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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 MARCH 31, 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	84-1127613
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
12200 N. Pecos Street, Denver, Colorado	80234-3439
(Address of principal executive offices)	(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

        On May 1, 2002, there were 32,993,762 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—March 31, 2002 and December 31, 2001
		Consolidated Statement of Cash Flows—Three Months Ended March 31, 2002 and 2001
		Consolidated Statement of Operations—Three Months Ended March 31, 2002 and 2001
		Consolidated Statement of Changes in Stockholders' Equity—Three Months Ended March 31, 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
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)

			March 31, 2002			December 31, 2001
			(unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	6,244		$	10,032
	Trade accounts receivable, net			246,726			231,724
	Product inventory			24,922			50,773
	Parts inventory			43			3,049
	Assets from price risk management activities			37,623			66,271
	Other			2,071			4,114
		Total current assets		317,629			365,963
Property and equipment:
	Gas gathering, processing, storage and transportation			923,374			912,003
	Oil and gas properties and equipment (successful efforts method)			205,957			193,656
	Construction in progress			111,075			106,385
				1,240,406			1,212,044
	Less: Accumulated depreciation, depletion and amortization			(380,414	)		(363,737	)
		Total property and equipment, net		859,992			848,307
Other assets:
	Gas purchase contracts (net of accumulated amortization of $35,805 and $35,329, respectively)			32,351			32,826
	Assets from price risk management activities			3,390			2,934
	Other			22,602			17,912
	Total other assets			58,343			53,672
TOTAL ASSETS			$	1,235,964		$	1,267,942
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	224,199		$	260,208
	Accrued expenses			30,349			23,123
	Liabilities from price risk management activities			19,600			18,075
	Dividends payable			3,779			3,767
		Total current liabilities		277,927			305,173
Long-term debt				369,867			366,667
Liabilities from price risk management activities				1,844			1,720
Other long-term liabilities				2,141			2,284
Deferred income taxes payable, net				113,006			118,746
Total liabilities				764,785			794,590
Stockholders' equity:
	Preferred Stock; 10,000,000 shares authorized:
		$2.28 cumulative preferred stock, par value $.10; 1,400,000 shares issued ($35,000,000 aggregate liquidation preference)		59			59
		$2.625 cumulative convertible preferred stock, par value $.10; 2,760,000 issued ($138,000,000 aggregate liquidation preference)		276			276
	Common stock, par value $.10; 100,000,000 shares authorized; 32,975,770 and 32,689,009 shares issued, respectively			3,319			3,293
	Treasury stock, at cost; 25,016 common shares and 44,290 shares of $2.28 cumulative preferred stock in treasury			(1,907	)		(1,907	)
	Additional paid-in capital			393,299			387,505
	Retained earnings			70,349			66,128
	Accumulated other comprehensive income			6,668			18,882
	Notes receivable from key employees secured by common stock			(884	)		(884	)
		Total stockholders' equity		471,179			473,352
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY			$	1,235,964		$	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)

		Three Months Ended March 31,
		2002			2001
Reconciliation of net income to net cash provided by operating activities:
Net income		$	8,000		$	40,590
Add income items that do not affect cash:
	Depreciation, depletion and amortization		17,946			14,478
	Gain on the sale of property and equipment		9			(11,223	)
	Deferred income taxes		3,836			16,719
	Non-cash change in fair value of derivatives		10,995			(5,019	)
	Other non-cash items, net		(27	)		8
			40,759			55,523
Adjustments to working capital to arrive at net cash provided by operating activities:
	(Increase) decrease in trade accounts receivable		(15,476	)		190,454
	Decrease in product inventory		25,851			30,458
	Decrease in parts inventory		—			387
	(Increase) decrease in other current assets		651			(299	)
	(Increase) decrease in other assets and liabilities, net		(71	)		8,076
	Decrease in accounts payable		(36,009	)		(180,254	)
	Decrease in accrued expenses		6,820			2,199
Net cash provided by operating activities			22,525			106,544
Cash flows from investing activities:
	Purchases of property and equipment		(26,896	)		(25,908	)
	Proceeds from the dispositions of property and equipment		32			38,075
	Contributions to equity investees		(4,702	)		(169	)
Net cash provided by (used in) investing activities			(31,566	)		11,998
Cash flows from financing activities:
	Proceeds from exercise of common stock options		5,477			955
	Repurchase of $2.28 cumulative preferred stock		—			(129	)
	Payments on revolving credit facility		(279,400	)		(301,953	)
	Borrowings under revolving credit facility		282,600			248,250
	Effect of re-priced options		343			—
	Dividends paid		(3,767	)		(4,205	)
Net cash provided by (used in) financing activities			5,253			(57,082	)
Net increase (decrease) in cash and cash equivalents			(3,788	)		61,460
Cash and cash equivalents at beginning of period			10,032			12,927
Cash and cash equivalents at end of period		$	6,244		$	74,387

