, or 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 majority of our wells producing from the Wyodak formation drain into these areas. The Wyoming and Montana DEQ offices have reached agreement on procedures for discharging and monitoring water into the Powder River and other drainages, in which most of our undeveloped prospects are located. Although the Wyoming and Montana DEQ offices have reached this agreement, the Wyoming DEQ has begun to grant permits only on a limited basis to the Powder River drainage area when it can be demonstrated that none of the discharge water will reach the Powder River itself. We can make no assurance that the conditions under which additional permits will be granted will not impact the level of our drilling or the cost or timing of the associated production.

On April 26, 2002, the Interior Board of Land Appeals (IBLA) ruled that the BLM did not comply with the National Environmental Policy Act (NEPA) prior to issuing three federal oil and gas leases held by an unaffiliated third party in the Powder River Basin, 156 IBLA at 358-59. There has not been a final decision regarding the validity of the three leases. The IBLA has remanded the case to the Wyoming BLM State Director without specifying a remedy. The State Director could, among other things, require additional NEPA analysis to be done on these three leases. The Powder River Basin Environmental Impact Statement is currently being conducted basin wide. This study includes a NEPA analysis covering coal bed methane development. The unaffiliated leaseholder has filed for judicial review in federal district court in Wyoming. We do not have any interests in these leases nor have we received notice of any challenge to leases that we hold. We are continuing to monitor the development of the issue.

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 first nine months of 2002, we were gathering 365 MMcf per day of our own production and that of other third-party producers. Of that volume, approximately 132 MMcf per day was transported through our wholly-owned MIGC pipeline.

Our capital budget in the Powder River Basin coal bed development provides for expenditures of approximately $74.8 million during 2002 of which $54.6 million was spent in the first nine months of 2002. This capital budget includes approximately $51.0 million for drilling costs for our interest in over 900 wells, production equipment and undeveloped acreage and $23.8 million for gathering lines and installation of compression. We have entered into several operating leases for compression equipment. As of September 30, 2002, we had leased a total of 120 compression units. These leases have terms ranging from two to ten years with return or fair market purchase options available at various times during the lease. Depending upon future drilling success, we may need to make additional capital expenditures or leasing commitments to continue expansion in this basin. In addition, due to regulatory uncertainties, which are beyond our control, we can make no assurance that we will incur this level of capital expenditure. Our co-developer in this area is also required to make similar capital commitments to continue the pace of the development as planned. In the summer of 2002, our co-developer in this area publicly disclosed that it had financial difficulties. We are currently unable to predict the impact, if any, of our co-developer's financial situation on the future pace of development in the Powder River coal bed area.

On October 23, 2002, we filed a complaint for declaratory relief and damages related to a dispute arising under various agreements between ourselves and Barrett Resources Corporation, dated on or about October 30, 1997, as each may have been amended. The dispute centers on our co-developer's acquisition of Barrett by merger consummated on August 2, 2001. We assert that we were entitled to a preferential right to purchase certain properties of Barrett located in the Powder River Basin under the agreements and that our consent was required prior to Barrett's assignment of its interests in the agreements to our co-developer. We also claim that our co-developer should no longer be the operator of these properties as a consequence of the merger transaction.

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 initially had a capacity of approximately 435 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. The gathering pipeline went into service in the third quarter of 1999. Construction of the gathering header and treating system was project financed by Fort Union and required a cash investment by us of approximately $900,000. In 1999, we entered into a ten-year agreement for firm gathering services on 60 MMcf per day of capacity at $0.14 per Mcf on Fort Union. In 2000, we and the other participants in Fort Union approved an expansion of the system. Construction of the 62-mile expansion was completed in the third quarter of 2001 and brought the system's capacity to 635 MMcf per day. The expansion costs totaled approximately $22.0 million and were project financed by Fort Union. In the fourth quarter of 2001, we invested approximately $500,000 as an equity contribution to Fort Union in conjunction with the project financing. Also in connection with the expansion, we increased our commitment for firm gathering services, effective December 2001, to a total of 83 MMcf per day of capacity at $0.14 per Mcf. All participants in Fort Union have guaranteed the project financing on a proportional basis, resulting in our guarantee of $6.5 million of the debt of Fort Union at September 30, 2002. This guarantee is not reflected on our Consolidated Balance Sheet.

