WESTERN GAS RESOURCES INC - 10-Q Quarterly Report

UNITED STATES
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, 2003

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.)

1099 18^th Street, Suite 1200, Denver, Colorado		80202
(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

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

On November 1, 2003, there were 33,238,670 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, 2003 and December 31, 2002

	Consolidated Statement of Cash Flows - Nine months Ended September 30, 2003 and 2002

	Consolidated Statement of Operations - Three and Nine months Ended September 30, 2003 and 2002

	Consolidated Statement of Changes in Stockholders’ Equity - Nine months Ended September 30, 2003

	Condensed 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, 2003			December 31, 2002
	(unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	57,890		$	7,312
Trade accounts receivable, net	215,331			253,587
Inventory	71,904			43,482
Assets held for sale	445			3,250
Assets from price risk management activities	22,312			34,873
Other	16,419			27,744
Total current assets	384,301			370,248

Property and equipment:
Gas gathering, processing, and transportation	996,401			942,147
Oil and gas properties and equipment (successful efforts method)	307,277			252,747
Construction in progress	129,495			104,033
	1,433,173			1,298,927
Less: Accumulated depreciation, depletion and amortization	(478,353		)	(432,281		)

Total property and equipment, net	954,820			866,646

Other assets:
Gas purchase contracts (net of accumulated amortization of $38,508 and $37,232, respectively)	29,648			30,924
Assets from price risk management activities	2,199			406
Other	43,638			33,920

Total other assets	75,485			65,250

TOTAL ASSETS	$	1,414,606		$	1,302,144
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	263,362		$	242,987
Accrued expenses	56,926			51,509
Liabilities from price risk management activities	15,979			34,811
Dividends payable	3,472			3,464
Total current liabilities	339,739			332,771

Long-term debt	341,333			359,933
Liabilities from price risk management activities	1,247			406
Other long-term liabilities	21,428			1,713
Deferred income taxes payable, net	166,522			124,253

Total liabilities	870,269			819,076

Stockholders’ equity:
Preferred Stock; 10,000,000 shares authorized: $ 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; 33,222,188 and 33,077,611 shares issued, respectively	3,347			3,329
Treasury stock, at cost; 25,016 common shares in treasury	(788		)	(788		)
Additional paid-in capital	383,810			381,066
Retained earnings	157,045			102,292
Accumulated other comprehensive income	647			(2,812		)
Notes receivable from key employees secured by common stock	—			(295		)

Total stockholders’ equity	544,337			483,068

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,414,606		$	1,302,144

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,
	2003			2002

Reconciliation of net income to net cash provided by operating activities:
Net income	$	65,164		$	35,153
Add income items that do not affect cash:
Depreciation, depletion and amortization	53,305			54,002
Loss on the sale of property and equipment	142			644
Cumulative effect of change in accounting principle	6,724			—
Deferred income taxes	39,272			14,602
Non-cash change in fair value of derivatives	(1,084		)	2,733
Other non-cash items, net	2,527			694

Adjustments to working capital to arrive at net cash provided by operating activities:
(Increase) decrease in trade accounts receivable	38,717			(23,276		)
(Increase) decrease in product inventory	(28,379		)	6,238
(Increase) decrease in other current assets	9,882			(15,892		)
(Increase) decrease in other assets and liabilities, net	(478		)	373
Increase (decrease) in accounts payable	20,375			(26,399		)
Increase in accrued expenses	4,306			23,993

Net cash provided by operating activities	210,473			72,865

Cash flows from investing activities:

Purchases of property and equipment	(125,484		)	(87,784		)
Proceeds from the dispositions of property and equipment	3,831			33,404
Contributions to equity investees	(10,450		)	(7,637		)

Net cash used in investing activities	(132,103		)	(62,017		)

Cash flows from financing activities:

Net proceeds from exercise of common stock options	3,062			6,434
Debt issue costs paid	(1,851		)	(123		)
Payments of long-term debt	15,000			—
Payments on revolving credit facility	(780,800		)	(732,780		)
Borrowings under revolving credit facility	747,200			723,280
Dividends paid	(10,403		)	(11,326		)

Net cash provided by (used in) financing activities	(27,792		)	(14,515		)

Net increase in cash and cash equivalents	50,578			(3,667		)

Cash and cash equivalents at beginning of period	7,312			10,032

Cash and cash equivalents at end of period	$	57,890		$	6,365

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,
	2003			2002			2003			2002

Revenues:
Sale of gas	$	556,606		$	510,764		$	1,890,435		$	1,566,551
Sale of natural gas liquids	86,009			85,214			258,568			229,888
Gathering, processing and transportation revenue	21,884			17,007			63,119			47,466
Non-cash change in fair value of derivatives	1,564			396			1,084			(2,733		)
Other	737			701			2,191			2,954
Total revenues	666,800			614,082			2,215,397			1,844,126

Costs and expenses:
Product purchases	566,937			529,911			1,898,375			1,602,806
Plant and transportation operating expense	21,944			20,824			66,478			59,485
Oil and gas exploration and production expense	13,029			7,553			38,830			24,084
Depreciation, depletion and amortization	17,477			18,813			53,305			54,002
Loss on sale of assets	56			562			142			644
Selling and administrative expense	8,972			8,061			29,487			28,639
Earnings from equity investments	(1,780		)	(1,141		)	(5,209		)	(2,793		)
Interest expense	6,449			6,858			19,692			20,288
Total costs and expenses	633,084			591,441			2,101,100			1,787,155

Income before income taxes	33,716			22,641			114,297			56,971
Provision for income taxes:
Current	544			2,507			3,137			7,216
Deferred	12,283			6,747			39,272			14,602
Total provision for income taxes	12,827			9,254			42,409			21,818

Income before cumulative effect of change in accounting principle	20,889			13,387			71,888			35,153

Cumulative effect of change in accounting principle, net of tax benefit of $3,967	—			—			(6,724		)	—

Net income	20,889			13,387			65,164			35,153

Preferred stock requirements	(1,811		)	(2,130		)	(5,434		)	(6,390		)

Income attributable to common stock	$	19,078		$	11,257		$	59,730		$	28,763

Net income per share of common stock before cumulative effect of change in accounting principle	$	.57		$	.34		$	2.00		$	.87

Cumulative effect of change in accounting principle	$	—		$	—		$	.20		$	—

Earnings per share of common stock	$	.57		$	.34		$	1.80		$	.87

Weighted average shares of common stock outstanding	33,197,265			33,010,914			33,144,296			32,921,846

Income attributable to common stock – assuming dilution	$	20,889		$	11,257		$	65,164		$	28,763

Earnings per share of common stock – assuming dilution	$	.56		$	.34		$	1.75		$	.86

Weighted average shares of common stock outstanding - assuming dilution	37,345,148			33,589,743			37,270,704			33,580,658

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 $ 2.625 Cumulative Convertible Preferred Stock	Shares of Common Stock	Shares of Common Stock in Treasury	$ 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, 2002	2,760,000	33,077,611	25,016	$	276	$	3,329	$	(788	)	$	381,066	$	102,292		$	(2,812	)	$	(295	)	$	483,068
Comprehensive income:
Net income, nine months ended September 30, 2003	—	—	—	—		—		—			—		65,164			—			—			65,164
Translation adjustments	—	—	—	—		—		—			—		—			857			—			857
Reclassification adjustment for settled contracts	—	—	—	—		—		—			—		—			3,060			—			3,060
Changes in fair value of outstanding hedging positions	—	—	—	—		—		—			—		—			(1,354		)	—			(1,354		)
Reduction due to estimated ineffectiveness	—	—	—	—		—		—			—		—			(29		)	—			(29		)
Fair value of new hedge positions	—	—	—	—		—		—			—		—			925			—			925
Change in accumulated derivative comprehensive income	—	—	—	—		—		—			—		—			2,602			—			2,602

Total comprehensive income, net of tax																						68,623
Stock options exercised	—	144,577	—	—		18		—			2,162		—			—			—			2,180
Effect of re-priced stock options	—	—	—	—		—		—			582		—			—			—			582
Loans forgiven	—	—	—	—		—		—			—		—			—			295			295
Dividends declared on common stock ($.10 per common share)	—	—	—	—		—		—			—		(4,977		)	—			—			(4,977		)
Dividends declared on $2.625 cumulative convertible preferred stock	—	—	—	—		—		—			—		(5,434		)	—			—			(5,434		)

Balance at September 30, 2003	2,760,000	33,222,188	25,016	$	276	$	3,347	$	(788	)	$	383,810	$	157,045		$	647		$	—		$	544,337

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

WESTERN GAS RESOURCES, INC.
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

GENERAL

We have prepared the accompanying unaudited interim consolidated financial statements under the rules and regulations of the Securities and Exchange Commission. As provided by such rules and regulations, we have condensed or omitted certain information and notes normally included in annual financial statements prepared in conformity with accounting principles generally accepted in the United States of America.

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, 2002. The interim consolidated financial statements as of September 30, 2003 and for the three and nine-month periods ended September 30, 2003 and 2002 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, 2003 are not necessarily indicative of the results of operations expected for the year ended December 31, 2003.

Prior period amounts in the interim consolidated financial statements and notes have been reclassified as appropriate to conform to the presentation used in 2003.

EARNINGS PER SHARE OF COMMON STOCK

Earnings per share of common stock are 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 $1.8 million and $2.1 million for the three months ended September 30, 2003 and 2002, respectively, and $5.4 million and $6.4 million, respectively, for the nine month periods ended September 30, 2003 and 2002. Common stock options and our $2.625 cumulative convertible preferred stock are potential common shares. The following is a reconciliation of the weighted average shares of common stock outstanding to the weighted average common shares outstanding – assuming dilution.

	Quarter Ended September 30,		Nine months Ended September 30,
	2003	2002	2003	2002
Weighted average shares of common stock outstanding	33,197,265	33,010,914	33,144,296	32,921,846
Potential common shares from:
Common stock options	676,185	578,829	654,710	658,812
$ 2.625 Cumulative Convertible Preferred Stock	3,471,698	—	3,471,698	—
Weighted average shares of common stock outstanding - assuming dilution	37,345,148	33,589,743	37,270,704	33,580,658

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 September 30, 2003 were unrealized losses of $2.8 million from the fair value of derivatives designated as cash flow hedges and unrealized gains of $1.2 million of cumulative foreign currency translation adjustments.

Included in Accumulated other comprehensive income at September 30, 2002 were unrealized losses of $200,000 from the fair value of derivatives designated as cash flow hedges and $1.9 million of cumulative foreign currency translation adjustments.

CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE

In June 2001, the FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 was 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 adopted SFAS No. 143 on January 1, 2003 and recorded a $11.5 million increase to Property and equipment, a $4.4 million increase to Accumulated depreciation, depletion and amortization, a $17.8 million increase to Other long-term liabilities and a $6.7 million non-cash, after-tax loss from the Cumulative effect of a change in accounting principle.

The following is a reconciliation of the asset retirement obligation for the nine months ended September 30, 2003 (dollars in thousands):

Asset retirement obligation as of January 1, 2003	$	17,801
Liability accrued upon capital expenditures	1,758
Liability settled	(290		)
Accretion of discount expense	874
Asset retirement obligation as of September 30, 2003	$	20,143

Exclusive of assets disposed of during 2002, if we had adopted SFAS No. 143 as of January 1, 2002, we estimate that the asset retirement obligation at that date would have been $15.7 million, based on the same assumptions used in our calculation of the obligation at January 1, 2003. The estimated 2002 pro forma effect of a hypothetical January 1, 2002 adoption of SFAS No. 143 on net income and earnings per share, for annual and interim periods, is not material.

In connection with the adoption of SFAS No. 143, we completed a review of our operating assets and reevaluated the operating life and salvage values of the associated equipment. As a result of this evaluation, we extended the useful life of many of our operating assets and adjusted the estimated salvage value of our operating equipment. These adjustments resulted in an approximate $3.4 million and $9.3 million, respectively, or $0.06 and $0.16 per share of common stock - assuming dilution, respectively, decrease in depreciation, depletion and amortization in the three and nine months ended September 30, 2003, from the expense calculated using the previous useful lives. The adjustments to the salvage value and depreciable lives of our assets are treated as a revision of an estimate and are accounted for on a prospective basis.

OTHER INFORMATION

Acquisition of Gathering Systems. Effective February 1, 2003, we acquired 18 gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million. Several of the systems located in the Powder River do not integrate directly into our existing systems, and accordingly we are negotiating for the sale of these systems. We completed the sale of several of these systems during the third quarter of 2003, and the remaining systems are classified as Assets held for sale on the Consolidated Balance Sheet at September 30, 2003. During the three and nine months ended September 30, 2003, the income, if any, generated by the assets included in Assets held for sale are immaterial for separate presentation as a discontinued operation.

Acquisition of Sand Wash Properties. Effective August 15, 2003, we acquired all the capital stock of a private corporation for $12.9 million. The assets of this entity primarily consisted of non-operating interests in various Sand Wash properties operated by us.