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 March 31,
			2002			2001
Revenues:
	Sale of gas		$	544,111		$	1,044,876
	Sale of natural gas liquids			64,808			129,477
	Processing and transportation revenue			16,909			16,036
	Unrealized gain (loss) on marketing activities			(10,995	)		5,049
	Other, net			1,933			1,838
		Total revenues		616,766			1,197,276
Costs and expenses:
	Product purchases			544,606			1,086,600
	Plant operating expense			18,871			17,037
	Oil and gas exploration and production expense			7,389			9,605
	Depreciation, depletion and amortization			17,946			14,478
	Gain (loss) on sale of assets			9			(11,223	)
	Selling and administrative expense			8,691			8,479
	Interest expense			6,660			6,829
		Total costs and expenses		604,172			1,131,805
Income before taxes				12,594			65,471
Provision for income taxes:
	Current			758			8,162
	Deferred			3,836			16,719
		Total provision for income taxes		4,594			24,881
Net income				8,000			40,590
Preferred stock requirements				(2,130	)		(2,584	)
Income attributable to common stock			$	5,870		$	38,006
Earnings per share of common stock			$	.18		$	1.17
Weighted average shares of common stock outstanding				32,760,081			32,405,044
Income attributable to common stock—assuming dilution			$	5,870		$	39,817
Earnings per share of common stock—assuming dilution			$	.18		$	1.08
Weighted average shares of common stock outstanding—assuming dilution				33,457,239			36,757,118

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 Stock- holders' 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, three months ended March 31, 2002		—	—	—	—	—		—		—		—		—			—		8,000			—			—			8,000
	Translation adjustments		—	—	—	—	—		—		—		—		—			—		—			183			—			183
	Reclassification adjustment for settled contracts		—	—	—	—	—		—		—		—		—			—		—			(4,392	)		—			(4,392	)
	Changes in fair value of outstanding hedging positions		—	—	—	—	—		—		—		—		—			—		—			(7,507	)		—			(7,507	)
	Reduction due to estimated ineffectiveness		—	—	—	—	—		—		—		—		—			—		—			(245	)		—			(245	)
	Fair value of new hedge positions		—	—	—	—	—		—		—		—		—			—		—			(253	)		—			(253	)
		Change in accumulated derivative comprehensive income	—	—	—	—	—		—		—		—		—			—		—			(12,397	)		—			(12,397	)
	Total comprehensive income, net of tax																												(4,214	)
Stock options exercised			—	—	—	286,761	—		—		—		26		—			5,451		—			—			—			5,477
Effect of re-priced stock options			—	—	—	—	—		—		—		—		—			343		—			—			—			343
Tax benefit related to stock options			—	—	—	—	—		—		—		—		—			—		—			—			—			—
Loans forgiven			—	—	—	—	—		—		—		—		—			—		—			—			—			—
Dividends declared on common stock			—	—	—	—	—		—		—		—		—			—		(1,649	)		—			—			(1,649	)
Dividends declared on $2.28 cumulative preferred stock			—	—	—	—	—		—		—		—		—			—		(319	)		—			—			(319	)
Dividends declared on $2.625 cumulative convertible preferred stock			—	—	—	—	—		—		—		—		—			—		(1,811	)		—			—			(1,811	)
Repurchase of $2.28 cumulative preferred stock			—	—	—	—	—		—		—		—		—			—		—			—			—			—
Balance at March 31, 2002			591,136	44,290	2,760,000	32,975,770	25,016	$	59	$	276	$	3,319	$	(1,907	)	$	393,299	$	70,349		$	6,668		$	(884	)	$	471,179

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 March 31, 2002 and for the three month periods ended March 31, 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 months ended March 31, 2002 are not necessarily indicative of the results of operations expected for the year ended December 31, 2002.

        Prior period 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-month periods ended March 31, 2002 and 2001, respectively. Common stock options and our $2.625 Cumulative Convertible Preferred Stock are potential common shares. Outstanding common stock options in both three-month periods and our $2.625 Cumulative Convertible Preferred Stock, which is convertible into 3,471,698 shares of common stock, in the three months ended March 31, 2001 had a dilutive effect on earnings. This resulted in an increase in the weighted average number of shares of common stock outstanding by 697,158 and 4,352,074 for the three-month periods ended March 31, 2002 and 2001, respectively. The numerators and the denominators for these periods were adjusted to reflect these potential shares and any related preferred dividends in calculating fully diluted earnings per share.

ACCUMULATED OTHER COMPREHENSIVE INCOME

        Included in Accumulated other comprehensive income at March 31, 2002 were unrealized gains of $4.7 million from the fair value of derivatives designated as cash flow hedges and $1.9 million of cumulative foreign currency translation adjustments.

        Included in Accumulated other comprehensive income at March 31, 2002 were unrealized losses of ($8.4) million from the fair value of derivatives designated as cash flow hedges and $2.4 million of cumulative foreign currency translation adjustments.

OTHER INFORMATION

        Bethel Treating Facility.    In December 2000, we signed an agreement with Anadarko Petroleum Corporation for the sale of all the outstanding stock of our wholly-owned subsidiary, Pinnacle Gas Treating, Inc. ("Pinnacle") for $38.0 million. The only asset of this subsidiary was a 300 MMcf per day treating facility and 86 miles of associated gathering assets located in east Texas. The sale closed in January 2001 and resulted in a net pre-tax gain for financial reporting purposes of $12.1 million in the first quarter of 2001. The proceeds from this sale were used to reduce borrowings outstanding on the Revolving Credit Facility.