Green River Basin. Our assets in the Green River Basin of southwest Wyoming are comprised of the Granger and Lincoln Road facilities, or collectively the Granger Complex, our 50% equity interest in Rendezvous Gas Services, L.L.C., our Red Desert facility and production in the Jonah Field and Pinedale Anticline areas. The Granger Complex and Red Desert have a combined operational capacity of 327 MMcf per day and processed an average of 192 MMcf per day in the first nine months of 2002. Our capital budget in this area provides for expenditures of approximately $34.8 million during 2002 of which $19.1 million was spent in the first nine months of 2002. This capital budget includes approximately $11.6 million for drilling costs and production equipment and approximately $23.2 million related to the gathering systems, plant facilities and additional capital contributions to Rendezvous. Due to drilling and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure.

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. 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 to Rendezvous. Each company owns a 50% interest in Rendezvous, and we serve as field operator of its systems. In the fourth quarter of 2001, Rendezvous began construction of additional gas gathering pipelines and compression facilities to increase capacity from the Pinedale Anticline. The first and second phases of our 50% owned Rendezvous gathering expansion into the Pinedale Anticline are completed and added a total of 170 MMcf per day of gathering capacity. Gas gathered in the Rendezvous system is delivered for blending or processing at either our Granger Complex or at a Questar processing facility. Through September 30, 2002, we have committed to spend approximately a total of $24.6 million, or $12.3 million net to our interest. A proposed phase three of this project, subject to the necessary approvals, is expected to commence in early 2003 and would extend the system approximately 30 miles further into the Pinedale Anticline. The total estimated construction cost of all three phases is anticipated to be $44.0 million, of which our share will be $22.0 million.

At September 30, 2002, we owned approximately 203,000 gross oil and gas leasehold acres, or approximately 32,500 net acres, in the Jonah Field and Pinedale Anticline areas. During 2002, we expect to participate in the drilling of 26 gross wells, or approximately 3 net wells on the Pinedale Anticline. The expected drilling and completion costs per gross well are approximately $3.3 million to $4.4 million and the average well depth in this area approximates 13,300 feet. Our average finding and development costs are estimated to be $0.57 to $0.90 per Mcf. During the third quarter of 2002, we produced an average of 12.5 MMcf per day, net, from these areas. Our production in the month of September 2002 was negatively impacted by an estimated 3 MMcf per day, net, as a result of the well operators' decisions to curtail production due to depressed natural gas prices in this region. We had established proven developed and undeveloped reserves totaling 71 Bcfe at December 31, 2001, based on 80-acre spacing. This represents a 29% increase as compared to December 31, 2000. As of December 31, 2001, we estimate a net total of 101 Bcf of probable and possible reserves associated with undeveloped acreage in this area. There can be no assurance, however, as to the ultimate recovery of these reserves.

Marketing.

Gas. We market gas produced at our wells and our plants and purchased from third parties to end-users, local distribution companies, or LDCs, pipelines and other marketing companies throughout the United States and Canada. Historically, our gas marketing was an outgrowth of our gas processing activities and was directed towards selling gas processed at our plants to ensure their efficient operation. As the natural gas industry became deregulated and offered more opportunity, we increased our third-party gas marketing. For the quarter and nine months ended September 30, 2002, our total gas sales volumes averaged 2.0 BcfD and 2.1 BcfD, respectively. Third-party sales, firm transportation capacity on interstate pipelines and our gas storage positions, combined with the stable supply of gas from our facilities and production, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods.

One of the primary goals of our gas marketing operations continues to be the preservation and enhancement of the value received for our equity volumes of natural gas. This goal is achieved through the use of hedges on the production of our equity natural gas and through the use of firm transportation capacity. For example, during the first three quarters of 2002, as a result of limited pipeline capacity from the Rocky Mountain region to market centers in the mid-continent and west coast areas, natural gas in this region has sold at a substantial discount to these other market areas. We have hedges in place for our equity production and firm transportation capacity to the mid-continent markets on approximately 92% of our equity production in the Rocky Mountain area for the remainder of 2002 and 2003. This has allowed us to realize an approximate $1.18 per Mcf improvement in price for natural gas per MMbtu relative to what would have been received if these hedges and capacity rights had not existed.