Price Reporting to Gas Trade Publications. In the third quarter of 2003, we learned that certain employees in our marketing department furnished inaccurate information regarding natural gas transactions to energy publications, which compile and report energy index prices. We discovered the inaccuracies during a review of certain marketing activities, which is being conducted in response to a subpoena issued by the Commodity Futures Trading Commission, or CFTC. Certain of our employees have identified inaccuracies associated with reporting of natural gas transactions primarily related to points in Texas. Our review of this and other regions is continuing as we respond to the CFTC subpoena. We are unable to predict whether we will be subject to any fines or penalties by CFTC, and what the amount of such fines would be if imposed.

SUBSEQUENT EVENT

On November 7, 2003, we issued a notice of redemption for approximately 700,000 shares of our $2.625 cumulative convertible preferred stock at its liquidation preference plus 0.525% premium. The holders of this preferred stock have the right to convert in whole or in part their preferred stock into shares of our common stock in lieu of receiving the redemption price in cash. The holders may make their election at any time prior to the redemption date. The redemption date is scheduled for December 11, 2003 and to the extent required, will be funded with amounts available under our revolving credit facility. If all holders elect to receive shares of our common stock, we will issue an additional 882,000 shares of common stock, and if all holders elect to receive cash, the redemption price will total approximately $35.6 million including accrued and unpaid dividends. Also if all holders elect to receive cash, the pro rata capitalized offering costs associated with the redeemed preferred stock of $1.3 million will be reflected as a special dividend to preferred shareholders in 2003 and will reduce earnings per share of common stock by approximately $0.04 per common share in the fourth quarter of 2003.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The net loss recognized in earnings through Sale of residue gas and Sale of natural gas liquids during the first nine months of 2003 from hedging activities was $27.9 million, and we recognized a loss from hedge ineffectiveness of $46,000. Overall, our hedges are expected to continue to be “highly effective” under SFAS No. 133 in the future. An additional $1.3 million of losses were reclassified into earnings as a result of the discontinuance of cash flow hedges. These cash flow hedges were discontinued due to the reduction of forecasted production volumes.

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, 2003, approximately $4.3 million of losses in Accumulated other comprehensive income will be reclassified to earnings in 2003 and approximately $1.5 million of gains in Accumulated other comprehensive income will be reclassified to earnings in 2004.

SUPPLEMENTARY CASH FLOW INFORMATION

Interest paid was $16.9 million and $17.2 million for the nine months ended September 30, 2003 and 2002, respectively. A total of $6.0 million and $600,000 were paid in income taxes in the nine months ended September 30, 2003 and 2002, respectively.

STOCK COMPENSATION

As permitted under SFAS No. 123, “Accounting for Stock-Based Compensation”, we have elected to continue to measure compensation costs for stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” We have complied with the pro forma disclosure requirements of SFAS No. 123 as required under the pronouncement. We realize an income tax benefit from the exercise of non-qualified stock options related to the amount by which the market price at the date of exercise exceeds the option price. This tax benefit is credited to additional paid-in capital.

We are required to record compensation expense (if not previously accrued) equal to the number of unexercised re-priced options multiplied by the amount by which our stock price at the end of any quarter exceeds $21.00 per share. We had re-priced options covering 24,719 common shares outstanding at September 30, 2003 and 58,167 common shares outstanding at September 30, 2002. Based on our stock price at September 30, 2003 of $38.00 per share and our stock price at September 30, 2002 of $31.25 per share, a recovery of compensation expense of $40,000 and $358,000, respectively, was recorded in the three months ended September 30, 2003 and 2002 and compensation expense of $301,000 and a recovery of compensation expense of $35,000, respectively, was recorded in the nine months ended September 30, 2003 and 2002.

SFAS No. 123 requires pro forma disclosures for each quarter that a statement of operations is presented. The following is a summary of the options to purchase our common stock granted during the quarters and nine months ended September 30, 2003 and 2002, respectively.

	Quarter Ended September 30,		Nine months Ended September 30,
	2003	2002	2003	2002
2002 Plan	499,950	—	544,950	—
2002 Directors’ Plan	—	—	16,000	18,000
Total options granted	499,950	—	560,950	18,000

The following is a summary of the weighted average fair value per share of the options granted during the quarters and nine months ended September 30, 2003 and 2002, respectively.

	Quarter Ended September 30,			Nine months Ended September 30,
	2003		2002	2003		2002
2002 Plan	$	19.51	—	$	19.52	—
2002 Directors’ Plan	—		—	$	21.39	$	22.50

These values were estimated using the Black-Scholes option-pricing model with the following assumptions:

	2002 Plan			2002 Directors’ Plan
Risk-free interest rate	3.47		%	2.59		%
Expected life (in years)	5			5
Expected volatility	53		%	54		%
Expected dividends (quarterly)	$	0.05		$	0.05

Under SFAS No. 123, the fair market value of the options at the grant date is amortized over the appropriate vesting period for purposes of calculating compensation expense. If we had recorded compensation expense for our grants under our stock-based compensation plans consistent with the fair value method under this pronouncement, our net income, income attributable to common stock, earnings per share of common stock and earnings per share of common stock - assuming dilution would approximate the pro forma amounts below (dollars in thousands, except per share amounts):

	Quarter Ended September 30,
	2003 As Reported		2003 Pro Forma		2002 As Reported			2002 Pro Forma
Net income	$	20,889	$	19,823	$	13,387		$	12,104
Net income attributable to common stock	19,078		18,012		11,257			9,974
Earnings per share of common stock	0.57		0.54		0.34			0.30
Earnings per share of common stock - assuming dilution	0.56		0.53		0.34			0.30
Stock-based employee compensation cost, net of related tax effects, included in net income	$	34	$	—	$	(156	)	$	—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	1,100	$	—		$	1,127

	Nine months Ended September 30,
	2003 As Reported		2003 Pro Forma		2002 As Reported		2002 Pro Forma
Net income	$	65,164	$	62,578	$	35,153	$	32,646
Net income attributable to common stock	59,730		57,144		28,763		26,256
Earnings per share of common stock	1.80		1.72		0.87		0.80
Earnings per share of common stock - assuming dilution	1.75		1.68		0.86		0.78
Stock-based employee compensation cost, net of related tax effects, included in net income	$	367	$	—	$	152	$	—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	2,953	$	—	$	2,659

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 our 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 our Exploration and Production segment) to our gathering systems for delivery to our processing or treating plants, process the

natural gas to extract NGLs and treat the natural gas in order to meet pipeline specifications. In some areas, where no processing is required, we gather and compress producers’ gas and deliver it to pipelines for further delivery to market. 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, treating or processing of natural gas for periods ranging from one month to twenty years or in some cases for the life of the oil and gas lease. Approximately 83% of our plant facilities’ gross margin, or revenue at the plant less product purchases, for the month of September 2003 was under percentage-of-proceeds agreements in which we are typically responsible for the marketing of the gas and NGLs. Under these agreements, we pay producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs.

Approximately 11% of our plant facilities’ gross margin for the month of September 2003 was under 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.

Approximately 6% of our plant facilities’ gross margin for the month of September 2003 was under contracts with ‘‘keepwhole’’ arrangements or wellhead purchase contracts. 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 ‘‘keepwhole’’ 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 in the Rocky Mountain area, 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. 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. The marketing of products purchased from third-parties typically results in low operating margins relative to the sales price. We sell our products under agreements with varying terms and conditions in order to match seasonal and other changes in demand. 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 conducted through our wholly-owned subsidiary WGR – Canada, Inc. and are immaterial for separate presentation.

Transportation. The Transportation segment reflects the operations of Western’s MIGC and MGTC pipelines. The revenue generated in this segment is primarily 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. The Transportation segments’ firm capacity contracts range in duration from one month to six years.

Segment Information. The following tables set forth our segment information as of and for the three and nine months ended September 30, 2003 and 2002 (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. Prior period amounts in the interim segment information have been reclassified to conform to the presentation used in 2003.

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Elim- inating Entries			Total

Quarter Ended September 30, 2003
Revenues from unaffiliated customers
Sale of gas	$	928		$	689		$	560,803		$	219		$	—		$	—		$	562,639
Sale of natural gas liquids	3			—			87,861			—									87,864
Equity hedges:
Residue	(540		)	(5,492		)	—			—			—			—			(6,033		)
Liquids	(1,854		)	—			—			—			—			—			(1,854		)
Gathering, processing and transportation revenue	20,033			—			—			1,756			95			—			21,884
Total revenues from unaffiliated customers	18,569			(4,803		)	648,663			1,975			95			—			664,499
Inter-segment revenues	268,158			54,825			8,224			3,422			14			(334,643		)	—
Non-cash change in fair value of derivatives	186			572			805			—			—			—			1,564
Interest income	(2		)	16			—			—			3,361			(3,375		)	—
Other, net	500			8			(277		)	—			506			—			737
Total revenues	287,411			50,619			657,415			5,397			3,976			(338,018		)	666,800
Product purchases	237,865			685			652,697			1,108			—			(325,418		)	566,937
Plant operating and transportation expense	20,609			100			79			2,058			(250		)	(652		)	21,944
Oil and gas exploration and production expense	—			21,595			—			—			—			(8,566		)	13,029
Earnings from equity investments	(1,780		)	—			—			—			—			—			(1,780		)
Operating profit	30,717			28,239			4,639			2,231			4,226			(3,382		)	66,670

Depreciation, depletion and amortization	7,485			7,393			35			413			2,151			—			17,477
Selling and administrative expense	4,016			2,749			1,734			485			—			(13		)	8,972
(Gain) loss from sale of assets	56			2			—			(5		)	3			—			56
Interest expense	—			24			93			(47		)	9,754			(3,375		)	6,449
Segment profit	$	19,160		$	18,071		$	2,777		$	1,385		$	(7,682	)	$	6		$	33,716

Identifiable assets
Other allocated assets	$	2,834		$	7,207		$	110,219		$	34,310		$	337,285		$	(66,891	)	$	424,964
Investment in others	3,164			—			—			3,751			264,230			(236,323		)	34,822
Capital assets	592,405			263,549			1,566			39,558			57,735			7			954,820
Total identifiable assets	$	598,403		$	270,756		$	111,785		$	77,619		$	659,250		$	(303,207	)	$	1,414,606

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Elim- inating Entries			Total

Quarter Ended September 30, 2002
Revenues from unaffiliated customers
Sale of gas	$	573		$	364		$	500,926		$	187		$	179		$	—		$	502,229
Sale of natural gas liquids	3			—			87,354			—			—			—			87,357
Equity hedges:
Residue	534			8,000			—			—			—			—			8,534
Liquids	(2,143		)	—			—			—			—			—			(2,143		)
Gathering, processing and transportation revenue	14,969			—			—			2,042			(3		)	—			17,008
Total revenues from unaffiliated customers	13,936			8,364			588,280			2,229			176			—			612,985
Inter-segment revenues	154,126			26,735			7,644			3,719			14			(192,238		)	—
Non-cash change in fair value of derivatives	470			(464		)	390			—			—			—			396
Interest income	—			8			(2		)	—			2,274			(2,280		)	—
Other, net	490			2			11			14			184			—			701
Total revenues	169,022			34,645			596,323			5,962			2,648			(194,518		)	614,082
Product purchases	126,335			746			587,106			(347		)	—			(183,929		)	529,911
Plant operating and transportation expense	18,246			40			79			2,107			683			(331		)	20,824
Oil and gas exploration and production expense	—			15,494			—			—			—			(7,941		)	7,553
Earnings from equity investments	(1,141		)	—			—			—			—			—			(1,141		)
Operating profit	25,582			18,365			9,138			4,202			1,965			(2,317		)	56,935
Depreciation, depletion and amortization	10,353			6,356			40			412			1,652			—			18,813
Selling and administrative expense	3,496			2,390			1,510			678			—			(14		)	8,060
(Gain) loss from sale of assets	720			(191		)	—			473			136			(576		)	562
Interest expense	—			—			40			(6		)	9,104			(2,280		)	6,858
Segment profit	$	11,013		$	9,810		$	7,548		$	2,645		$	(8,927	)	$	553		$	22,642

Identifiable assets
Other allocated assets	$	3,709		$	2,547		$	114,647		$	20,836		$	285,326		$	(18,799	)	$	408,266
Investment in others	1,764			—			—			3,811			235,391			(224,886		)	16,080
Capital assets	531,020			219,808			1,709			42,357			51,032			576			846,503
Total identifiable assets	$	536,493		$	222,355		$	116,356		$	67,005		$	571,749		$	(243,109	)	$	1,270,849