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 133.

SUPPLEMENTARY CASH FLOW INFORMATION

        Interest paid was $3.0 million and $4.2 million for the three months ended March 31, 2002 and 2001, respectively.

        No income taxes were paid during the three months ended March 31, 2002 or the three months ended March 31, 2001.

SEGMENT REPORTING

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

        In the Gas Gathering, Processing and Treating 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. The Marketing segment sells the residue gas and NGLs extracted at our processing facilities.

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

        Our Marketing segment buys and sells gas and NGLs in the United States and Canada from or to a variety of customers. In addition, this segment also markets gas and NGLs produced by our gathering, processing and production assets. Also included in this segment are our Canadian marketing operations (which are immaterial for separate presentation). The Marketing segment also includes gains and (losses) associated with our equity gas and NGL hedging program of $9.4 million and ($14.5) million for the three months ended March 31, 2002 and 2001, respectively.

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

        The following table sets forth our segment information as of and for the three months ended March 31, 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, Processing and Treating		Exploration and Production			Marketing			Transmission		Corporate		Eliminating Entries			Total
Quarter ended March 31, 2002
Revenues from unaffiliated customers	$	14,451	$	1,309		$	598,707		$	3,004	$	16	$	—		$	617,487
Interest income		—		10			—			—		1,827		(1,800	)		37
Other, net		352		(17	)		(1,622	)		12		517		—			(758	)
Inter-segment sales		121,115		20,984			3,560			4,129		14		(149,802	)		—
Total revenues		135,918		22,286			600,645			7,145		2,374		(151,602	)		616,766
Product purchases		101,192		1,700			584,070			—		322		(142,678	)		544,606
Plant operating expense		16,532		—			—			2,615		232		(508	)		18,871
Oil and gas exploration and production expense		—		13,045			—			—		—		(5,656	)		7,389
Operating profit	$	18,194	$	7,541		$	16,575		$	4,530	$	1,820	$	(2,760	)	$	45,900
Depreciation, depletion and amortization		10,275		5,643			40			435		1,553		—			17,946
Interest expense																	6,660
Gain on sale of assets																	9
Selling and administrative expense																	8,691
Income before income taxes																$	12,594
Identifiable assets	$	608,524	$	195,732		$	79		$	46,412	$	58,246	$	—		$	908,993

	Gas Gathering, Processing and Treating		Exploration and Production			Marketing			Transmission			Corporate		Eliminating Entries			Total
Quarter ended March 31, 2001
Revenues from unaffiliated customers	$	14,035	$	721		$	1,209,769		$	2,675		$	282	$	—		$	1,227,482
Interest income		—		—			—			—			5,086		(4,802	)		284
Other, net		4		(1	)		(31,872	)		2			1,377		—			(30,490	)
Inter-segment sales		318,073		52,150			11,486			4,267			14		(385,990	)		—
Total revenues		332,112		52,870			1,189,383			6,944			6,759		(390,792	)		1,197,276
Product purchases		272,839		2,645			1,188,165			(434	)		13		(376,628	)		1,086,600
Plant operating expense		15,320		30			39			2,094			375		(821	)		17,037
Oil and gas exploration and production expense		—		17,054			—			—			—		(7,449	)		9,605
Operating profit	$	43,953	$	33,141		$	1,179		$	5,284		$	6,371	$	(5,894	)	$	84,034
Depreciation, depletion and amortization		9,500		3,067			40			415			1,456		—			14,478
Interest expense																		6,829
Gain on sale of assets																		(11,223	)
Selling and administrative expense																		8,479
Income before income taxes																	$	65,471
Identifiable assets	$	563,850	$	141,430		$	57		$	46,808		$	55,384	$	—		$	807,529

LEGAL PROCEEDINGS

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

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

        In June 2001, the FASB issued SFAS No. 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 have not yet determined the impact that the adoption of SFAS No. 143 will have on our earnings or financial position.

        In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. This statement addresses the accounting for long-lived assets to be disposed of by sale, whether previously held and used or newly acquired. We have not yet determined the impact that the adoption of SFAS No. 144 will have on our earnings or financial position.

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

        The following discussion and analysis relates to factors that have affected our consolidated financial condition and results of operations for the three months ended March 31, 2002 and 2001. Certain prior year amounts have been reclassified 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 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 months ended March 31, 2002 compared to the three months ended March 31, 2001
(Dollars in thousands, except per share amounts and operating data).