We sell gas under agreements with varying terms and conditions in order to match seasonal and other changes in demand. The duration of our sales contracts have an average tenor of 15 months. In addition to our offices in Denver and Houston, we have a marketing office in Calgary, Alberta. The Calgary office also provides us with information regarding market conditions in Canada, which affect the gas markets in the United States.

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. When we hedge the price of our equity production, we also lock in basis to ensure the effectiveness of the value of the hedge.

Our 2002 gas marketing plan emphasizes growth through our asset base and storage and transportation capacities that we control. In general, we do not expect to increase our third-party sales volumes in 2002 significantly from levels achieved over the last several years, and in fact, due to credit concerns in the energy industry, our overall sales volumes may decrease in the remainder of this year. We continually monitor and review the credit exposure to our marketing counter parties. As the probable failure of Enron became more apparent in the third quarter of 2001, we became increasingly concerned with our credit exposure to our customers, primarily a category of our customers generally known as "energy merchants." Energy merchants create liquidity in the marketplace for natural gas transactions and have historically been some of our largest suppliers and customers. In order to minimize our credit exposures, we have utilized existing netting agreements to reduce our net credit exposure, established new netting agreements with additional customers, terminated several long-term marketing obligations, negotiated accelerated payment terms with several customers, and reduced the amount of credit which we make available to various customers. If any of these customers with whom we have netting agreements were to file for bankruptcy, although similar netting agreements have been upheld by bankruptcy courts in the past, we can provide no assurance that our agreements will not be challenged or as to the outcome of any challenge. Primarily due to the bankruptcy filing of a large mid-western co-op in the second quarter, we incurred a charge to income through an allowance for doubtful accounts of $1.6 million in the nine months ended September 30, 2002.

We have identified one Master Swap Agreement containing ratings triggers. Under this agreement, either party may be required to post additional collateral in the event of a decrease in their current rating by Standard & Poor's or Moody's Investors Service. Based on our outstanding positions under this agreement and our counter party's credit rating at September 30, 2002, we were holding approximately $3.8 million of collateral.

On June 5, 2002, and as amended on June 18, 2002, we responded to a data request of the Federal Energy Regulatory Commission (FERC) in Docket No. PA02-2-000. The FERC's request inquired as to any "wash", "round trip", or "sell, buy back" trading in the United States portion of the Western States Coordinating Council and/or Texas during the years ended December 31, 2000 and 2001. During the time period described above, we engaged in two transactions that met the FERC's criteria for a trading transaction of this type. The transactions occurred in April 2001 and involved an aggregate quantity of approximately 259,000 Mmbtu or $3.5 million of gross revenue. The transactions were not entered into for the purpose of artificially inflating our trading volume or revenue. Our internal control policies require valuation of the current market value of gas placed in storage based upon some objective criteria, and these transactions were intended to provide a third-party generated price for natural gas placed in storage. These transactions represent 0.1% of our total sales revenues for the year ended December 31, 2001. The FERC has not inquired as to sales activity in 2002. During the first nine months of 2002, no transactions of this type are included in our revenues.

NGLs. We market NGLs, or ethane, propane, iso-butane, normal butane, natural gasoline and condensate produced at our plants and purchased from third parties, in the Rocky Mountain, Mid-Continent, Gulf Coast and Southwestern regions of the United States. A majority of our production of NGLs moves to the Gulf Coast area, which is the largest NGL market in the United States. Through the development of end-use markets and distribution capabilities, we seek to ensure that products from our plants move on a reliable basis, avoiding curtailment of production. For the quarter and nine months ended September 30, 2002, NGL sales averaged 2,219 MGal per day and 2,098 MGal per day, respectively.

Consumers of NGLs are primarily the petrochemical industry, the petroleum refining industry and the retail and industrial fuel markets. As an example, the petrochemical industry uses ethane, propane, normal butane and natural gasoline as feedstocks in the production of ethylene, which is used in the production of various plastics products. Over the last several years, the petrochemical industry has increased its use of NGLs as a major feedstock and is projected to continue to increase such usage. Further, consumers use propane for home heating, transportation and for agricultural applications. Price, seasonality and the economy primarily affect the demand for NGLs.