	Gas Gathering and Processing			Exploration and Production			Marketing		Trans- portation			Corporate			Elim- inating Entries			Total
Nine months Ended September 30, 2003
Revenues from unaffiliated customers
Sale of gas	$	2,799		$	2,830		$	1,903,240	$	653		$	—		$	—		$	1,909,522
Sale of natural gas liquids	9			—			267,114		—									267,123
Equity hedges:
Residue	(2,101		)	(16,985		)	—		—			—			—			(19,087		)
Liquids	(8,555		)	—			—		—			—			—			(8,555		)
Gathering, processing and transportation revenue	57,848			—			—		5,285			(14		)	—			63,119
Total revenues from unaffiliated customers	50,000			(14,155		)	2,170,353		5,938			(14		)	—			2,212,122
Inter-segment revenues	832,287			171,951			26,849		10,651			41			(1,041,779		)	—
Non-cash change in fair value of derivatives	(284		)	(1,262		)	2,630		—			—			—			1,084
Interest income	4			29			—		2			8,678			(8,713		)	—
Other, net	1,618			21			4		42			506			—			2,191
Total revenues	883,625			156,584			2,199,837		16,633			9,211			(1,050,492		)	2,215,397
Product purchases	737,442			1,716			2,171,367		1,709			—			(1,013,859		)	1,898,375
Plant operating and transportation expense	62,472			226			239		5,686			—			(2,145		)	66,478
Oil and gas exploration and production expense	—			64,488			—		—			—			(25,658		)	38,830
Earnings from equity investments	(5,209		)	—			—		—			—			—			(5,209		)
Operating profit	88,920			90,154			28,231		9,238			9,211			(8,830		)	216,923

Depreciation, depletion and amortization	22,603			23,421			106		1,275			5,900			—			53,305
Selling and administrative expense	13,060			8,936			5,650		1,882			—			(41		)	29,487
(Gain) loss from sale of assets	210			2			—		(123		)	53			—			142
Interest expense	—			24			134		(103		)	28,350			(8,713		)	19,692
Segment profit	$	53,047		$	57,770		$	22,341	$	6,307		$	(25,092	)	$	(76	)	$	114,297

Identifiable assets
Other allocated assets	$	2,834		$	7,207		$	110,219	$	34,310		$	337,285		$	(66,891	)	$	424,964
Investment in others	3,164			—			—		3,751			264,230			(236,323		)	34,822
Capital assets	592,405			263,549			1,566		39,558			57,735			7			954,820
Total identifiable assets	$	598,403		$	270,756		$	111,785	$	77,619		$	659,250		$	(303,207	)	$	1,414,606

	Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Elim- inating Entries			Total
Nine months Ended September 30, 2002
Revenues from unaffiliated customers
Sale of gas	$	1,429		$	989		$	1,538,668		$	967		$	—		$	—		$	1,542,053
Sale of natural gas liquids	9			—			236,010			—			—			—			236,019
Equity hedges:
Residue	2,882			21,616			—			—			—			—			24,498
Liquids	(6,131		)	—			—			—			—			—			(6,131		)
Gathering, processing and transportation revenue	41,073			—			—			6,346			47			—			47,466
Total revenues from unaffiliated customers	39,262			22,605			1,774,678			7,313			47			—			1,843,905
Inter-segment revenues	438,065			72,305			17,070			11,574			41			(539,055		)	—
Non-cash change in fair value of derivatives	406			431			(3,570		)	—			—			—			(2,733		)
Interest income	—			32			10			—			6,064			(6,106		)	—
Other, net	2,780			4			11			28			131			—			2,954
Total revenues	480,513			95,377			1,788,199			18,915			6,283			(545,161		)	1,844,126
Product purchases	360,452			1,946			1,757,264			932			—			(517,788		)	1,602,806
Plant operating and transportation expense	53,043			129			211			6,277			776			(951		)	59,485
Oil and gas exploration and production expense	—			44,395			—			—			—			(20,311		)	24,084
Earnings from equity investments	(2,793		)	—			—			—			—			—			(2,793		)
Operating profit	69,811			48,907			30,724			11,706			5,507			(6,111		)	160,544

Depreciation, depletion and amortization	31,303			16,470			120			1,272			4,837			—			54,002
Selling and administrative expense	12,603			7,995			5,714			2,368			—			(41		)	28,639
(Gain) loss from sale of assets	720			(250		)	—			479			271			(576		)	644
Interest expense	—			—			92			(6		)	26,308			(6,106		)	20,288
Segment profit	$	25,185		$	24,692		$	24,798		$	7,593		$	(25,909	)	$	612		$	56,971

Identifiable assets
Other allocated assets	$	3,709		$	2,547		$	114,647		$	20,836		$	285,326		$	(18,799	)	$	408,266
Investment in others	1,764			—			—			3,811			235,391			(224,886		)	16,080
Capital assets	531,020			219,808			1,709			42,357			51,032			576			846,503
Total identifiable assets	$	536,493		$	222,355		$	116,356		$	67,005		$	571,749		$	(243,109	)	$	1,270,849

GUARANTOR AND NON-GUARANTOR SUBSIDIARIES

Our payment obligations under the revolving credit facility, the master shelf agreement and the senior subordinated notes, or collectively the financing facilities, are fully and unconditionally guaranteed by our significant subsidiaries to the extent allowed by applicable law. These guarantees are joint and several and, in the case of the senior subordinated notes, are subordinated in right of payment to senior debt of the guarantors.

During the three and nine month periods ended September 30, 2003 and 2002, the guarantors of our payment obligations under the financing facilities were Lance Oil & Gas Company, Inc., Western Gas Resources-Texas, Inc., Mountain Gas Resources, Inc., MIGC, Inc., MGTC, Inc. and Western Gas Wyoming, L.L.C., or collectively, the guarantor subsidiaries.

Our subsidiaries that did not guarantee our payment obligations under the financing facilities during the three and nine month periods ended September 30, 2003 and 2002 included Western Power Services, Inc., Western Gas Resources-Westana, Inc. and WGR Canada, Inc., or collectively, the non-guarantor subsidiaries.

Presented below is condensed consolidating financial information for Western Gas Resources, Inc., or the Parent Company, the guarantor subsidiaries and the non-guarantor subsidiaries. Balance sheet data are presented as of September 30, 2003 and 2002. The Statement of Operations and Statement of Cash Flows data are presented for the three and nine-month periods ended September 30, 2003 and 2002.

For purposes of the following tables, the Parent Company’s investments in its subsidiaries are accounted for using the equity method of accounting. Net income of guarantor and non-guarantor subsidiaries is, therefore, reflected in the Parent Company column under Earnings from equity investments. Selling and administrative expense and Provision for income

taxes are primarily reflected in the Parent Company column. The Consolidating Entries eliminate the investments in the subsidiaries and other inter-company transactions for consolidated reporting purposes.

Supplemental Condensed Consolidating Balance Sheet
As of September 30, 2003

	Parent Company		Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Consolidating Entries			Total
ASSETS
Current assets:
Cash and cash equivalents	$	51,993	$	5,330		$	567	$	—		$	57,890
Trade accounts receivable, net	255,869		18,073			8,624		(67,235		)	215,331
Inventory	48,244		43			23,617		—			71,904
Assets held for sale	445		—			—		—			445
Assets from price risk management activities	22,312		—			—		—			22,312
Other	14,909		(106		)	1,616		—			16,419
Total current assets	393,772		23,340			34,424		(67,235		)	384,301
Total property and equipment, net	398,657		480,838			74,701		624			954,820

Other assets:
Gas purchase contracts, net	7,470		22,178			—		—			29,648
Assets from price risk management activities	2,199		—			—		—			2,199
Other assets	71,883		1,261			93		(64,421		)	8,816
Investments in subsidiaries	558,703		31,658			3,164		(558,703		)	34,822
Total other assets	640,255		55,097			3,257		(623,124		)	75,485

Total assets	$	1,432,684	$	559,275		$	112,382	$	(689,735	)	$	1,414,606

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	347,547	$	30,435		$	21,849	$	(136,469	)	$	263,362
Accrued expenses	31,160		24,385			1,381		—			56,926
Liabilities from price risk management activities	15,979		—			—		—			15,979
Dividends payable	3,472		—			—		—			3,472
Total current liabilities	398,158		54,820			23,230		(136,469		)	339,739

Long-term debt	341,333		44,967			19,454		(64,421		)	341,333
Other long-term liabilities	11,170		9,495			763		—			21,428
Liabilities from price risk management activities	1,247		—			—		—			1,247
Deferred income taxes payable	136,439		29,805			5,989		(5,711		)	166,522

Total liabilities	888,347		139,087			49,436		(206,601		)	870,269
Total stockholders’ equity	544,337		420,188			62,946		(483,134		)	544,337

Total liabilities and stockholders’ equity	$	1,432,684	$	559,275		$	112,382	$	(689,735	)	$	1,414,606

Supplemental Condensed Consolidating Statement of Operations
For the Quarter ended September 30, 2003

	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Entries			Total
Total revenues	$	872,005		$	91,186		$	41,626		$	(338,017	)	$	666,800
Costs and expenses:
Product purchases	832,090			21,100			39,010			(325,263		)	566,937
Plant operating expense	15,340			6,715			697			(808		)	21,944
Oil and gas exploration and production costs	546			21,004			45			(8,566		)	13,029
Depreciation, depletion and amortization	6,645			10,045			10,045			—			17,477
Selling and administrative expense	8,556			379			50			(13		)	8,972
(Gain) loss on sale of assets	59			(3		)	—			—			56
Earnings from equity investments	(31,365		)	(1,164		)	(616		)	31,365			(1,780		)
Interest expense	6,425			3,307			91			(3,374		)	6,449
Total costs and expenses	838,296			61,383			40,064			(306,659		)	633,084
Income before income taxes	33,709			29,803			1,562			(31,358		)	33,716
Total provision for income taxes	12,827			—			—			—			12,827
Net income	$	20,882		$	29,803		$	1,562		$	(31,358	)	$	20,889

Supplemental Condensed Consolidating Statement of Operations

For the Nine Months ended September 30, 2003

	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Entries			Total
Total revenues	$	2,851,316		$	275,537		$	139,036		$	(1,050,492	)	$	2,215,397
Costs and expenses:
Product purchases	2,724,468			53,607			133,537			(1,013,237		)	1,898,375
Plant operating expense	45,679			21,340			2,225			(2,766		)	66,478
Oil and gas exploration and production costs	1,069			63,374			45			(25,658		)	38,830
Depreciation, depletion and amortization	19,632			31,797			1,876			—			53,305
Selling and administrative expense	28,187			1,167			174			(41		)	29,487
(Gain) loss on sale of assets	21			121			—			—			142
Earnings from equity investments	(96,555		)	(3,431		)	(1,778		)	96,555			(5,209		)
Interest expense	19,663			8,611			131			(8,713		)	19,692
Total costs and expenses	2,742,164			176,586			136,210			(953,860		)	2,101,100
Income before income taxes	109,152			98,951			2826			(96,632		)	114,297
Total provision for income taxes	42,409			—			—			—			42,409
Net income before cumulative effect of change in accounting principle	66,743			98,951			2,826			(96,632		)	71,888
Cumulative effect of change in accounting principle	(1,502		)	(4,969		)	(253		)	—			(6,724		)
Net income	$	65,241		$	93,982		$	2,573		$	(96,632	)	$	65,164

Supplemental Condensed Consolidating Statement of Cash Flows
For the Nine Months ended September 30, 2003

	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Entries			Total
Net cash provided by operating activities	$	145,844		$	58,442		$	5,463		$	724		$	210,473
Cash flows from investing activities:
Purchases of property and equipment, including acquisitions	(63,808		)	(44,164		)	(18,227		)	715			(125,484		)
Proceeds from the disposition of property and equipment	3,896			1,374			—			(1,439		)	3,831
Other net cash used in investing activities	(13,285		)	(10,450		)	13,285			—			(10,450		)
Net cash used in investing activities	(73,197		)	(53,240		)	(4,942		)	(724		)	(132,103		)
Cash flows from financing activities:
Payments on revolving credit facility	(780,800		)	—			—			—			(780,800		)
Borrowings under revolving credit facility	747,200			—			—			—			747,200
Dividends paid	(10,403		)	—			—			—			(10,403		)
Other net cash used in financing activities	16,211			—			—			—			16,211
Net cash used in financing activities	(27,792		)	—			—			—			(27,792		)
Net decrease in cash and cash equivalents	44,855			5,202			521			—			50,578
Cash and cash equivalents at beginning of year	7,138			128			46			—			7,312
Cash and cash equivalents at end of year	$	51,993		$	5,330		$	567		$	—		$	57,890

Supplemental Condensed Consolidating Balance Sheet
As of December 31, 2002

	Parent Company		Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Consolidating Entries			TOTAL
ASSETS
Current assets:
Cash and cash equivalents	$	7,138	$	128		$	46	$	—		$	7,312
Trade accounts receivable, net	256,508		14,013			10,382		(27,316		)	253,587
Inventory	36,406		—			7,076		—			43,482
Assets held for sale	3,250		—			—		—			3,250
Assets from price risk management activities	34,873		—			—		—			34,873
Other	29,847		(2,675		)	572		—			27,744
Total current assets	368,022		11,466			18,076		(27,316		)	370,248

Total property and equipment, net	348,937		466,538			51,271		(100		)	866,646
Other assets:
Gas purchase contracts, net	7,722		23,202			—		—			30,924
Assets from price risk management activities	406		—			—		—			406
Other assets	58,864		486			5		(51,051		)	8,304
Investments in subsidiaries	450,397		22,777			2,839		(450,397		)	25,616
Total other assets	517,389		46,465			2,844		(501,448		)	65,250

Total assets	$	1,234,348	$	524,469		$	72,191	$	(528,864	)	$	1,302,144

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	211,220	$	45,003		$	15,078	$	(28,314	)	$	242,987
Accrued expenses	40,091		9,472			1,946		—			51,509
Liabilities from price risk management activities	34,811		—			—		—			34,811
Dividends payable	3,464		—			—		—			3,464
Total current liabilities	289,586		54,475			17,024		(28,314		)	332,771