	Three Months Ended March 31,
					Percent Change
	2002		2001
Financial results:
Revenues	$	616,766	$	1,197,276	(48	)
Gross profit		27,945		80,779	(65	)
Net income		8,000		40,590	(80	)
Earnings per share of common stock		.18		1.17	(85	)
Earnings per share of common stock-diluted		.18		1.08	(83	)
Net cash provided by operating activities	$	22,525	$	106,544	(80	)
Operating data:
Average gas sales (MMcf/D)		2,445		1,665	47
Average NGL sales (MGal/D)		1,940		2,230	(13	)
Average gas prices ($/Mcf)	$	2.47	$	6.97	(65	)
Average NGL prices ($/Gal)	$	.37	$	.63	(41	)

        Net income decreased $32.6 million for the three months ended March 31, 2002 compared to the same period in 2001. The decrease in net income was primarily attributable to a significant reduction in gas and NGL prices in the first quarter of 2002 compared to the same period last year. This decrease in prices more than offset increased production from the Powder River basin coal bed methane development. Also contributing to the decrease in net income was a pre-tax $8.5 million reduction in operating income from our marketing operations in the three months ended March 31, 2002 compared to the same period in 2001. The three months ended March 31, 2001 also included an after-tax gain of $7.1 million from the sale of a subsidiary corporation in that quarter. These decreases were partially offset by a net increase in after-tax gains on hedging activities on our equity gas and NGLs of $15.3 million in the first quarter of 2002 as compared to the same period in 2001.

        Revenues from the sale of gas decreased $500.8 million for the three months ended March 31, 2002 compared to the same period in 2001. This decrease was due to reduction in product prices in 2002 which more than offset an increase in sales volume. Average gas prices realized by us decreased $4.50 per Mcf to $2.47 per Mcf for the quarter ended March 31, 2002 compared to the same period in 2001. Average gas sales volumes increased 780 MMcf per day to 2,445 MMcf per day for the quarter ended March 31, 2002 compared to the same period in 2001. This increase was due to an intentional reduction in 2001 by us in our third-party transactions due to the high price of natural gas and its impact on the credit exposure to our individual counter-parties. With the decrease in prices, we have returned to a more traditional level of third party sales.

        Revenues from the sale of NGLs decreased approximately $64.7 million for the three months ended March 31, 2002 compared to the same period in 2001. This decrease is primarily due to a significant reduction in product prices and to a lesser extent, a reduction in sales volumes. Average NGL prices realized by us decreased $.26 per gallon to $.37 per gallon for the three months ended March 31, 2002 compared to the same period in 2001. Average NGL sales volumes decreased 290 MGal per day to 1,940 MGal per day for the three months ended March 31, 2002 compared to the same period in 2001.

        Product purchases decreased by $542.0 million for the quarter ended March 31, 2002 compared to the same period in 2001 as a result of the significant decrease in commodity prices. Overall, combined product purchases as a percentage of sales of all products decreased to 89% in the first quarter of 2002 from 91% in the first quarter of 2001. The reduction in this percentage is primarily the result of the decrease in commodity prices and our level of third party purchases and sales.

        Marketing margins on residue gas averaged $.02 per Mcf in the first quarter of 2002 compared to $.06 per Mcf in the first quarter of 2001. Marketing margins on NGLs averaged $.01 per gallon in the first quarter of 2002 compared to $.008 per gallon in the first quarter of 2001. The reduction in the margin earned on the sale of residue gas was due to a $5.0 million gain in the first quarter of 2001 resulting from the adoption of SFAS 133, "Accounting for Derivative Instruments and Derivative Activities", and lesser margin earned in the quarter ended March 31, 2002 on our firm transportation capacity positions. There is no assurance, however, that these market conditions for our gas and NGL products and related margins will continue in the future, that we will be in a similar position to benefit from them or that we will continue to originate the same amount of transactions in future quarters. During the first quarter of 2002, we did not add to our reserve for doubtful accounts and in the first quarter of 2001 we reserved a total of $1.6 million for doubtful accounts. This reserve is not included in the calculation of the marketing margins and is reported in Selling and administrative expenses.

        Oil and gas exploration and production expenses decreased $2.2 million for the quarter ended March 31, 2002 compared to the same period in 2001. This decrease is due to a reduction in production taxes resulting from the significant decrease in price received for natural gas, which was partially offset by an increase in lease operating expenses resulting from an increase in the number of wells and higher utility costs.

        Depreciation, depletion and amortization increased by $3.4 million in the quarter ended March 31, 2002 compared to the same period in 2001 due to increased production and the number of wells in operation. Also contributing to the increase is the reduction in product prices which reduced the average calculated reserves per well.

Cash Flow Information

        Cash flows from operating activities decreased by $84.0 million in the first quarter of 2002 compared to the same period in 2001. This reduction was primarily due to a decrease in net income in the first quarter of 2002 compared to the prior year and the timing of cash receipts and payables.

        Cash flows from investing activities decreased by $43.6 million in the first quarter of 2002 compared to the same period in 2001. This reduction was primarily due to the sale of our Bethel Treating facility in the first quarter of 2001.

        Cash flows from financing activities increased by $62.3 million in the first quarter of 2002 compared to the same period in 2001. This increase was due to the application of the proceeds received in the sale of our Bethel Treating facility in the first quarter of 2001 to reduce the amounts outstanding under our revolving credit facility.

Other Information

        Bethel Treating Facility.    In December 2000, we signed an agreement with Anadarko Petroleum Corporation for the sale of all the outstanding stock of our wholly-owned subsidiary, Pinnacle, for $38.0 million. The only asset of this subsidiary was a 300 MMcf per day treating facility and 86 miles of associated gathering assets located in east Texas. The sale closed in January 2001 and resulted in an approximate pre-tax gain for financial reporting purposes of $12.1 million in the first quarter of 2001. The proceeds from this sale were used to reduce borrowings outstanding on the Revolving Credit Facility.