We decreased NGL sales to third parties by approximately 116 MGal per day and 217 MGal per day, for the quarter and nine months ended September 30, 2002, respectively, compared to the same periods in 2001. As in the case of natural gas, we continually monitor and review the credit exposure to our NGL marketing counter parties. With the sale of our Toca facility in September of 2002, we anticipate that sales of third-party product will decrease further.

Transportation. We own and operate MIGC, an interstate pipeline located in the Powder River Basin in Wyoming, and MGTC, an intrastate pipeline located in northeast Wyoming. MIGC charges a FERC approved tariff and is connected to pipelines owned by Colorado Interstate Gas Company, Williston Basin Interstate Pipeline Company, Kinder Morgan Interstate Pipeline Co., Wyoming Interstate Company, Ltd. and MGTC. During the first nine months of 2002, MIGC transported an average of 179 MMcf per day. It is anticipated that MIGC will continue at that level through 2003. MGTC provides transportation and gas sales to the Wyoming cities of Gillette, Moorcroft and Wright at rates that are subject to the approval of the Wyoming Public Service Commission.

The FERC has implemented changes over the past several years to restrict transactions between regulated pipelines and affiliated companies. In addition, the FERC has proposed to limit the use of affiliates' employees in the operation of regulated entities. On August 1, 2002, the FERC issued a Notice of Proposed Rule Making that, if enacted, would require MIGC to establish its own cash management function possibly including its own revolving credit facility. In addition, this proposed rule would limit the ability of MIGC to transfer funds to its parent company. Further, this proposed rule would require us to modify our existing subsidiary guarantees under our credit facilities. We can make no assurances as to the ultimate regulations passed by the FERC or the effects such regulations may have on the operating costs of MIGC or our financial position.

Recent Changes to Environmental Regulations. Federal regulations regarding spill prevention and containment have recently been modified to establish a lower threshold of storage capacity of petroleum and petroleum by-products at a site for which a spill prevention plan is required. We are evaluating all of our assets for compliance with this regulation and estimate that approximately 100 existing sites will need to be modified to meet the new requirements. We currently estimate our costs for compliance to be approximately $2.0 million. The new spill prevention plans must be in place for covered assets by February 2003. All modifications called for in those plans must be in place by August 2003.

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, which matures on April 24, 2003, and a $167 million Revolving Credit Facility, or Tranche B, which matures on April 30, 2004. At September 30, 2002, $85.5 million was 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, 2002, the interest rate payable on borrowings under this facility was approximately 3.1%. 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 35%. 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 2.5 to 1.0 through September 30, 2002 and increases to 3.25 to 1.0 at December 31, 2002. This facility also limits our ability to enter into operating leases and sale leaseback transactions. This facility is guaranteed and secured via a pledge of the stock of all of our material subsidiaries.

We intend to enter into a new revolving loan arrangement in the first quarter of 2003 to replace the existing Revolving Credit Facility. Our practice has been to replace our existing facility approximately one year prior to its final maturity date to ensure adequate sources of capital for our operations. While we believe that we would be able to secure a new revolving loan agreement, we can provide no assurance as to the pricing and terms of a new facility.

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, 2002 are as indicated in the following table (dollars in thousands):

Issue Date	Amount		Interest Rate		Final Maturity	Principal Payments Due
October 27, 1992	$	16,666	7.99	%	October 27, 2003	$8,333 on October 27, 2002 and 2003
December 27, 1993		25,000	7.23	%	December 27, 2003	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
	$	116,666

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 55% and a senior debt to capitalization ratio of not more than 35%. This agreement also requires an EBITDA to interest ratio of not less than 3.75 to 1.0 and an EBITDA to interest on senior debt ratio of not less than 5.50 to 1.0. EBITDA in these calculations excludes some non-recurring items. In addition, this agreement contains a calculation limiting dividends and other restricted payments including preferred stock redemptions. Under this limitation, approximately $84.4 million was available at September 30, 2002. This facility also limits our ability to enter into operating leases and sale leaseback transactions. 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 unsecured debt from Moody's Investors Service or Standard & Poor's. Borrowings under the Master Shelf Agreement are guaranteed by, and secured via, a pledge of the stock of all of our material subsidiaries.