Long-term debt	359,933		—			—		—			359,933
Other long-term liabilities	1,713		44,967			6,084		(51,051		)	1,713
Liabilities from price risk management activities	406		—			—		—			406
Deferred income taxes payable	99,642		29,287			—		(4,676		)	124,253

Total liabilities	751,280		128,729			23,108		(84,041		)	819,076

Total stockholders’ equity	483,068		395,740			49,083		(444,823		)	483,068

Total liabilities and stockholders’ equity	$	1,234,348	$	524,469		$	72,191	$	(528,864	)	$	1,302,144

Supplemental Condensed Consolidating Statement of Operations
For the Quarter ended September 30, 2002

	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Entries			Total
Total revenues	$		730,016	$	51,092		$	27,487		$	(194,513	)	$	614,082
Costs and expenses:
Product purchases	680,940			8,565			24,310			(183,904		)	529,911
Plant operating expense	14,187			6,298			714			(375		)	20,824
Oil and gas exploration and production costs	160			15,333			—			(7,940		)	7,553
Depreciation, depletion and amortization	7,620			10,427			766			—			18,813
Selling and administrative expense	7,274			736			66			(15		)	8,061
(Gain) loss on sale of assets	583			283			272			(576		)	562
Earnings from equity investments	—			(548		)	(593		)	—			(1,141		)
Interest expense	6,858			2,241			40			(2,281		)	6,858
Total costs and expenses	717,622			43,335			25,575			(195,091		)	591,441
Income before income taxes	12,394			7,757			1,912			578			22,641
Total provision for income taxes	9,254			—			—			—			9,254
Net income	$	3,140		$	7,757		$	1,912		$	578		$	13,387

Supplemental Condensed Consolidating Statement of Operations

For the Nine Months ended September 30, 2002

	Parent Company		Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Entries			Total
Total revenues	$	2,151,234	$	144,011		$	94,030		$	(545,149	)	$	1,844,126
Costs and expenses:
Product purchases	2,007,653		28,112			84,423			(517,382		)	1,602,806
Plant operating expense	40,486		18,231			2,124			(1,356		)	59,485
Oil and gas exploration and production costs	1,007		43,387			—			(20,310		)	24,084
Depreciation, depletion and amortization	23,322		28,552			2,128			—			54,002
Selling and administrative expense	26,602		1,829			250			(42		)	28,639
(Gain) loss on sale of assets	718		230			272			(576		)	644
Earnings from equity investments	—		(1,208		)	(1,585		)	—			(2,793		)
Interest expense	20,288		6,015			92			(6,107		)	20,288
Total costs and expenses	2,120,076		125,148			87,704			(545,773		)	1,787,155
Income before income taxes	31,158		18,863			6,326			624			56,971
Total provision for income taxes	21,334		—			484			—			21,818
Net income	$	9,824	$	18,863		$	5,842		$	624		$	35,153

Supplemental Condensed Consolidating Statement of Cash Flows
For the Nine Months ended September 30, 2002

	Parent Company			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Entries			Total
Net cash provided by operating activities	$	(9,331	)	$	72,762		$	9,434		$	—		$	72,866
Cash flows from investing activities:
Purchases of property and equipment, including acquisitions	(17,923		)	(65,641		)	(6,238		)	2,018			(87,784		)
Proceeds from the disposition of property and equipment	32,851			2,496			75			(2,018		)	33,404
Other net cash used in investing activities	5,250			(7,622		)	(5,265		)	—			(7,637		)
Net cash used in investing activities	20,178			(70,767		)	(11,428		)	—			(62,017		)
Cash flows from financing activities:
Payments on revolving credit facility	(732,780		)	—			—			—			(732,780		)
Borrowings under revolving credit facility	723,280			—			—			—			723,280
Dividends paid	(11,326		)	—			—			—			(11,326		)
Other net cash used in financing activities	6,311			—			—			—			6,311
Net cash used in financing activities	(14,515		)	—			—			—			(14,515		)
Net decrease in cash and cash equivalents	(3,668		)	1,995			(1,994		)	—			(3,667		)
Cash and cash equivalents at beginning of year	9,359			(1,833		)	2,506			—			10,032
Cash and cash equivalents at end of year	$	5,691		$	162		$	512		$	—		$	6,365

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

SFAS No. 141 and SFAS No. 142. Statement of Financial Accounting Standards No. 141, Business Combinations (FAS 141) and Statement of Financial Accounting Standards, No. 142, Goodwill and Intangible Assets (FAS 142) were issued by the Financial Accounting Standards Board (FASB) in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. FAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, FAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. FAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under FAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. One interpretation being considered relative to these standards is that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and gas properties, as intangible assets on our balance sheets. In addition, the disclosures required by FAS 141 and 142 relative to intangibles would be included in the notes to financial statements. Historically, we have included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the oil and gas properties, even after FAS 141 and 142 became effective.

This interpretation of FAS 141 and 142 described above would only affect our balance sheet classification of oil and gas leaseholds. Our results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with accounting rules for oil and gas companies provided in Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies (FAS 19).

At September 30, 2003, we had undeveloped leaseholds of approximately $53.7 million that would be classified on our balance sheet as “intangible undeveloped leasehold” and developed leaseholds of an estimated $31.4 that would be classified as “intangible developed leaseholds” if we applied the interpretation currently being considered.

We will continue to classify our oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.

FIN 46. In January 2003, the FASB issued Interpretation No. 46, or “FIN 46”, “Consolidation of Variable Interest Entities.” FIN 46 provides guidance on how to identify a variable interest entity, or VIE, and determine when the assets, liabilities, and results of operations of a VIE need to be included in a company’s consolidated financial statements. FIN 46 also requires additional disclosures by primary beneficiaries and other significant variable interest holders in a VIE. The provisions of FIN 46 are effective immediately for all VIEs created after January 31, 2003. For VIEs created before February 1, 2003, the provisions of FIN 46, as amended, must be adopted at the beginning of the fourth quarter of 2003. We are continuing to evaluate the impact of FIN 46 and will adopt this pronouncement as required.

SFAS No. 149. In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 is effective for contracts entered into or modified after September 30, 2003. This statement amends and clarifies financial accounting reporting for derivative instruments and for hedging activities under SFAS Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities.” We adopted SFAS No. 149 on October 1, 2003 and the adoption of this pronouncement did not impact our earnings or financial position.

SFAS No. 150. In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS No. 150 is effective for instruments entered into or modified after May 31, 2003 and is otherwise effective at the beginning of the first interim period beginning after June 15, 2003. This statement establishes standards for classifying and measuring financial instruments of both liabilities and equity. We adopted SFAS No. 150 on June 1, 2003. The adoption of this pronouncement did not have an impact on our financial statements as we do not have any instruments that were the subject of this pronouncement.

EITF Issue No. 03-11. At the July 31, 2003 meeting of the EITF, a consensus was reached on Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in EITF Issue No. 02-3”. This statement, among other issues, addresses the financial presentation of derivative contracts not held for trading purposes and whether they should be reported gross or net of associated costs. This statement does not have an impact on our financial statements as we record revenue on our physical gas and NGL marketing activities on a gross basis versus sales net of purchases basis because we obtain title to all the gas and NGLs that we buy including third-party purchases, bear the risk of loss and credit exposure on these transactions, and it is our intention upon entering these contracts to take physical delivery of the product. Our presentation is in compliance with EITF Issue No. 03-11.

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, 2003 and 2002. Some prior year amounts have been reclassified as appropriate to conform to the presentation used in 2003. You should also refer to our interim consolidated financial statements and notes included in “Part 1 – Financial Information – Item 1. Financial Statements” of this report. This section, as well as other sections in this Quarterly Report on 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, 2003 compared to the three and nine months ended September 30, 2002

(Dollars in thousands, except per share amounts and operating data).

	Three Months Ended September 30,					Percent		Nine months Ended September 30,						Percent
	2003			2002		Change		2003			2002			Change

Financial results:
Revenues	$	666,800		$	614,082	9		$	2,215,397		$	1,844,126		20
Gross profit	49,137			37,560		31		163,476			105,898			54
Net income	20,889			13,387		56		65,164			35,153			85
Earnings per share of common stock	.57			.34		68		1.80			.87			107
Earnings per share of common stock - diluted	.56			.34		65		1.75			.86			103
Net cash provided by operating activities	$	68,823		$	4,627	1387		$	210,473		$	72,865		188
Net cash provided by (used in) investing activities	$	(56,616	)	$	1,956	(2994	)	$	(132,103	)	$	(62,017	)	(113	)
Net cash provided by (used in) financing activities	$	4,952		$	27,946	118		$	(27,792	)	$	(14,515	)	(91	)

Operating data:
Average gas sales (MMcf/D)	1,285			2,001		(36	)	1,374			2,098			(35	)
Average NGL sales (MGal/D)	1,639			2,219		(26	)	1,640			2,095			(22	)
Average gas prices ($/Mcf)	$	4.70		$	2.77	70		$	5.03		$	2.73		84
Average NGL prices ($/Gal)	$	.57		$	.42	36		$	.58		$	.40		45

Net income increased $7.5 million and $30.0 million for the three and nine months ended September 30, 2003 compared to the same periods in 2002. The increases in net income were primarily attributable to a significant increase in gas and NGL prices in 2003 compared to the same periods last year. This increase in prices was supplemented by increased equity production from the Powder River Basin coal bed methane project and the Green River Basin. Partially offsetting the increases to net income in the nine months ended September 30, 2003 was a pre-tax loss of $1.2 million from the discontinuance of hedge treatment on some financial instruments and a $6.7 million after-tax loss from the Cumulative effect of a change in accounting principle from the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations” on January 1, 2003.

Revenues from the sale of gas increased $45.8 million to $556.6 million for the three months ended September 30, 2003 compared to the same period in 2002. This increase was primarily due to an increase in product prices, which more than offset a decrease in sales volume in the three months ended September 30, 2003. Average gas prices realized by us increased $1.93 per Mcf to $4.70 per Mcf for the quarter ended September 30, 2003 compared to the same period in 2002. Included in the calculation of the realized gas price were approximately $6.0 million of losses recognized in the three months ended September 30, 2003 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately half of our equity gas for the remainder of 2003 and in 2004. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average gas sales volumes decreased 716 MMcf per day to 1,285 MMcf per day for the

quarter ended September 30, 2003 compared to the same period in 2002. This decrease was due to a reduction in third party sales volume resulting from the increase in product prices and an intentional effort to reduce related credit exposure.

Revenues from the sale of gas increased $323.8 million to $1,890.4 million for the nine months ended September 30, 2003 compared to the same period in 2002. This increase was primarily due to an increase in product prices, which more than offset a decrease in sales volume in the nine months ended September 30, 2003. Average gas prices realized by us increased $2.30 per Mcf to $5.03 per Mcf for the nine months ended September 30, 2003 compared to the same period in 2002. Included in the calculation of the realized gas price were approximately $19.1 million of losses recognized in the nine months ended September 30, 2003 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately half of our equity gas for the remainder of 2003 and in 2004. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average gas sales volumes decreased 724 MMcf per day to 1,374 MMcf per day for the nine months ended September 30, 2003 compared to the same period in 2002. This decrease was due to a reduction in third party sales volume resulting from the increase in product prices and an intentional effort to reduce related credit exposure.

Revenues from the sale of NGLs remained constant at $86.0 million for the three months ended September 30, 2003 compared to the same period in 2002. This is primarily due to a significant increase in product prices that was substantially offset by a reduction in third party sales volumes and as a result of reduced NGL production at our Granger facility as it was more economic to sell ethane as residue gas. Average NGL prices realized by us increased $0.15 per gallon to $0.57 per gallon for the three months ended September 30, 2003 compared to the same period in 2002. Included in the calculation of the realized NGL price were approximately $1.9 million of losses recognized in the three months ended September 30, 2003 related to futures positions on equity NGL volumes. We have entered into additional futures positions for the majority of our equity NGL production for the remainder of 2003 and in 2004. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average NGL sales volumes decreased 579 MGal per day to 1,640 MGal per day for the three months ended September 30, 2003 compared to the same period in 2002.

Revenues from the sale of NGLs increased approximately $28.7 million to $258.6 million for the nine months ended September 30, 2003 compared to the same period in 2002. This increase is primarily due to a significant increase in product prices, which was partially offset by a reduction in third-party sales volumes. Average NGL prices realized by us increased $0.18 per gallon to $0.58 per gallon for the nine months ended September 30, 2003 compared to the same period in 2002. Included in the calculation of the realized NGL price were approximately $8.6 million of losses recognized in the nine months ended September 30, 2003 related to futures positions on equity NGL volumes. We have entered into additional futures positions for the majority of our equity NGL production for the remainder of 2003 and in 2004. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average NGL sales volumes decreased 455 MGal per day to 1,640 MGal per day for the nine months ended September 30, 2003 compared to the same period in 2002.