Business Strategy

        Maximizing the value of our existing core assets is the focal point of our business strategy. Our core assets are our midstream operations in west Texas and Oklahoma and our fully integrated upstream and midstream assets in the Powder River and Green River Basins in Wyoming. 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, development, in the Green River Basin and in the Sand Wash Basin. We have acquired drilling rights on approximately 827,000 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 of our producing properties remains at over 13 years. Our production in the first quarter of 2002 as compared to the same period in 2001 increased by 33% to 10.9 Bcfe and in 2001, we replaced 275% of that year's production. All of our 2001 reserve growth and our 2002 production growth 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 development locations in the Big George, Wyodak and related coals. 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.

        We are also actively seeking to add another core project which is focused on Rocky Mountain natural gas. We will utilize our expertise in the low-risk development of coal bed methane plays and in tight-gas sands 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 to seek to increase 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 and process 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 and processing at our facilities. At December 31, 2001, our estimated dedicated reserves totaled 3.2 Tcf. This includes third party reserves dedicated to our facilities, our proven reserves, but does not include our 2.1 Tcf of probable and possible reserves. 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 quarter of 2002, we spent approximately $23.0 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.

        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 operating facilities to ensure that a satisfactory rate of return is achieved. If an operating facility is not generating targeted returns or is outside of our core operating areas, we explore various options, such as consolidation with other Western-owned or 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 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 or for our other liquidity needs, 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, or general downturns in the national economy, 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, developing our existing leaseholds, 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 including contributions to joint ventures, make any scheduled debt principal and interest payments and to pay common and preferred dividends. Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital. Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or use a combination of alternatives. While we believe that we would be able to secure additional financing, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing. We also believe that cash provided by operating activities and amounts available under the Revolving Credit Facility will be sufficient to meet our debt service and preferred stock dividend requirements for 2002.

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

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

        Our sources and uses of funds for the quarter ended March 31, 2002 are summarized as follows (dollars in thousands):

Sources of funds:
	Borrowings under revolving credit facility		$	282,600
	Proceeds from the dispositions of property and equipment			32
	Net cash provided by operating activities			22,525
	Proceeds from exercise of common stock options			5,477
	Other			343
		Total sources of funds	$	310,977
Uses of funds:
	Payments related to long-term debt (including debt issue costs)		$	279,400
	Capital expenditures			26,896
	Dividends paid			3,767
	Contributions to equity investments			4,702
		Total uses of funds	$	314,765

        Inventories and Storage Capacity.    An additional source of liquidity available to us is our inventories of gas and NGLs in storage facilities. We continue to view access to storage capacity as 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 March 31, 2002, we had contracts in place for approximately 17.3 Bcf of storage capacity at various third-party facilities. A contract for storage capacity for 3 Bcf expired in April 2002. The fees associated with these contracts during 2002 will average $0.30 per Mcf of annual capacity, and the associated contract periods range from three months to three years, with an average tenor of one and one-half years. Several of these long-term storage contracts require an annual renewal. At March 31, 2002, we held gas in storage and in imbalances of approximately 9.0 Bcf at an average cost of $2.04 per Mcf compared to 2.4 Bcf at an average cost of $5.03 per Mcf at March 31, 2001 under these storage contracts. These positions are for storage withdrawals within the next twelve months. Under mark-to-market accounting, the profit to be earned on these transactions was recorded in the month of origination.

        At March 31, 2002, we also held NGLs in storage at various third-party facilities of 3,261 MGal, consisting primarily of propane and normal butane, at an average cost of $0.27 per gallon compared to 5,831 MGal at an average cost of $0.44 per gallon at March 31, 2001.

        Firm Transportation Capacity.    We also continue to view access to firm transportation as a significant element of our marketing 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 March 31, 2002, we had contracts for approximately 628 MMcf per day of firm transportation. This amount represents our total contracted amount on each individual pipeline. In many cases it is necessary to utilize sequential pipelines to deliver gas into a specific sales market. For example, to transport 100 MMcf per day of gas produced in the Powder River to the Mid-Continent utilizes a total of 300 MMcf per day of firm capacity on four separate pipelines. The fixed fees associated with these contracts during 2002 will average approximately $0.13 per Mcf per day, and the associated contract periods range from three months to fifteen years. In addition, some contracts contain provisions requiring us to pay the fees associated with these contracts whether or not the transportation is used. In conjunction with an expansion of the Trailblazer pipeline in May 2002, we entered into a ten-year contract for an additional 56 MMcf per day of firm transportation capacity on this pipeline at the prevailing tariff. We have also entered into 112 MMcf per day of firm transportation precedent agreements for transportation on pipeline expansions which are not completed. These expansions are anticipated to be completed in 2002. When the expansions are completed, we will enter into firm transportation agreements.

        Operating Leases.    Primarily to support our growing development in the Powder River coal bed development, we have entered into several 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. As of March 31, 2002, we had leased a total of 93 compression units. These leases have terms ranging from two to ten years with fair market purchase options available at various times during the lease. We anticipate entering into additional leases during 2002 to accommodate future production growth in the Powder River coal bed development.