In October 2002, we funded a required principal repayment under the Master Shelf Agreement of $8.3 million 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 tradeable notes under the same terms and conditions. The Subordinated Notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%. These notes contain covenants, which include limitations on debt incurrence, restricted payments, liens and sales of assets. Under the calculation limiting restricted payments, including common dividends and preferred stock redemptions, approximately $52.3 million was available at September 30, 2002. The Subordinated Notes are unsecured and are guaranteed on a subordinated basis by all of our material subsidiaries. We incurred approximately $5.0 million in offering commissions and expenses, which have been capitalized and will be amortized over the term of the notes.

Covenant Compliance. We were in compliance with all covenants in our debt agreements at September 30, 2002. Taking into account all the covenants contained in these agreements, we had approximately $120 million of available borrowing capacity at September 30, 2002. None of our credit facilities include covenant requirements or acceleration provisions based upon a change in our credit ratings.

Principal Facilities

The following tables provide information concerning our principal facilities during 2002. 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, 2002
				Gas Gathering System Miles(2)	Gas Throughput Capacity (MMcf/D)(3)	Average for the Nine Months Ended September 30, 2002
Facilities(1)			Year Placed In Service	Gas Gathering System Miles(2)	Gas Throughput Capacity (MMcf/D)(3)	Gas Throughput (MMcf/D)(4)	Gas Production (MMcf/D)(5)	NGL Production (MGal/D)(5)
Texas
	Gomez Treating(6)		1971	386	280	94	88	—
	Midkiff/Benedum		1949	2,213	165	142	94	871
	Mitchell Puckett Gathering(6)		1972	93	120	55	35	1
Louisiana
	Toca(7)(8)(14)		1958	—	160	67	64	54
Wyoming
	Coal Bed Methane Gathering		1990	1,253	223	365	195	—
	Fort Union Gas Gathering		1999	106	635	444	444	—
	Granger(7)(9)(10)		1987	524	235	167	149	289
	Hilight Complex(7)		1969	626	124	15	10	52
	Kitty/Amos Draw(7)		1969	314	17	8	5	32
	Lincoln Road(10)		1988	149	50	12	12	5
	Newcastle(7)		1981	146	5	3	2	20
	Red Desert(7)		1979	111	42	13	11	23
	Rendezvous Gas Services		2001	—	125	103	103	—
	Reno Junction(9)		1991	—	—	—	—	103
Oklahoma
	Chaney Dell		1966	2,082	130	66	53	323
	Westana		1981	1,001	45	79	75	5
New Mexico
	San Juan River(6)		1955	140	60	25	19	29
Utah
	Four Corners Gathering		1988	104	15	2	2	10
		Total		9,248	2,431	1,660	1,361	1,817

				Average for the Nine Months Ended September 30, 2002
Transportation Facilities(1)		Year Placed In Service	Transportation Miles(2)	Pipeline Capacity (MMcfD)(2)	Gas Throughput (MMcfD)(4)
MIGC(11)(13)		1970	245	130	177
MGTC(12)		1963	252	18	11
	Total		497	148	188

(1): Our interest in all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%); Fort Union gathering system (13%); and Rendezvous Gas Services (50%). 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, transportation miles and pipeline capacity are as of September 30, 2002.
(3): Gas throughput capacity is as of September 30, 2002 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): Processing facility that includes fractionation (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): Lincoln Road is operated on an intermittent basis to process excess gas from the Granger system.
(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 certificated capacity at the Powder River junction only and does not include interruptible capacity or capacity at other delivery points.
(14): This facility was sold on September 24, 2002.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 fixed price purchase and sale commitments, the value of storage inventories and exposure to physical market price volatility.

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 goals. 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 enter into futures transactions on the New York Mercantile Exchange, or NYMEX, 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 many of 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. At November 1, 2002 we had posted margin totaling $12.1 million with various counter parties.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) our 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.