Product purchases increased by $37.0 million and $295.6 million for the quarter and nine months ended September 30, 2003 compared to the same periods in 2002 as a result of the significant increase in commodity prices. Overall, combined product purchases as a percentage of sales of all products remained constant at 89% in both the quarter and nine months ended September 30, 2003.

Plant and transportation operating expense increased by $1.1 million and $7.0 million, respectively, for the three and nine months ended September 30, 2003 compared to the same periods in 2002. The increases in both the quarter and nine months ended September 30, 2003 were primarily due to increased throughput at our facilities, the acquisition of several gathering systems in the first quarter of 2003 and additional leased compression in the Powder River Basin coal bed development. Also contributing to this increase were the fees paid to other companies, primarily Rendezvous Gas Services, L.L.C., or Rendezvous, for gas gathering services. Rendezvous is a 50%-owned entity that delivers gas to our Granger Complex. Rendezvous is accounted for under the equity method and our share of its gathering revenues is reflected in Earnings from equity investments.

Oil and gas exploration and production expenses increased by $5.5 million and $14.7 million, respectively, for the three and nine months ended September 30, 2003 compared to the same periods in 2002. In our operating areas, the significant increase in residue gas prices in 2003 resulted in substantially higher severance tax expenses. Overall, lease operating expense for the nine months ended September 30, 2003 remained constant compared to the same period in 2002 and averaged $0.43 per Mcfe.

Depreciation, depletion and amortization decreased by $1.3 million and $697,000, respectively, for the three and nine months ended September 30, 2003 as compared to the same periods in 2002. These decreases were the result of revisions to

the operating lives and salvage values of our operating assets, which were partially offset by additional depreciation in 2003 from new projects in 2003. The revisions to the operating lives and salvage values were the result of analysis performed in connection with the adoption of SFAS No. 143 on January 1, 2003 and were treated as a revision of an estimate and are accounted for on a prospective basis.

Selling and administrative expenses increased by approximately $900,000 in both the three and nine months ended September 30, 2003 as compared to the same periods in 2002. These increases were due to higher compensation expenses for the three-month period and higher compensation and professional fees partially offset by a reduction in the accruals for doubtful accounts in the nine-month period of 2003.

In the first nine months of 2003, in order to properly align our hedged volumes of natural gas to our forecasted equity production for 2003, we discontinued hedge treatment on financial instruments for 10 MMcf per day of natural gas and 50,000 Barrels per month of ethane. As a result, a pre-tax loss of $2.8 million was reclassified into earnings in the nine months ended September 30, 2003 from Accumulated other comprehensive income.

Cash Flow Information

Cash flows from operating activities increased by $137.6 million in the first nine months of 2003 compared to the same period in 2002. This increase was primarily due to an increase in net income in the first nine months of 2003 compared to the prior year and the timing of cash receipts and payables.

Cash flows used in investing activities increased by $70.1 million in the first nine months of 2003 compared to the same period in 2002. This increase was primarily due to a higher level of capital expenditures.

Cash flows used in financing activities increased by $13.3 million in the first nine months of 2003 compared to the same period in 2002. This increase was due to increased cash flows from operating activities, which was used to reduce our long-term debt.

Other Information

Acquisition and Disposition of Gathering Systems. Effective February 1, 2003, we acquired 18 gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million. Several of the systems located in the Powder River do not integrate directly into our existing systems, and accordingly we are negotiating for the sale of these systems. We completed the sale of several of these systems during the third quarter of 2003, and the remaining systems are classified as Assets held for sale on the Consolidated Balance Sheet at September 30, 2003. During the three and nine months ended September 30, 2003, the income, if any, generated by the assets included in Assets held for sale are immaterial for separate presentation as a discontinued operation.

Acquisition of Sand Wash Properties. In August 2003, through the acquisition of the stock of a private corporation for $12.9 million, we acquired additional reserves, production and acreage in this area. The assets of this entity consist primarily of non-operating interests in various Sand Wash properties operated by us. This acquisition included 10.6 Billion Cubic Feet equivalent, or Bcfe, of proved reserves, 2.1 MMcfed of production and approximately 11,000 net acres under lease.

Segment Information

Gas Gathering, Processing and Treating. The Gas gathering, Processing and Treating segment realized segment-operating profit of $30.7 million for the third quarter of 2003 and $88.9 million in the nine months ended September 30, 2003. This compares to $25.6 million for the third quarter of 2002 and $69.8 million in the nine months ended September 30, 2002. The increase in operating profit in this segment in the 2003 periods is primarily due to higher commodity prices, increased gathering volumes and the acquisition of several gathering systems in February 2003.

Exploration and Production. The Exploration and Production segment realized segment-operating profit of $28.2 million for the third quarter of 2003 and $90.2 million in the nine months ended September 30, 2003. This compares to $18.4 million for the third quarter of 2002 and $48.9 million in the nine months ended September 30, 2002. The increase in operating profit in this segment in the 2003 periods was primarily due to substantially higher natural gas prices and production volume growth from the Powder River Basin coal bed methane area and the Pinedale Anticline field.

Marketing. The Marketing segment realized segment-operating profit of $4.6 million for the third quarter of 2003 and $28.2 million in the nine months ended September 30, 2003. This compares to $9.1 million for the third quarter of 2002 and $30.7 million in the nine months ended September 30, 2002.

Marketing margins on residue gas averaged $0.03 and $0.06 per Mcf in the third quarter and the nine months ended September 30, 2003, respectively. This represents a decrease of approximately $0.01 per Mcf as compared to the margin realized during the third quarter of 2002 and an increase of approximately $0.01 per Mcf as compared to the margin realized during the nine months ended September 30, 2002. The changes in the marketing margins are primarily due to transactions associated with our firm transportation capacity from the Rocky Mountain region to the Mid-Continent. Our firm transportation allows us to purchase gas in the Rocky Mountain region for resale in the higher priced Mid-Continent markets. In the second quarter of 2003, additional transportation capacity out of the Rocky Mountain region became operational, which reduced the price difference between the two regions. We expect that the reduced margins experienced in the third quarter of 2003 will continue in future periods. There is no assurance that the margins we realized on the sale of our residue gas in the third quarter will continue in the future, or that we will continue to originate the same amount of transactions in future quarters.

Transportation. The Transportation segment realized segment-operating profit of $2.2 million for the third quarter of 2003 and $9.2 million in the nine months ended September 30, 2003. This compares to $4.2 million for the third quarter of 2002 and $11.7 million in the nine months ended September 30, 2002. The transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin.

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 additional or 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 results, efficient operation of our facilities and our ability to obtain financing at favorable terms.

Although some of our plants have experienced natural declines in dedicated reserves, overall we have been successful in connecting additional reserves to more than offset these declines and in fact have increased throughput volumes at our plant facilities. However, the overall level of drilling associated with our plant facilities 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. 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, results of operations and cash flows.

During the past several years, we have been successful in developing additional reserves of natural gas and increasing our equity natural gas production. However, the overall level of drilling and production associated with our producing properties will depend upon, among other factors, the price for gas, availability of transportation capacity to market centers, the energy and environmental policy and regulation by governmental agencies, and the issuance of drilling and water disposal permits, none of which is entirely within our control. Any reduction in the levels of exploration, development and production by us or a significant reduction in natural gas prices could have a material adverse effect on our financial condition, results of operations and cash flows.

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 and complete our current capital expenditure program. Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital. Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to

borrow funds from third-parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or a combination of alternatives. While we believe that we would be able to secure additional financing, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing. In October 2003, we utilized a portion of the revolving credit facility to fund a $8.3 million scheduled payment on the master shelf agreement. We believe that cash provided by operating activities and amounts available under the revolving credit facility will be sufficient to meet remaining scheduled principal repayments during 2003 of $25.0 million under the master shelf agreement, scheduled principal repayments during 2004 on this facility of $35.0 million, our preferred stock dividend requirements during the remainder of 2003 of approximately $1.7 million, and our projected preferred stock dividend requirements during 2004.

We have effective shelf registration statements filed with the 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. These shelf registrations allow us to access the debt and equity markets without the requirement of further SEC review.

Preferred Stock Redemption. On November 7, 2003, we issued a notice of redemption for approximately 700,000 shares of our $2.625 cumulative convertible preferred stock at its liquidation preference plus 0.525% premium. The holders of this preferred stock have the right to convert in whole or in part into shares of our common stock in lieu of receiving the redemption price in cash. The holders may make their election at any time prior to the redemption date. The redemption date is scheduled for December 11, 2003 and to the extent required, will be funded with amounts available under our revolving credit facility. If all holders elect to receive shares of our common stock, we will issue an additional 882,000 shares of common stock, and if all holders elect to receive cash, the redemption will total $35.6 million including accrued and unpaid dividends. Also if all holders elect to receive cash, the pro rata capitalized offering costs associated with the redeemed preferred stock of $1.3 million will be reflected as a special dividend to preferred shareholders in 2003 and will reduce earnings per share of common stock by approximately $0.04 per common share in the fourth quarter of 2003.

Our sources and uses of funds for the nine months ended September 30, 2003 are summarized as follows (dollars in thousands):

Sources of funds:
Borrowings under the revolving credit facility	$	747,200
Borrowings under the master shelf agreement	25,000
Proceeds from the dispositions of property and equipment	3,831
Net cash provided by operating activities	210,473
Proceeds from exercise of common stock options	3,062
Total sources of funds	$	989,566

Uses of funds:
Payments related to long-term debt (including debt issue costs)	$	792,651
Capital expenditures	125,484
Contributions to equity investees	10,450
Preferred dividends paid	5,434
Common dividends paid	4,969
Total uses of funds	$	938,988

Capital Investment Program. We currently anticipate capital expenditures in 2003 of approximately $223.0 million. Overall, capital expenditures in the Powder River Basin coal bed methane development and in southwest Wyoming operations represent 26% and 54%, respectively, of the total 2003 budget. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2003 will not change. This budget may be increased to provide for acquisitions if approved by our board of directors.

The 2003 capital budget and our capital expenditures during the nine months ended September 30, 2003, which totaled approximately $136.0 million, are presented in the following table (dollars in thousands).

Type of Capital Expenditure	Amount Expended Through September 30, 2003			2003 Capital Budget
Gathering, processing, treating and pipeline assets	$	40.3	*	$	83.9	*
Exploration and production and lease acquisition activities	37.4			77.0
Acquisition of gathering systems, which closed in January 2003	37.1			37.1
Acquisition of all the capital stock of a private corporation which closed in August 2003	12.9			12.9
Information technology and other items	4.2			4.3
Capitalized interest and overhead	4.1			7.8
Total	$	136.0		$	223.0

* Includes $6.9 million and $13.3 million, respectively for maintaining existing facilities.

Contractual Commitments and Obligations

Contractual Cash Obligations. A summary of our contractual cash obligations as of September 30, 2003 is as follows (dollars in thousands):

			Payments by Period
Type of Obligation	Total Obligation		Due in 2003		Due in 2004 – 2005		Due in 2006 – 2007		Due Thereafter
Guarantee of Fort Union Project Financing	$	5,738	$	192	$	1,669	$	1,931	$	1,946
Operating Leases	76,992		5,754		24,256		23,237		23,745
Firm Transportation Capacity and Gathering Agreements	216,141		7,807		56,201		54,339		97,794
Firm Storage Capacity Agreements	13,018		1,720		6,698		2,677		1,923
Long-term Debt	341,333		33,333		45,000		83,000		180,000
Total Contractual Cash Obligations	$	653,222	$	48,806	$	133,824	$	165,184	$	305,408

Guarantee of Fort Union Project Financing. We own a 13% equity interest in the Fort Union Gas Gathering, L.L.C., or Fort Union, and are the construction manager and field operator. Fort Union gathers and treats natural gas in the Powder River Basin in northeast Wyoming. Initial construction and any expansions of the gathering header and treating system have been project financed by Fort Union. This debt is amortizing on an annual basis and is scheduled to be fully paid in 2009. All participants in Fort Union have guaranteed Fort Union’s payment of the project financing on a proportional basis, resulting in our guarantee of $5.7 million of the debt of Fort Union at September 30, 2003. Our requirement to fund under this guarantee would be reduced by the value of assets held by Fort Union. This guarantee is not reflected on our Consolidated Balance Sheet.

Operating Leases. In the ordinary course of our business operations, we enter into operating leases for office space, office equipment, communication equipment and transportation equipment. In addition, 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. These leases have terms ranging from one month to ten years with return or fair market purchase options available at various times during the lease. If we were to exercise the purchase options on all the leased equipment, these purchase options would require the capital expenditure of approximately $36.9 million between 2007 and 2012.

Firm Transportation Capacity and Gathering Agreements. 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, 2003, we had contracts for approximately 625 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 171 MMcf per day of gas from the Rocky Mountain area to the Mid-Continent. This utilizes a total of approximately 376 MMcf per day of firm capacity on three separate pipelines. The total rate under these long-term contracts to transport this gas to the Mid-Continent approximates $0.35 per Mcf. Our remaining firm capacity consists of 108 MMcf per day to markets within the Rocky Mountains and 140 MMcf per day contracted in various other markets throughout the country. In addition, we hold 83 MMcf per day of firm gathering capacity on the Fort Union gathering line. These agreements are not reflected on our Consolidated Balance Sheet.