        Capital Investment Program.    Capital expenditures related to existing operations totaled approximately $31.6 million during the first quarter of 2002, consisting of the following: (i) approximately $12.0 million related to gathering, processing and pipeline assets, including $700,000 for maintaining existing facilities; (ii) approximately $17.7 million related to exploration and production activities; and (iii) approximately $1.9 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 49% and 31%, respectively, of the total capital expenditures in the quarter.

        We expect capital expenditures related to existing operations to be approximately $139.8 million during 2002. The 2002 budget represents an approximate 15% 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 $69.3 million related to gathering, processing, treating and transportation assets, including $6.4 million for maintaining existing facilities; (ii) approximately $67.6 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 54% and 25%, 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 gas reserves and 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 quarter of 2002, we continued to be the largest producer of natural gas (together with our partner), the largest gatherer of natural gas and the largest gas transporter out of this basin. At March 31, 2002, we held the drilling rights on approximately 527,000 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.

        We plan to participate in over 900 gross wells in 2002, of which 378 were drilled in the first quarter. 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 250 to 320 million cubic feet, MMcf. Our average finding and development costs in this area are estimated to be approximately $0.42 per Mcf. As deeper wells are drilled to the Big George coal, reserves per well are expected to increase as will the average cost per well. It is expected that the deeper Big George wells will result in a higher rate of return. Our share of production from wells in which we own an interest has increased from an average of approximately 81 MMcf per day in the three months ended March 31, 2001 to 106 MMcf per day in the three months ended March 31, 2002. As of May 1, 2002, we were producing an average of 113 MMcf per day, net to our interest. We currently anticipate production rates of 145 net MMcf per day (370 gross MMcf per day) from this area by the end of 2002. Within the Hoe Creek area of the Powder River Basin, approximately 150 gross wells have not responded to dewatering as expected and may not achieve our original estimate of production or reserves. All of the remaining areas under development in the Wyodak coal continue to produce at or above forecasted levels.

        We are currently evaluating fourteen pilot development areas in the Big George. By the end of 2002, we expect to have drilled approximately 425 gross wells in these areas. Several of these areas are in close proximity to four producing Big George areas, including our All Night Creek pilot. Production from these areas is increasing and in the first quarter of 2002, they were producing over 28 MMcf per day. As of February 20, 2002, our All Night Creek pilot was producing 7.5 gross MMcf per day of gas from 51 wells with an additional 18 wells in the de-watering stage and another 29 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 federal acreage will be delayed subject to completion of the Powder River Basin Oil & Gas Environmental Impact Statement (EIS). The comment period for the draft EIS has been extended to May 15, 2002. We anticipate the study to be completed in the late third or early fourth quarter of 2002. However, we can make no assurance the EIS will be completed within this time period. Our drilling plans for 2002 are not expected to be substantially impacted by this study due to our large inventory of non-federal drilling locations and the issuance of drilling permits by the Bureau of Land Management, BLM, for approximately 250 well locations to prevent drainage of federal acreage. Our drilling plans for 2003 are dependent on permits to be issued pursuant to the completion of the EIS. However, we could drill up to 800 wells on various state and fee acreage in 2003 without the completion of the EIS.

        Additionally, the Wyoming Department of Environmental Quality, DEQ, has revised some standards for surface water discharge that have allowed the issuance of most of the permits that apply to the Cheyenne and Belle Fourche drainage areas. The majority of wells on our acreage 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 drainage areas, in which most of our Big George prospects are located. The Wyoming DEQ has begun to release permits on a limited basis to the Powder River drainage area, however only when it can be demonstrated that none of the discharge water will reach the Powder River itself. Discussions are in progress between the Wyoming and Montana DEQ offices to implement numeric standards for sodium absorption ratio, electro-conductivity and total dissolved solids. 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 timing of the associated production.

        On April 26, 2002, the Interior Board of Land Appeals (IBLA) ruled that the Bureau of Land Management (BLM) did not comply with the National Environmental Policy Act (NEPA) prior to issuing three federal oil and gas leases held by unaffiliated third parties 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. Additionally, the decision by the IBLA is still under review by the parties involved in the case and further action may include a petition to overturn the decision by the Secretary of the Interior, a petition for reconsideration or filing for judicial review. 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 quarter of 2002, we were gathering 348 MMcf per day of our own production and that of other third-party producers. Of that volume, approximately 130 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 $15.5 million was spent in the first quarter. 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 March 31, 2002, we had leased a total of 93 compression units. These leases have terms ranging from two to ten years with 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. Due to drilling and regulatory uncertainties which are beyond our control, we can make no assurance that we will incur this level of capital expenditure.