Hedge Positions. For the remaining quarter of 2002, we have hedged approximately 60% of our projected equity natural gas volumes and approximately 68% of our estimated equity production of crude oil, condensate, and NGLs. For 2003, we have entered into hedging positions for approximately 51% of our projected equity gas volumes and approximately 36% of our estimated equity production of crude oil, condensate, and NGLs. These contracts are designated and accounted for as cash flow hedges. As such, gains and losses related to the effective portions of the changes in the fair value of the derivatives are recorded in Accumulated other comprehensive income, a component of Stockholders' equity. Any gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Product purchases when the hedged transactions occur. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Non-cash change in the fair value of derivatives. This ineffectiveness is primarily due to the use of crude oil swaps in hedging the variability in the sales price of butanes. During the nine months ended September 30, 2002, we recognized a total of $154,000 of loss from the ineffective portions of our hedges. Overall, our hedges are expected to continue to be "highly effective" under SFAS No. 133 in the future and no gains or losses were reclassified into earnings as a result of the discontinuance of cash flow hedges.

To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must correlate with changes in the price of the forecasted transaction being hedged so that our exposure to the risk of commodity price changes is reduced. To meet this requirement, we hedge both the price of the commodity and the basis between that derivative's contract delivery location and the cash market location used for the actual sale of the product. This structure attains a high level of effectiveness, insuring that a change in the price of the forecasted transaction will result in an equal and opposite change in the cash price of the hedged commodity. We utilize crude oil as a surrogate hedge for butanes. This typically results in an effective hedge as crude oil and butane prices historically have moved in tandem.

Outstanding Equity Hedge Positions and the Associated Basis for the remainder of 2002. In order to determine the hedged price to the particular operating region, deduct the basis differential from the NYMEX price. The prices for NGLs do not include the cost of the hedges of approximately $1.5 million. There are no associated costs for the natural gas hedges.

Product	Quantity and NYMEX or Settlement Price	Hedge of Basis Differential
Natural gas	80,000 MMbtu per day with an average minimum and maximum price of $3.81 and $5.87 per MMbtu, respectively.	Mid-Continent—40,000 MMbtu per day with an average basis price of ($0.14) per MMbtu. Permian—15,000 MMbtu per day with an average basis price of ($0.05) per MMbtu. Rocky Mountain—25,000 MMbtu per day with an average basis price of ($0.51) per MMbtu.
Crude, Condensate, Natural Gasoline and Butanes (Crude oil is used as a surrogate for butanes)	75,000 Barrels per month. Fixed price of $20.20 per barrel with right to participate in price increases above $22.50 per barrel. 55,000 Barrels per month. Floor at $20.00 per barrel.	Not Applicable
Propane	120,000 Barrels per month. Floor at $0.32 per gallon.	Not Applicable
Ethane	50,000 Barrels per month. Floor at $0.21 per gallon. 20,000 Barrels per month. Sold at $0.21 per gallon with right to participate in price increases above $0.25 per gallon.	Not Applicable

Outstanding Equity Hedge Positions and the Associated Basis for 2003. In order to determine the hedged price to the particular operating region, deduct the basis differential from the NYMEX price. The prices for NGLs do not include the cost of the hedges of approximately $930,000. There are no associated costs for the natural gas hedges.

Product	Quantity and NYMEX Price	Hedge of Basis Differential
Natural gas	20,000 MMbtu per day with an average price of $3.77 per MMbtu. 20,000 MMbtu per day with a minimum price of $3.50 per MMbtu and an average maximum price of $4.43 per MMbtu. 40,000 MMbtu per day at an average price of $4.05 per MMbtu.	Mid-Continent—20,000 MMbtu per day with an average basis price of ($0.15) per MMbtu. Permian—5,000 MMbtu per day with an average basis price of ($0.13) per MMbtu. Rocky Mountain—55,000 MMbtu per day with an average basis price of ($0.80) per MMbtu.
Butanes	50,000 Barrels of crude oil per month. Floor at $24.00 per barrel. (Crude oil is used as a surrogate for butanes).	Not Applicable
Propane	50,000 Barrels per month. Average minimum and maximum price of $0.37 per gallon and $0.53 per gallon, respectively.	Not Applicable
Ethane	75,000 Barrels per month. Average minimum and maximum price of $0.25 per gallon and $0.37 per gallon, respectively.	Not Applicable