A portion of this firm transportation capacity was contracted for use in our Marketing operations. For example, our Marketing segment purchases gas in the Rocky Mountain region, transports this gas utilizing its 56 MMcf per day of our firm transportation capacity to the Mid-Continent, and resells the gas to various markets. During the nine months ended September 30, 2003, these types of transactions have been profitable as the price difference, or basis, between the Rocky Mountain and Mid-Continent regions has exceeded the cost of transportation. We expect that the fixed fees associated with our contracts for firm transportation capacity during the fourth quarter of 2003 will average approximately $0.13 per Mcf per day. The associated contract periods range from one month 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.

Firm Storage Capacity Agreements. 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, 2003, we had contracts in place for approximately 13.3 Bcf of storage capacity at various third-party facilities. Of the total storage capacity under contract, approximately 6.2 Bcf is under contract to our Canadian subsidiary, WGR – Canada, Inc., and Western guarantees the subsidiary’s performance under these contracts. This subsidiary is wholly owned by us and fully consolidated in our financial statements.

The fees associated with these contracts during the remainder of 2003 will average $0.41 per Mcf of annual capacity. The associated contract periods at September 30, 2003 have an average term of twenty months. At September 30, 2003, we held gas in our contracted storage facilities and in imbalances of approximately 14.5 Bcf at an average cost of $4.56 per Mcf compared to 19.7 Bcf at an average cost of $2.34 per Mcf at September 30, 2002. These positions are for storage withdrawals within the next thirteen months. At the time that we place product into storage, we contract for the sale of that product, physically or financially, and do not speculate on the future value of the product. These agreements for storage capacity are not reflected on our Consolidated Balance Sheet.

From time to time, we lease NGL storage space at major trading locations to facilitate the distribution of products. At September 30, 2003, we held NGLs in storage at various third-party facilities of 2,687 MGal, consisting primarily of propane and normal butane, at an average cost of $0.26 per gallon compared to 4,005 MGal at an average cost of $0.31 per gallon at September 30, 2002. These agreements for storage capacity are not reflected on our Consolidated Balance Sheet.

Long-term Debt

Revolving Credit Facility. At September 30, 2003, $63.0 million was outstanding under our existing four-year, $300 million revolving credit facility. Loans made under this facility are secured by a pledge of the capital stock of our significant subsidiaries. These subsidiaries also guarantee the borrowings under the facility. The facility contains a provision that requires us to secure loans under the facility with 75% of our oil and gas reserves. This provision would only be triggered in the event of a reduction to a debt rating on the revolving credit facility of Ba3 or lower by Moody’s Investors Service, Inc., or Moody’s, or the reduction to a debt rating on the revolving credit facility of BB- or lower by Standard & Poor’s Rating Services, a division of The McGraw-Hill Companies, Inc., or S&P. This facility has been rated Ba1 by Moody’s and BB+ by S&P.

The borrowings under the credit facility bear interest at Eurodollar rates or a base rate, as requested by us, plus an applicable percentage based on our debt to capitalization ratio. The base rate is the agent’s published prime rate. We also pay a quarterly facility fee ranging between 0.30% and 0.50%, depending on our debt to capitalization ratio. This fee is paid on the total commitment. At September 30, 2003, the interest rate payable on borrowings under the new facility was approximately 2.87%.

Under the credit facility, we are subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55%; maintaining a senior debt to capitalization ratio of not more than 40%; and maintaining a ratio of EBITDA, as defined in the credit facility, to interest and dividends on preferred stock over the last four quarters in excess of 3.25 to 1.0, increasing to 4.25 to 1.0 by March 31, 2005.

The credit facility ranks equally with borrowings under our master shelf agreement with The Prudential Insurance Company.

Master Shelf Agreement. Amounts outstanding under the master shelf agreement with The Prudential Insurance Company of America at September 30, 2003 are as indicated in the following table (dollars in thousands):

Issue Date	Amount		Interest Rate		Final Maturity	Principal Payments Due
October 27, 1992	$	8,333	7.99	%	October 27, 2003	single payment at maturity
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	40,000		7.61	%	July 28, 2007	$ 10,000 on each of July 28, 2004 through 2007
January 17, 2003	25,000		6.36	%	January 17, 2008	single payment at maturity
	$	123,333

Our borrowings under the master shelf agreement are secured by a pledge of the capital stock of our significant subsidiaries, some of which have also provided a guaranty of payments owed by us under the facility. The master shelf requires us to secure loans under the facility with 75% of our oil and gas reserves. This provision would only be triggered in the event of a reduction to the debt rating on the revolving credit facility of Ba3 or lower by Moody’s or the reduction to the debt rating on the revolving credit facility of BB- or lower by S&P.

Under our master shelf agreement, we are subject to a number of covenants, including: maintaining 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; maintaining a total debt to capitalization ratio of not more than 55% and a senior debt to capitalization ratio of not more than 40%; maintaining a quarterly test of EBITDA to interest for the last four quarters in excess of 3.25 to 1.0, increasing to 4.25 to 1.0 by March 31, 2005; and maintaining a ratio of senior debt to EBITDA, as defined in the Master Shelf Agreement, of no greater than 4.0 to 1.0.

In October 2003, we utilized funds available under the revolving credit facility to fund a $8.3 million scheduled payment under the master shelf agreement. In December 2003, we will make another required principal repayment under the master shelf agreement totaling $25.0 million, and in 2004, we will make scheduled payments totaling $35.0 million on this facility. We intend to fund these repayments with funds available under the revolving credit facility.

Senior Subordinated Notes. In 1999, we sold $155.0 million of senior subordinated notes in a private placement with a final maturity of 2009 due in a single payment which were subsequently exchanged for registered publicly tradable notes under the same terms and conditions. The 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. The Subordinated Notes are unsecured and are guaranteed on a subordinated basis by our material subsidiaries. We incurred approximately $5.0 million in offering commissions and expenses, which were capitalized and are being amortized over the term of the notes. The senior subordinated notes are callable at our option, in whole or in part, at decreasing premiums, beginning in June 2004. Our ability to call these notes may be restricted by the covenants under our other debt facilities.

Covenant Compliance. We were in compliance with all covenants in our debt agreements at September 30, 2003.

Upstream Operations

Each of our existing upstream projects are fully integrated with our midstream operations. In other words, we provide the gathering, compression, processing, marketing or transportation services for both our own production and for third-party operators. Additionally, we are actively pursuing new exploration, development and producing property acquisition opportunities. Our principal upstream operations are summarized in the following table:

Production Area	Net Acres Under Lease At September 30, 2003	Proven Reserves at December 31, 2002*	Average Net Production for the Nine Months Ended September 30, 2003
Powder River Basin Coal Bed Methane	524,000	414 Bcfe	124 MMcfe per day
Pinedale/Jonah Basin	33,000	162 Bcfe	20 MMcfe per day
Sand Wash Basin	188,000	23 Bcfe	4 MMcfe per day
Other	275,000	—	—

* Includes the additional reserves acquired in Sand Wash in August 2003.

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, together with our co-developer, in the first nine months of 2003, we were the largest producer of natural gas. In addition, Western is the largest gatherer of natural gas and, through our MIGC pipeline, transports a significant volume of gas out of this basin.

In October 2003, we settled on-going litigation with our co-developer in this area. Under the terms of the settlement agreement, both our co-developer and we will each operate the drilling and production on approximately half of the jointly owned leasehold in the coal-bed methane development of the Powder River Basin of Wyoming. We began operating our half of the properties on November 1, 2003.

The drilling operations in the Powder River Basin through September 30, 2003 have primarily focused on developing reserves in the Wyodak coal, which is located on the east side of the coal bed development. The average drilling and completion cost for our coal bed methane gas wells has averaged approximately $105,000 per well, with average reserves per successful Wyodak well of approximately 275 MMcf. The majority of future development will be concentrated on developing the Big George and other coal seams. Much of the Big George coal seam is deeper and thicker than the Wyodak coal. We expect that as wells are drilled and developed in the Big George coal, the gas reserves and production per well and the average drilling and completion cost per well will increase.

We currently plan to participate in a total of 600 to 650 gross wells in 2003, which is a reduction from our original estimate of 845 wells. The reduction is the result of delays in receiving permits to drill on federal lands from the Bureau of Land Management, or BLM. Our share of production from wells in which we own an interest averaged approximately 124 MMcfe per day in the first nine months of 2003. This represents an increase of 9% from the average daily production in the first nine months of 2002. We currently anticipate daily production to remain relatively constant through the end of 2003.

Industry-wide, production from the Big George coal increased to approximately 112 MMcf per day in August 2003 from nine individual areas separated by as much as 40 miles. This represents an increase of 158% since August 2002. We are currently evaluating 11 pilot areas and one development area in the Big George. We have marketable production quantities in the All Night Creek, Pleasantville and Kingsbury areas. In October 2003, these areas were producing a combined 37 gross MMcf per day.

On April 30, 2003, the BLM issued the final Record of Decision, or ROD, in relation to its Environmental Impact Statement, or EIS regarding future coal bed methane, or CBM, drilling in the Powder River Basin. The ROD requires additional surveys for plant and animal species, cultural surveys and noxious weed mitigation. We have filed permit applications for approval by the BLM under the terms of the new EIS, but are unable to predict the rate at which permits will be granted. Since the issuance of the final ROD, the BLM has been reviewing their permitting process in an effort to issue to industry, a total of 3,000 permits per year. In the last four months, the BLM has issued to industry, a total of 270 permits. This timing may be further affected by several lawsuits, which were filed on May 1, 2003 in the U.S. District Court in Billings, Montana challenging the BLM’s decision. While we believe that these lawsuits are unlikely to be successful, we are unable to predict the outcome of the litigation or the impact, if any, on the timing of our development. For further information, see “Part II – Other Information – Item 1. Legal Proceedings” of this Form 10-Q.

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 existing production is from wells draining into these areas. Most of our undeveloped prospects from the Big George formation are located in the Powder River drainage area. The Wyoming DEQ will require additional water management techniques, such as containment or treating, in these areas pursuant to the conditions described in the EIS referred to above. While we believe these additional requirements will add to the cost of development of this area we do not believe they will have a significant impact on our results of operation or financial position.

Our 2003 capital budget in the Powder River Basin coal bed project includes approximately $45.2 million for drilling costs, production equipment and lease acquisitions, of which approximately $28.3 million was spent in the first nine months of 2003. 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 during 2003.

Jonah/Pinedale Fields. Our upstream assets in the Green River Basin of southwest Wyoming are located in the Jonah Field and Pinedale Anticline areas. During the first nine months of 2003, we participated in 43 gross wells, or four net wells,

in these areas, at a cost of $5.4 million and experienced a success rate of 100%. Our capital budget for 2003 in the Jonah Field and Pinedale Anticline areas provides for expenditures of approximately $20.1 million for drilling costs and production equipment. 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. During the remainder of 2003, we expect to participate in the drilling of 13 gross wells, or approximately one net wells on the Pinedale Anticline.

In the third quarter of 2003, the Wyoming Oil & Gas Commission approved two in-fill pilot programs on our leasehold to evaluate decreasing the well spacing on the Pinedale Anticline to 20 acres per well from 40 acres per well. A total of 64 wells are expected to be drilled by two of the operators in this area during the next 12 to 24 months in this program. We will have the option to participate in this new drilling program on a well-by-well basis.

The expected gross costs to drill a successful well in this area range from approximately $3.5 million to $5.0 million, depending on location of the well site and the depth of the well. Average well depths in this area range from approximately 13,000 feet to 14,200 feet, and average gross reserves per successful well approximate 6 to 8 Bcfe. During the third quarter of 2003, we produced an average of 20 MMcfe per day, net, from these areas.

Sand Wash Basin. We continue to explore and develop our acreage position in the Sand Wash Basin in northwest Colorado, located in the Greater Green River Basin. In August 2003, through the acquisition of the stock of a private corporation for $12.9 million, we acquired additional reserves, production and acreage in this area. This acquisition included 10.6 Bcfe of proved reserves, 2.1 MMcfed of production and approximately 11,000 net acres under lease.

We now own approximately 208,000 gross oil and gas leasehold acres, or approximately 188,000 net acres, in this basin. The majority of this acreage is in the exploration phase and will be evaluated in future years. In September and October 2003, we drilled an exploratory well, which encountered mechanical difficulties prior to reaching the targeted reservoir. This well has been plugged and abandoned. In connection with this well, we recorded a dry hole expense of approximately $300,000 in the third quarter of 2003 and will record an additional charge of approximately $1.0 million in the fourth quarter of 2003. Our capital budget in this area provides for expenditures of approximately $18.2 million during 2003 for our participation in the drilling of eight gross developmental wells, or one net wells, and two workovers of existing wells. Of the total 2003 capital budget, approximately $11.8 million was spent in the first nine months of 2003.

Exploration. We are also actively seeking to add additional upstream core projects that are focused on Rocky Mountain natural gas. We will utilize our expertise in exploration and low-risk development of tight-gas sands, coal bed methane and fractured shale plays to evaluate acquisitions of either additional leaseholds, proven and undeveloped reserves or companies with operations focused in the Rockies. Toward this goal, we have acquired the drilling rights on approximately 275,000 net acres in another basin. In the fourth quarter of 2003, we intend to drill two wells in this area to further evaluate its potential.