        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 the fourth quarter of 2000, Western 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 $7.3 million of the debt of Fort Union. 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. These facilities have a combined operational capacity of 327 MMcf per day and processed an average of 237 MMcf per day in the first quarter of 2002. Our capital budget in this area provides for expenditures of approximately $35.1 million during 2002 of which $10.5 million was spent in the first quarter. This capital budget includes approximately $12.5 million for drilling costs and production equipment and approximately $22.6 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 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 Western 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 with a capacity to transport approximately 275 MMcf per day of gas production from the Pinedale Anticline. The first phase of our 50% owned Rendezvous gathering expansion into the Pinedale Anticline is completed. The second phase of the construction is expected to be completed in November 2002. The first two phases will add a total of 175 MMcf per day of gathering capacity. This gas will be delivered for blending or processing at either our Granger Complex or at a Questar processing facility. The total estimated construction cost of this expansion is $44.0 million, of which our share will be $22.0 million. Of this $22.0 million, approximately $18.3 million is expected to be spent in 2002 and is included in our capital expenditure budget.

        At March 31, 2002, we owned approximately 245,000 gross oil and gas leasehold acres, or approximately 35,000 net acres, in the Jonah Field and Pinedale Anticline areas. During 2002, we expect to participate in the drilling of over 30 gross wells, or approximately 4 net wells on the Pinedale Anticline. Drilling in this area cannot commence until the removal of winter stipulations in May 2002. The expected drilling and completion costs per gross well are approximately $2.4 million to $3.5 million and the average well depth in this area approximates 13,000 feet. Our average finding and development costs are estimated to be $0.80 to $0.90 per Mcf. We had established proven developed and undeveloped reserves totaling 71 Bcfe at December 31, 2001. 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.

Financing Facilities

        Revolving Credit Facility.    The Revolving Credit Facility is with a syndicate of banks and provides for a maximum borrowing commitment of $250 million consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A, and a $167 million Revolving Credit Facility, or Tranche B, which matures on April 30, 2004. At March 31, 2002, $98.0 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 March 31, 2002, the interest rate payable on the borrowings under this facility was 2.9%. 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 and sale leaseback transactions. This facility is guaranteed by, and secured via, a pledge of the stock of all of our material subsidiaries.

        Master Shelf Agreement.    In December 1991, we entered into a Master Shelf Agreement with The Prudential Insurance Company of America. Amounts outstanding under the Master Shelf Agreement at March 31, 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 40% through March 2002 and not more than 35% thereafter. 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 certain non-recurring items. In addition, this agreement contains a calculation limiting dividends. Under this limitation, approximately $79.4 million was available to be paid at March 31, 2002. This facility also limits our ability to enter into operating 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 secured 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 will make a required principal repayment 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 Senior Subordinated Notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%. These notes contain maintenance covenants which include limitations on debt incurrence, restricted payments, liens and sales of assets. Under the calculation limiting restricted payments, including common dividends, approximately $46.8 million was available at March 31, 2002. The Senior Subordinated Notes are unsecured and are guaranteed on a subordinated basis by some of our subsidiaries. We incurred approximately $5.0 million in offering commissions and expenses which have been capitalized and are being amortized over the term of the notes.

        Covenant Compliance.    We were in compliance with all covenants in our debt agreements at March 31, 2002. Taking into account all the covenants contained in these agreements, we had approximately $118 million of available borrowing capacity at March 31, 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 use futures, swaps and options to reduce price risk and basis risk. Basis is the difference in price between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations.

        We enter into futures transactions on the New York Mercantile Exchange, or NYMEX, and the Kansas City Board of Trade and through OTC swaps and options with various counter parties, consisting primarily of financial institutions and other natural gas companies. We conduct our standard credit review of OTC counter parties and have agreements with 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.

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

        Hedge Positions.    For the remaining three quarters of 2002, we have hedged approximately 58% of our projected equity natural gas volumes and approximately 59% of our estimated equity production of crude oil, condensate, and NGLs. In 2003, we have entered into hedging positions for approximately 25% of our projected equity gas volumes. 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. During the quarter ended March 31, 2002, we recognized a total of $426,000 of loss from the ineffective portions of our 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.

        For the remaining three quarters of 2002, we have entered into hedging positions for approximately 58 percent and 59 percent of our projected equity gas and NGL volumes respectively. In 2003, we have entered into hedging positions for approximately 25 percent of our projected equity gas volumes.

Outstanding Equity Hedges for the remainder of 2002. All prices are NYMEX-equivalents and do not include the cost of NGL hedges in 2002 of approximately $3 million.

	2nd Quarter of 2002	3rd and 4th Quarters of 2002
Natural gas	80,000 MMbtu per day with an average minimum and maximum price of $3.81 and $5.87 per MMbtu, respectively.
Crude, Condensate, Natural Gasoline and Butanes	75,000 Barrels per month Fixed price of $20.20 per barrel	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 Fixed price of $21.15 per barrel	55,000 Barrels per month Floor at $20.00 per barrel
Propane	75,000 Barrels per month Fixed price of $0.32 per gallon	120,000 Barrels per month Floor at $0.32 per gallon
Ethane	50,000 Barrels per month Fixed price of $0.21 per gallon	50,000 Barrels per month Floor at $0.21 per gallon
	20,000 Barrels per month Sold 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

Outstanding Equity Hedges for 2003. All prices are NYMEX equivalents.

Natural gas	20,000 MMbtu per day at an average price of $3.75 per MMbtu.
	20,000 MMbtu per day with a minimum price of $3.50 and an average maximum price of $4.43 per MMbtu.