Account balances related to equity hedging transactions at September 30, 2002, were $6.7 million in Current Assets from price risk management activities, $8,000 in Non-current Assets from price risk management activities, $5.7 million in Current Liabilities from price risk management activities, $1.3 million in Liabilities from price risk management activities, $107,000 in Deferred income taxes payable, net and a $186,000 after-tax unrealized loss in Accumulated other comprehensive income, a component of Shareholders' Equity. Based on the commodity prices as of September 30, 2002, an after-tax gain of $600,000 would be re-classified from Accumulated other comprehensive income to Product Purchases during the next twelve months.

Summary of Derivative Positions. A summary of the change in our derivative position from December 31, 2001 to September 30, 2002 is as follows (dollars in thousands):

Fair value of contracts outstanding at December 31, 2001	$	49,411
Decrease in value due to change in price		(6,446	)
Increase in value due to new contracts entered into during the period		28,960
Gains realized during the period from existing and new contracts		(52,020	)
Changes in fair value attributable to changes in valuation techniques		—

Fair value of contracts outstanding at September 30, 2002	$	19,905

A summary of our outstanding derivative positions at September 30, 2002 is as follows (dollars in thousands):

	Fair Value of Contracts at September 30, 2002
Source of Fair Value	Total Fair Value			Maturing In 2002			Maturing In 2003-2004			Maturing In 2005-2006			Maturing Thereafter
Exchange published prices	$	(13,892	)	$	(5,379	)	$	(8,513	)		—			—
Other actively quoted prices(1)		29,884			14,622			15,380		$	(117	)	$	(1	)
Other valuation methods(2)		3,913			3,660			253			—			—

Total fair value	$	19,905		$	12,903		$	7,120		$	(117	)	$	(1	)

(1): Other actively quoted prices are derived from broker quotations, trade publications, and industry indices.
(2): Other valuation methods are the Black-Scholes option pricing model utilizing prices and volatility obtained from broker quotations, trade publications, and industry indices.

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, 2002, the net notional value of such contracts was approximately $22.3 million in Canadian dollars, which approximates fair market value.

Accounting for 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 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.

ITEM 4. CONTROLS AND PROCEDURES

(a): Evaluation of disclosure controls and procedures.

Within the 90 days prior to the date of this report, we carried out an evaluation, under the supervision and with the participation of our management, including the President and Chief Executive Officer and Executive Vice President, Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to the Securities Exchange Act Rule 13a-14. Based upon that evaluation, the President and Chief Executive Officer and Executive Vice President, Chief Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to us that is required to be included in our periodic SEC filings.

Disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file under the Securities Exchange Act is accumulated and communicated to our management, including the President and Chief Executive Officer and Executive Vice President, Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

(b): Changes in internal controls.

There were no significant changes to our internal controls or in other factors that could significantly affect these controls subsequent to the date they were evaluated.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Western Gas Resources, Inc. and Lance Oil & Gas Company, Inc. (together the Plaintiffs) v. Williams Production RMT Company., (Defendant) Civil Action No. CO2-10-394, District Court, County of Sheridan, Wyoming. On October 23, 2002 Plaintiffs filed a complaint for declaratory relief and damages related to a dispute arising under a Development Agreement, a Purchase and Sale Agreement and an Operating Agreement, (collectively, the "Agreements") between the Plaintiffs and Barrett Resources Corporation, or Barrett, dated on or about October 30, 1997, as each may have been amended. The dispute centers on Defendant's acquisition of Barrett by merger consummated on August 2, 2001. Plaintiffs allege that they were entitled to a preferential right to purchase certain properties of Barrett located in the Powder River Basin of Wyoming under the Agreements and that Plaintiffs' consent was required prior to Barrett's assignment of its interests in the Agreements to the Defendant. Plaintiffs also allege that Barrett (now Defendant) should no longer be the operator of these properties as a consequence of the merger transaction. At this time, we are unable to predict the outcome of this action.