In the fourth quarter of 2003, we also participated in an exploratory well for a 25% working interest in the eastern Green River Basin. The well is waiting on completion. If this well is successful, additional offset locations may be proposed.

Midstream Operations

Our midstream operations consist of our gathering, processing, treating, marketing and transportation operations. An important element of our long-term business plan is to meet or exceed throughput projections in these areas and to optimize their profitability. To achieve this goal, we must continue our efforts to add to natural gas throughput levels through new well connections and through the expansion or acquisition of gathering or processing systems. We also seek to increase the efficiency of our operations by modernization of equipment and the consolidation of existing facilities.

Gas Gathering, Processing and Treating.

At September 30, 2003, we operated a variety of gathering, processing and treating facilities, or plant operations, with approximately 9,933 miles of gathering lines, as presented on the Principle Gathering and Processing Facilities Table, as set forth below. These facilities are primarily located in five states and have a combined throughput capacity of 2.9 billion cubic feet, Bcf, per day of natural gas. Our operations are located in some of the most actively drilled oil and gas producing basins in the United States. Five of our processing plants can further separate, or fractionate, the mixed NGL stream into ethane, propane, normal butane and natural gasoline to obtain a higher value for the NGLs, and three of our plants are capable of processing and treating natural gas containing hydrogen sulfide or other impurities that require removal prior to delivery to market pipelines. In addition to our integrated upstream and midstream operations in the Powder River and Green River Basins in Wyoming, our

core assets include our plant operations located in west Texas and Oklahoma. We believe that our core assets have stable production rates, provide a significant operating cash flow and continue to provide us with strategic growth opportunities.

Powder River Basin. Our midstream operations in the Powder River Basin are fully integrated with our upstream operations as we provide the gathering, compression and processing services for our own production. Additionally we provide the same types of services for third-parties. As of September 30, 2003, our assets in the Powder River Basin in northeast Wyoming were primarily comprised of our coal bed methane gathering system with a capacity of 525 MMcf per day, several gas processing facilities with a combined capacity of 146 MMcf per day, and our 13% equity interest in Fort Union.

We averaged 423 MMcf per day of CBM gathering volumes, including third-party gas, during the third quarter of 2003. Of that volume, approximately 111 MMcf per day was transported through our MIGC pipeline. As part of our settlement of on-going litigation with our co-developer in this area, we amended our long-term gathering contract for gas produced by our co-developer to significantly increase the area of dedication, to extend the term of the contract, and to modify the fee schedule. While this does not immediately increase our gathering volumes, we believe that we are well positioned for future growth opportunities.

We are the construction manager and field operator of the Fort Union gathering system and header. The Fort Union system 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 has a capacity of 635 MMcf per day. We have a long-term, firm gathering agreement with Fort Union for 83 MMcf per day of this capacity at $0.14 per Mcf.

Our capital budget in the Powder River Basin for midstream activities provides for expenditures of approximately $15.2 million during 2003, of which approximately $8.1 million was spent in the first nine months of the year. Depending upon our future drilling success, we may need to make additional capital expenditures or leasing commitments to continue expansion in this basin. Due to drilling, regulatory, commodity pricing and other uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure.

Green River Basin. Our midstream operations in the Green River Basin of southwest Wyoming are also fully integrated with our upstream operations in this area. Our midstream assets in this basin are comprised of the Granger and Lincoln Road facilities, or collectively the Granger complex, our 50% equity interest in Rendezvous, our Red Desert facility and our recently acquired Table Rock, Wamsutter and Desert Springs gathering systems. These facilities have a combined gathering capacity of 682 MMcf per day, and in the nine months ended September 30, 2003, these facilities averaged throughput of 548 MMcf per day. Additionally, these systems have a combined processing capacity of 327 MMcf per day and in the nine months ended September 30, 2003, processed an average of 216 MMcf per day.

Our 2003 capital budget for midstream activities in this basin provides for expenditures of approximately $81.3 million during 2003 of which $52.5 million was spent in the first nine months of the year. This capital budget includes approximately $28.1 million for gathering lines and installation of compression to expand the capacity of our Granger Complex, our Wamsutter gathering system and our Red Desert facility, $16.1 million for additional contributions to Rendezvous for the expansion of its system and $37.1 million for the acquisition of additional gathering systems in February 2003. Due to drilling, commodity pricing and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure.

In 2001, we, together with an unrelated third-party, formed Rendezvous. Rendezvous gathers gas along the Pinedale Anticline for blending or processing at either our Granger Complex or at the third-party owned and operated Blacks Fork processing facility. Each company owns a 50% interest in Rendezvous, and we serve as field operator of its systems. Rendezvous has a capacity of 275 MMcf per day and in the nine months ended September 30, 2003 gathered an average of 215 MMcf per day. An expansion of the system is planned for completion in December 2003. The expansion would extend the system approximately 24 miles further into the Pinedale Anticline and increase the overall capacity of the system to 350 MMcf per day. The estimated cost of this expansion is $32.0 million gross, of which our share is approximately $16.0 million. As part of Rendezvous’ expansion process, we are implementing a 100 MMcf per day processing capacity upgrade at our Granger plant at a cost of $2.0 million.

West Texas. Our primary assets in west Texas are the Midkiff/Benedum complex and the Gomez and Mitchell Puckett treating facilities. These facilities process gas produced by third-parties in the Permian Basin, have a combined operational capacity of 565 MMcf per day and processed an average of 287 MMcf per day in the first nine months of 2003. Also for this

period, these facilities produced an average of 208 MMcf per day of natural gas for delivery to sales markets and produced an average of 796 MGal per day of NGLs. Our capital budget in this area provides for expenditures of approximately $7.4 million during 2003, of which $5.2 million was spent in the first nine months.

Oklahoma. Our primary assets in Oklahoma are the Chaney Dell and Westana systems. These facilities gather and process gas produced by third-parties in the Anadarko Basin and have a combined operational capacity of 175 MMcf per day. In the nine months ended September 30, 2003, these facilities gathered an average of 160 MMcf per day, produced an average of 139 MMcf per day of natural gas for delivery to sales markets and produced 307 MGal per day of NGLs. Our capital budget in this area provides for expenditures of approximately $15.7 million during 2003, of which approximately $10.3 million has been spent in the first nine months.

Principal Gathering and Processing Facilities Table. The following tables provide information concerning our principal gathering, processing and treating facilities at September 30, 2003.

Facilities (1)	Year Placed In Service	Gas Gathering System Miles (2)	Gas Throughput Capacity (MMcf/D) (3)	Average for the Nine months Ended September 30, 2003
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	88	81	—
Midkiff/Benedum	1949	2,245	165	137	87	795
Mitchell Puckett Treating (6)	1972	93	120	62	40	1
Wyoming
Coal Bed Methane Gathering	1990	1,312	525	416	218	—
Desert Springs Gathering (10)	1979	65	10	6	6	16
Fort Union Gas Gathering	1999	167	635	481	481	—
Granger (7)(8)(9)	1987	538	235	227	150	309
Hilight Complex (7)	1969	626	124	16	11	52
Kitty/Amos Draw (7)	1969	314	17	6	4	27
Lincoln Road (9)	1988	149	50	36	20	9
Newcastle (7)	1981	146	5	3	2	20
Red Desert (7)	1979	111	42	13	11	21
Rendezvous	2001	—	275	215	215	—
Reno Junction (8)	1991	—	—	—	—	102
Table Rock Gathering (10)	1979	101	20	14	14	—
Wamsutter Gathering (10)	1979	186	50	37	37	5
Wind River Gathering (10)	1979	109	80	47	47	—
Oklahoma
Chaney Dell/Westana	1966	3,141	175	160	139	307
New Mexico
San Juan River (6)	1955	140	60	29	23	46
Utah
Four Corners Gathering	1988	104	15	3	2	16
Total		9,933	2,883	1,996	1,588	1,726

(1) Our interest in all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%); Fort Union gathering system (13%) and Rendezvous (50%). We operate all facilities, and all data include 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, processing or treating facilities.

(2) Gas gathering system miles are as of September 30, 2003.

(3) Gas throughput capacity is as of September 30, 2003 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.

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

(9) Lincoln Road is operated on an intermittent basis to process excess gas from the Granger system.

(10) These facilities were acquired on February 1, 2003.

Transportation. We own and operate MIGC, Inc. an interstate pipeline located in the Powder River Basin in Wyoming, and MGTC, Inc., an intrastate pipeline located in northeast Wyoming. MIGC charges a Federal Energy Regulatory Commission, or 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 nine months ended September 30 2003, MIGC transported an average of 159 MMcf per day. It is anticipated that

MIGC will continue to operate around that level in the fourth quarter of 2003 as well. MIGC earns fees 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. Contracts for firm capacity on MIGC range in duration from one month to six years and the fees charged averaged $0.33 per Mcf in the first nine months of 2003. MGTC provides transportation and gas sales to various cities in Wyoming at rates that are subject to the approval of the Wyoming Public Service Commission.

The following table provides information concerning our principal transportation assets at September 30, 2003.

			Average for the Nine Months Ended September 30, 2003
Transportation Facilities (1)	Year Placed In Service	Transportation Miles (2)	Pipeline Capacity (MMcf/D) (2)	Gas Throughput (MMcf/D) (3)
MIGC (4)	1970	245	130	159
MGTC (5)	1963	252	18	6
Total		497	148	165

(1) Our interest in all facilities is 100%, and we operate all facilities.

(2) Ttransportation miles and pipeline capacity are as of September 30, 2003. Pipeline capacity represents certificated capacity at the Powder River junction only and does not include interruptible capacity or capacity at other delivery points.

(3) Aggregate volumes transported by a pipeline.

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

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

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. In addition to our offices in Denver, we have a marketing office in both Houston, Texas and Calgary, Alberta. 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. For the nine months ended September 30, 2003, our total gas sales volumes averaged 1.4 Bcf per day, of which 475 MMcf per day was produced at our plants or from our producing properties, or equity volumes.

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. Historically, the gas produced in the Rocky Mountain region has traded at a substantial discount to the Mid-Continent and west coast areas as a result of limited pipeline capacity from the region. In the nine months ended September 30, 2003, as a result of our firm transportation capacity, we realized an approximate $0.20 per Mcf improvement in price for natural gas relative to the price that would have been received if these capacity rights had not existed. In the second quarter of 2003, additional pipeline capacity out of the Rocky Mountain region went into service. This pipeline expansion contributed to a reduction in the price difference between the Rocky Mountain region and Mid-Continent market center to approximately $0.48 per Mcf in September 2003 as compared to an average of $2.30 per Mcf in the first quarter of 2003. We expect this additional pipeline capacity to continue to an ongoing impact on the price differences between the Rocky Mountain and Mid-Continent regions. The remainder of our equity production of natural gas in the Rocky Mountain region that is not transported to the Mid-Continent is hedged for the remainder of 2003 using financial instruments.

We sell gas under agreements with varying terms and conditions in order to match seasonal and other changes in demand. As of September 30, 2003, the average duration of our sales contracts was 14 months. The marketing of products purchased from third-parties typically results in low profit margins relative to the sales price. In general, due to price volatility and credit concerns in the energy industry, our overall sales volume in 2003 has decreased as compared to prior years.

publications. See further discussion in “Part II – Other Information, Item 1. Legal Proceedings.”

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 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 nine months ended September 30, 2003, NGL sales averaged 1,640 MGal per day, of which 1,350 MGal per day was produced at our plants.

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 agricultural applications. Price, seasonality and the economy primarily affect the demand for NGLs. As in the case of natural gas, we continually monitor and review the credit exposure to our NGL marketing counterparties.

We sell NGLs under agreements with varying terms and conditions in order to match seasonal and other changes in demand. At September 30, 2003, the terms of our sales contracts range from one month to three years. The marketing of products purchased from third-parties typically results in low profit margins relative to the sales price.

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 and net income in relation to those anticipated by our operating budget. The second goal is to manage price risk related to our 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 also use financial instruments to reduce 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 through OTC swaps and options with various counterparties, consisting primarily of investment banks, financial institutions and other natural gas companies. We conduct credit reviews of all of our OTC counterparties 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 OTC exposures. OTC exposure is marked-to-market daily for the credit review process. Our exposure to OTC credit risk is reduced by our ability to require a margin deposit from our counterparties based upon the mark-to-market value of their net exposure. We are also subject to margin deposit requirements under these same agreements and under margin deposit requirements for our NYMEX transactions. At October 31, 2003, we did not have a material amount of margin deposits outstanding.

We continually monitor and review the credit exposure to our marketing counterparties. 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. Although netting agreements similar to those that we utilize have been upheld by bankruptcy courts in the past, if any of these customers with whom we have netting agreements were to file for bankruptcy, we can provide no assurance that our agreements will not be challenged or as to the outcome of any challenge.

The use of financial instruments may expose us to the risk of financial loss in some 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 counterparties 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.