        Account balances related to these transactions at March 31, 2002, were $12.9 million in Current Assets from price risk management activities, $1.3 million in Non-current Assets from price risk management activities, $7.1 million in Current Liabilities from price risk management activities, $2.7 million in Deferred income taxes payable, net and a $4.7 million after-tax unrealized gain in Accumulated other comprehensive income, a component of Shareholder's Equity. Based on the commodity prices as of March 31, 2002, an after-tax gain of $3.7 million would be re-classified from Accumulated other comprehensive income to Product Purchases during the next twelve months.

        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 March 31, 2002, the net notional value of such contracts was approximately $1.7 million in Canadian dollars, which approximates its 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 133.

Principal Facilities

        The following tables provide information concerning our principal facilities at March 31, 2002. We also own and operate several smaller treating, processing and transmission facilities located in the same areas as our other facilities.

						Average for the Quarter Ended March 31, 2002
				Gas Gathering System Miles(2)	Gas Throughput Capacity (MMcfD)(3)
Facilities(1)			Year Placed In Service			Gas Throughput (MMcfD)(4)	Gas Production (MMcfD)(5)	NGL Production (MGalD)(5)
Texas
	Gomez Treating(6)		1971	386	280	97	88	—
	Midkiff/Benedum		1949	2,203	165	140	95	858
	Mitchell Puckett Gathering(6)		1972	93	120	56	36	—
Louisiana
	Toca(7)(8)		1958	—	160	81	76	64
Wyoming
	Coal Bed Methane Gathering		1990	1,253	223	342	189	—
	Fort Union Gas Gathering		1999	106	635	412	412	—
	Granger(7)(9)(10)		1987	523	235	194	151	179
	Hilight Complex(7)		1969	626	124	15	47	10
	Kitty/Amos Draw(7)		1969	314	17	9	5	31
	Lincoln Road(10)		1988	149	50	30	28	12
	Newcastle(7)		1981	146	5	3	2	18
	Red Desert(7)		1979	111	42	13	11	22
	Rendezvous Gas Services(14)		2001		170	167	165	—
	Reno Junction(9)		1991	—	—	—	—	100
Oklahoma
	Chaney Dell		1966	2,080	130	145	127	313
	Westana		1981	1,001	45	78	73	16
New Mexico
	San Juan River(6)		1955	140	60	24	23	15
Utah
	Four Corners Gathering		1988	104	15	2	2	9
		Total		9,235	2,476	1,808	1,530	1,647

				Average for the Quarter Ended March 31, 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	185
MGTC(12)		1963	252	18	12
	Total		497	148	197

(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 March 31, 2002.

(3)

Gas throughput capacity is as of March 31, 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)

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

(8)

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

(9)

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

(10)

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

(14)

Rendezvous Gas Services, L.L.C. was formed in October 2001.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

        Western Gas Resources, Inc., v. Amerada Hess Corporation, District Court, Denver County, Colorado, Civil Action No. 00-CV-1433.    We were a defendant in prior litigation, styled as Berco Resources, Inc. v. Amerada Hess Corporation and Western Gas Resources, Inc., United States District Court, District of Colorado, Civil Action No. 97-WM-1332, which was settled in 2000 for an amount which did not have a material impact on our 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. We are reviewing the trial court's ruling for the possibility of appeal.

        Texas Natural Resource Conservation Commission (TNRCC)—Notification of Alleged Violations, Midkiff, Texas.    We have received notification of six alleged violations associated with our air emissions permit at the Midkiff Gas Plant in Texas. Five of the alleged violations relate to reporting requirements under the permit and one alleged violation relates to the failure to operate within the time restrictions of the permit. We have responded to the TNRCC and are taking corrective action. 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.    The Company has 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 facility had been physically removed by the unaffiliated company 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.

Item 4. Submission of Matters to a Vote of Security Holders

        None.

Item 6. Exhibits and Reports on Form 8-K

(a)

Exhibits:

10.26	Eighth Amendment dated February 25, 2002 to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc., and Bank of America, N.A., as agent, and the Lenders.
10.27	Limited Waiver, Consent, Release and Amendment No. 6 dated March 1, 2002 to the Second Amended and Restated Master Shelf Agreement by and among Western Gas Resources, Inc., and The Prudential Insurance Company of America and Pruco Life Insurance Company.
10.28	Ninth Amendment dated April 26, 2002 to Loan Agreement dated April 29, 1999 by and among Western Gas Resources, Inc., and Bank of America, N.A., as agent, and the Lenders.

(b)

Reports on Form 8-K:

A report on Form 8-K was filed on February 28, 2002 furnishing information pursuant to Regulation FD, Rules100-103 that provided projections related to the Company's expected operational performance in 2002.

A report on Form 8-K was filed on April 15, 2002 announcing the Company's hedging positions for 2003.

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: May 14, 2002	By:	/s/  PETER A. DEA Peter A. Dea Chief Executive Officer and President
Date: May 14, 2002	By:	/s/  WILLIAM J. KRYSIAK William J. Krysiak Chief Financial Officer (Principal Financial and Accounting Officer)