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 results of operations or financial position. We are seeking reimbursement from Amerada Hess under a contractual indemnity. We amended our original complaint and requested a jury trial in this case. Both parties filed cross motions for summary judgment. On April 19, 2002, the trial court ruled on the parties' cross motions for summary judgment in favor of Amerada Hess, indicating that Amerada Hess has no obligation to indemnify us in this matter. On May 31, 2002, we appealed the trial court decision to the Colorado Court of Appeals. Amerada Hess filed a motion to dismiss the appeal, which was denied by the Colorado Court of Appeals on July 29, 2002. At this time, we are unable to predict the outcome of this appeal.

Texas Natural Resource Conservation Commission (TNRCC)—Notification of Enforcement and Notification of Alleged Violations, Gomez Field Gathering Station, Fort Stockton, Texas. On October 28, 2002, we received a Notice of Enforcement for an alleged violation that a compliance certification during the period of December 30, 2000 through December 29, 2001 was not timely filed under our general operating permit requirements. We also received three Notices of Violations on October 18, 2002, for alleged failure to timely submit Permit Compliance Certifications for the period of April 2, 2000 through April 1, 2001 within thirty days and sixty days from the applicable deadlines, and a Notice of Violation for not submitting a deviation report, as required under Title V for the late submittals, for the period of April 2, 2000 through October 10, 2001. At this time, we are unable to quantify penalties or fines, if any, associated with these alleged violations.

Texas Natural Resource Conservation Commission (TNRCC)—Notification of Alleged Violations, Gomez Treating Plant, Texas. On December 5, 2001, we received notification of an alleged violation associated with compliance certifications for a Gomez Treating Plant owned by an unaffiliated company, which subsequently sold the Gomez Compressor Station to us in 1999. We have contested the alleged violation on the basis that we never purchased this treating facility and the unaffiliated company had physically removed the facility in 1995. At this time, we are unable to quantify penalties or fines, if any, associated with this alleged violation.

Other Litigation. We are involved in various other litigation and administrative proceedings arising in the normal course of 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.

Retirement Plan. Our retirement plan for our employees includes a fund, which allows them to invest in our common stock. The fund manager, Fidelity Investments, purchases this stock in open market transactions. Under SEC rules, the stock purchased by the plan participants during a portion of 2001and 2002 may be required to be registered by us. To resolve this issue, we intend to file a registration statement on Form S-3 with the SEC and offer to rescind or pay damages related to certain employee-initiated transactions during that period. Any stock acquired by us through this rescission offer will be treated as treasury stock. While we are unable to estimate the cost or results of the rescission offer, we do not expect the costs to 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:

99.1: Certification by President and Chief Executive Officer required by Sarbanes-Oxley Act of 2002.
99.2: Certification by Executive Vice President, Chief Financial Officer required by Sarbanes-Oxley Act of 2002.

(b): Reports on Form 8-K

A report on Form 8-K was furnished on November 13, 2002 pursuant to Regulation F-D, Rules 100-103 announcing third quarter 2002 results and providing operational performance guidance.

A report on Form 8-K was furnished on August 13, 2002 announcing that certifications of the President and Chief Executive Officer and Executive Vice President, Chief Financial Officer had been filed with the Securities and Exchange Commission as required pursuant to 18 U.S.C., Section 1350 and pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

A report on Form 8-K was furnished on August 14, 2002 with certifications of the President and Chief Executive Officer and Executive Vice President, Chief Financial Officer as required pursuant to 18 U.S.C., Section 1350 and pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 had been filed with the Securities and Exchange Commission.

A report on Form 8-K was filed on October 24, 2002 announcing the filing of a lawsuit initiated by Western Gas Resources, Inc., and Lance Oil & Gas Company, Inc., against Williams Production RMT Company, Civil Action No. CO2-10-394, in Sheridan County, Wyoming.

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 13, 2002	By:	/s/ PETER A. DEA Peter A. Dea President and Chief Executive Officer
Date: November 13, 2002	By:	/s/ WILLIAM J. KRYSIAK William J. Krysiak Executive Vice President, Chief Financial Officer (Principal Financial and Accounting Officer)