Risk Policy and Control. We control the extent of risk management and marketing activities through policies and procedures that involve the senior level of management. On a daily basis, our marketing activities are audited and monitored by our independent risk oversight department, or IRO. This department reports to the Chief Financial Officer, thereby providing a separation of duties from the marketing department. Additionally, the IRO reports monthly to the Risk Management Committee, or RMC. This committee is comprised of corporate managers and officers and is responsible for developing the policies and guidelines that control the management and measurement of risk. The RMC is also responsible for setting risk limits including value-at-risk and dollar stop loss limits. Our board of directors approves the risk limit parameters and risk management policy.

Hedge Positions. As of October 31, 2003, we have hedged approximately 51% of our projected 2003 equity natural gas volumes and approximately 78% of our estimated equity production of crude oil, condensate, and NGLs. We have also begun to enter into hedges for our projected 2004 equity natural gas volumes and for our estimated equity production of crude oil, condensate, and NGLs. All of 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 fair value of derivatives. We regularly use crude oil swaps in hedging the variability in the sales price of butanes, which may result in hedge ineffectiveness from time to time. During the nine months ended September 30, 2003, we recognized a loss of $46,000 from the ineffective portions of our hedges. Overall, our hedges are expected to continue to be “highly effective” under SFAS 133 in the future.

To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must be highly correlated 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 2003. The following table details our hedge positions as of October 31, 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 $155,000. There is no associated cost for the natural gas hedges.

Product	Quantity and NYMEX or Settlement Price	Hedge of Basis Differential
Natural gas	50,000 MMbtu per day with an average price of $3.94 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.	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 – 45,000 MMbtu per day with an average basis price of ($0.78) per MMbtu.

Crude Oil	55,000 Barrels of crude oil per month with an average price of $24.97 per barrel.	Not Applicable

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	100,000 Barrels per month. Average minimum and maximum price of $0.37 per gallon and $0.50 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

Outstanding Equity Hedge Positions and the Associated Basis for 2004. The following table details our hedge positions as of October 31, 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 $1.2 million. There is no associated cost for the natural gas hedges.

Product	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	70,000 MMBtu per day with a minimum price of $4.00 and a maximum price ranging from $6.50 to $9.45 (average of $7.81 per MMBtu.)	Mid-Continent – 55,000 MMBtu per day with an average basis price of ($0.266). Permian – 5,000 MMBtu per day with an average basis price of ($0.345) per MMbtu. Rocky Mountain – 10,000 MMBtu per day with an average basis price of ($0.745) per MMbtu.

Crude, Condensate, Natural Gasoline	50,000 Barrels per month with a minimum price of $22.00 per barrel and a maximum price of $30.08 per barrel.	Not Applicable

Butanes	50,000 Barrels per month. Floor at $22.00 per barrel. (Crude oil used as surrogate for butanes.)	Not Applicable

Propane	90,000 Barrels per month with minimum and maximum price of $0.425 per gallon and $0.56 per gallon, respectively.	Not Applicable

Ethane	50,000 Barrels per month. Floor at $0.305 per gallon.	Not Applicable

Account balances related to equity and transportation hedging transactions at September 30, 2003 were $2.7 million in Current Assets from price risk management activities, $7.7 million in Current Liabilities from price risk management activities, $875,000 in Non-current assets from price risk management activities, $162,000 in Non-current liabilities from price risk management activities, ($1.6) million in Deferred income taxes payable, net, and a $2.8 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Shareholders’ Equity. Based on prices as of September 30, 2003, approximately $4.3 million of losses in Accumulated other comprehensive income will be reclassified to earnings in 2003 and $1.5 million of gains in Accumulated other comprehensive income will be reclassified to earnings in 2004.

Summary of Derivative Positions. A summary of the change in our derivative position from December 31, 2002 to September 30, 2003 is as follows (dollars in thousands):

Fair value of contracts outstanding at December 31, 2002	$	63
Decrease in value due to change in price	(29,928		)
Increase in value due to new contracts entered into during the period	30,865
Losses realized during the period from existing and new contracts	6,285
Changes in fair value attributable to changes in valuation techniques	—
Fair value of contracts outstanding at September 30, 2003	$	7,285

A summary of our outstanding derivative positions at September 30, 2003 is as follows (dollars in thousands):

	Fair Value of Contracts at September 30, 2003
Source of Fair Value	Total Fair Value				Maturing In 2003			Maturing In 2004-2005		Maturing In 2006-2007			Maturing Thereafter
Exchange published prices	$	(4,189		)	$	(6,196	)	$	2,007	—			—
Other actively quoted prices (1)	5,603				3,000			2,611		$	(8	)	—
Other valuation methods (2)	5,871				(63		)	5,934		—			—
Total fair value	$		7,285		$	(3,259	)	$	10,552	$	(8	)	—

(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, 2003, the net notional value of such contracts was approximately $25.0 million in Canadian dollars, which approximates fair market value.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures.

At the end of the reporting period, we carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and President and Executive Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Company’s Chief Executive Officer and President and Executive Vice President and Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Changes in Internal Controls Over Financial Reporting.

Our Chief Executive Officer and Chief Financial Officer have also concluded that there has not been any change in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Western Gas Resources, Inc. and Lance Oil & Gas Company, Inc. v. Williams Production RMT Company, (Defendant), Civil Action No. CO2-10-394, District Court, County of Sheridan, Wyoming. As most recently reported in our Form 10-Q for the quarter ended June 30, 2003, in October 2002, we filed a complaint for declaratory relief and damages related to a dispute arising under a development agreement and other agreements between the parties. On October 24, 2003, we reached an agreement with the Defendant to settle these disputes, as previously disclosed in our Form 8-K filed on October 24, 2003. Under the terms of the settlement agreement, the Defendant and we each operate the drilling and production on approximately half of the jointly owned leasehold in the coal-bed methane development of the Powder River Basin of Wyoming. Effective November 1, 2003, the parties agreed to an expanded area of mutual interest and Western assumed an expanded area of dedication in its gas gathering operations in the Powder River Basin. The parties have also agreed to modifications to the fee schedule. On November 3, 2003, we filed, in conjunction with the Defendant, a joint stipulation of voluntary dismissal of this action.

Price, et al. v. Gas Pipelines, Western Gas Resources, Inc., et al., District Court, Stevens County, Kansas, Case No. 99-C-30. As most recently reported in our Form 10-Q for the quarter ended June 30, 2003, we are a defendant in litigation filed in 1999, along with numerous other natural gas companies, in which Mr. Price is claiming an under measurement of gas and Btu volumes throughout the country. We along with other natural gas companies filed a motion to dismiss for failure to state a claim. The court denied these motions to dismiss. The court denied plaintiff’s motion for certification as a class and, in the second quarter of 2003, the plaintiff amended and refiled for certification as a class. On May 12, 2003, Mr. Price filed a further claim Will Price et al v. Western Gas Resources, Inc. et al., District Court, Stevens County, Kansas, Case No. 03C23, relating to certain matters previously removed from the foregoing action. We believe that Mr. Price’s claims are without merit and intend to vigorously contest the allegations in this case. At this time, we are unable to predict the outcome of this matter.

In the Matter of the Appeal of Lance Oil & Gas Company from a Decision by the Department of Revenue, Docket No. 2003-44, Before the State Board of Equalization for the State of Wyoming. As most recently reported in our Form 10-Q for the quarter ended June 30, 2003, the Wyoming Department of Revenue has conducted an audit of Lance Oil & Gas Company, Inc. for the period from January 1, 1998 through December 31, 1999. On March 24, 2003, the Department of Revenue notified us that it had assessed additional severance taxes and increased taxable value for ad valorem tax purposes. The additional severance and ad valorem taxes claimed by the Department of Revenue amount to $196,000 and $351,000, respectively, together with statutory interest. We believe that the Wyoming Department of Revenue claims are without merit and intend to vigorously contest their assessments. On April 23, 2003, we filed a Notice of Appeal with the Wyoming State Board of Equalization. The hearing has been set for March 15, 2004. We also filed an appeal on October 24, 2003 in Lance Oil & Gas Company v. Campbell County Treasurer, District Court, Campbell County, Wyoming, Civil Action No. 25203, to appeal the assessment of interest claimed by the Campbell County Treasurer in relation to the additional taxes assessed by the Wyoming Department of Revenue.

In the Matter of the Notice of Violation Issued to Mountain Gas Resources, Inc., Department of Environmental Quality, State of Wyoming. As reported in our Form 10-Q for the quarter ended June 30, 2003, we received a Notice of Violation issued by the State of Wyoming Department of Environmental Quality for failing to obtain a permit prior to constructing certain dehydration units at facilities in Sublette County, Wyoming. This Notice of Violation was received after we self-reported to the Department of Environmental Quality in April 2003 that we had inadvertently failed to submit notices of intent and air permit applications for such dehydration units. We anticipate that we will be able to resolve this matter in the fourth quarter of 2003 and that it will not have a material adverse effect on our financial position, results of operations or cash flows.

National Pipeline Mapping System. As reported in our Form 10-Q for the quarter ended June 30, 2003, we received correspondence from the U.S. Department of Transportation regarding our failure to submit information for incorporation into the National Pipeline Mapping System within nine months of enactment of the Pipeline Safety Improvement Act of 2002. We have worked with the U.S. Department of Transportation Office of Pipeline Safety to supply the required information. We are unable to predict whether we will be subject to any fines or penalties under the Pipeline Safety Improvement Act, and what the amount of such fines would be if imposed.

conducted in response to a subpoena issued by the Commodity Futures Trading Commission, or CFTC. Certain of our employees have identified inaccuracies associated with reporting of natural gas transactions primarily related to points in Texas. Our review of this and other regions is continuing as we respond to the CFTC subpoena. We are unable to predict whether we will be subject to any fines or penalties by CFTC, and what the amount of such fines would be if imposed.

Challenges to the Powder River Basin EIS. As reported in our Form 10-Q for the quarter ended June 30, 2003, two lawsuits were filed challenging the Federal Bureau of Land Management’s Record of Decision on the Environmental Impact Statement issued on April 30, 2003 as it relates to the State of Wyoming. The respective suits are Western Organization of Resource Councils vs. Kathleen Clarke et al., Case No. CV-03-70-BLG-RWA, U.S. District Court for the District of Montana and American Lands Alliance v. U.S. Bureau of Land Management et al., Case No. CV-03-71-BLG-RWA, U.S. District Court for the District of Montana.

Both the Bureau of Land Management and the State of Wyoming have filed separate motions to dismiss for lack of venue or, in the alternative, to transfer the cases to the U.S. District Court, for the District of Wyoming. We, along with various industry companies, have filed motions to intervene and responses to the complaints, including motions to dismiss. At this time we are unable to predict the outcome of this matter or its impact on our future development plans in the Powder River Basin.

Other Litigation. We are involved in various other litigation and administrative proceedings arising in the normal course of business. In the opinion of our 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 or cash flows.

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

None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)	Exhibits:

	Exhibit Number	Description

	3.1	Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.1 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).

	3.2	Certificate of Amendment to the Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.2 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).

	3.3	Certificate of Designation of 7.25% Cumulative Senior Perpetual Convertible Preferred Stock of the Company (previously filed as Exhibit 3.5 to Western Gas Resources, Inc.’s Registration Statement on Form S-1, Registration No. 33-43077 and incorporated herein by reference).

	3.4	Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on April 7, 2003 (previously filed as Exhibit 3.5 to our Quarterly Report on Form 10-Q filed on May 13, 2003 and incorporated herein by reference).

	31.1	Section 302 Certification of the Chief Executive Officer.

	31.2	Section 302 Certification of the Chief Financial Officer.

	32.1	Section 906 Certification of the Chief Executive Officer and Chief Financial Officer.

	(b) Reports on Form 8-K:

	During the quarter ended September 30, 2003, we furnished the following reports on Form 8-K:

• Current Report on Form 8-K filed on August 12, 2003, announcing financial results for the quarter and six months ending June 30, 2003.

• Current Report on Form 8-K filed on September 30, 2003, reporting an internal review of historical price reporting to gas trade publications.

• Current Report on Form 8-K filed on October 24, 2003, announcing the settlement of litigation with Williams Production RMT Company.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	WESTERN GAS RESOURCES, INC.
	(Registrant)


Date: November 12, 2003	By:	/s/ PETER A. DEA
		Peter A. Dea
		Chief Executive Officer and President


Date: November 12, 2003	By:	/s/ WILLIAM J. KRYSIAK
		William J. Krysiak
		Executive Vice President - Chief Financial Officer
		(Principal Financial and Accounting Officer)

Exhibit Index

3.1		Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.1 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).

3.2		Certificate of Amendment to the Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.2 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).

3.3		Certificate of Designation of 7.25% Cumulative Senior Perpetual Convertible Preferred Stock of the Company (previously filed as Exhibit 3.5 to Western Gas Resources, Inc.’s Registration Statement on Form S-1, Registration No. 33-43077 and incorporated herein by reference).

3.4		Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on April 7, 2003 (previously filed as Exhibit 3.5 to our Quarterly Report on Form 10-Q filed on May 13, 2003 and incorporated herein by reference).

31.1		Section 302 Certification of the Chief Executive Officer.

31.2		Section 302 Certification of the Chief Financial Officer.

32.1		Section 906 Certification of the Chief Executive Officer and Chief Financial Officer.