WESTERN GAS RESOURCES INC - 10-Q Quarterly Report

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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, 2004

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 of the Exchange Act). Yes ý No o

On November 1, 2004, there were 73,955,425 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, 2004 and December 31, 2003

		Consolidated Statement of Cash Flows - Three Months Ended September 30, 2004 and 2003

		Consolidated Statement of Operations - Three Months Ended September 30, 2004 and 2003

		Consolidated Statement of Changes in Stockholders’ Equity - Three Months Ended September 30, 2004

		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 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, 2004				December 31, 2003
	(unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	2,719			$			26,116
Trade accounts receivable, net	240,235				262,509
Inventory	109,260				70,304
Assets from price risk management activities	35,760				17,149
Other	9,210				11,225
Total current assets	397,184				387,303

Property and equipment:
Gas gathering, processing and transportation	1,090,319				1,028,176
Oil and gas properties and equipment (successful efforts method)	385,654				329,555
Construction in progress	158,705				134,751
	1,634,678				1,492,482
Less: Accumulated depreciation, depletion and amortization	(548,506			)	(495,721				)

Total property and equipment, net	1,086,172				996,761

Other assets:
Gas purchase contracts (net of accumulated amortization of $40,223 and $38,937, respectively)	27,932				29,219
Assets from price risk management activities	546				1,466
Equity investments	38,021				39,289
Other	4,071				6,486

Total other assets	70,570				76,460

TOTAL ASSETS	$	1,553,926			$		1,460,524

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$		284,734		$		303,186
Accrued expenses	38,455				42,136
Liabilities from price risk management activities	34,617				10,603
Dividends payable	3,697				3,056
Total current liabilities	361,503				358,981

Long-term debt	317,500				339,000
Liabilities from price risk management activities	1,881				1,304
Other long-term liabilities	24,373				22,057
Deferred income taxes payable, net	217,376				176,673

Total liabilities	922,633				898,015

Stockholders’ equity:
Preferred Stock; 10,000,000 shares authorized: $2.625 cumulative convertible preferred stock, par value $0.10; 0 and 2,060,000 issued and outstanding, respectively	—				206
Common stock, par value $0.10; 100,000,000 shares authorized; 73,891,286 and 68,271,802 shares issued, respectively	7,412				6,876
Treasury stock, at cost; 50,032 common shares in treasury	(788			)	(788				)
Additional paid-in capital	388,469				381,581
Retained earnings	241,354				173,076
Accumulated other comprehensive income	(5,154			)	1,558

Total stockholders’ equity	631,293				562,509

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$		1,553,926		$	1,460,524

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,
	2004			2003

Reconciliation of net income to net cash provided by operating activities:
Net income	$	78,181		$	65,164
Add income items that do not affect cash:
Depreciation, depletion and amortization	67,013			53,305
Loss on the sale of property and equipment	1,409			142
Cumulative effect of a change in accounting principle	(4,714		)	6,724
Deferred income taxes	42,533			39,272
Non-cash change in fair value of derivatives	(2,163		)	(1,084		)
Other non-cash items, net	2,468			2,527

Adjustments to working capital to arrive at net cash provided by operating activities:
Decrease in trade accounts receivable	23,125			38,717
Increase in inventory	(37,738		)	(28,379		)
(Increase) decrease in other current assets	(2,365		)	9,882
(Increase) decrease in other assets and liabilities, net	205			(478		)
Increase (decrease) in accounts payable	(18,452		)	20,375
Increase (decrease) in accrued expenses	(200		)	4,306

Net cash provided by operating activities	149,302			210,473

Cash flows from investing activities:

Purchases of property and equipment	(147,103		)	(125,484		)
Proceeds from dispositions of property and equipment	1,022			3,831
Contributions to equity investees	—			(10,450		)
Distributions from equity investees	1,196			—

Net cash used in investing activities	(144,885		)	(132,103		)

Cash flows from financing activities:

Net proceeds from exercise of common stock options	6,760			3,062
Payments for the redemption of preferred stock	(1,930		)	—
Debt issue costs paid	(1,850		)	(1,851		)
Borrowings of long-term debt	100,000			—
Payments on long-term debt	(165,000		)	15,000
Borrowings under revolving credit facility	1,390,330			747,200
Payments on revolving credit facility	(1,346,830		)	(780,800		)
Dividends paid	(9,294		)	(10,403		)

Net cash (used in) financing activities	(27,814		)	(27,792		)

Net (decrease) increase in cash and cash equivalents	(23,397		)	50,578

Cash and cash equivalents at beginning of period	26,116			7,312

Cash and cash equivalents at end of period	$	2,719		$	57,890

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,
	2004			2003			2004			2003

Revenues:
Sale of gas	$	560,983		$	557,105		$	1,821,974		$	1,909,297
Sale of natural gas liquids	124,464			86,009			319,400			258,840
Gathering, processing and transportation revenue	25,080			21,884			66,319			63,119
Price risk management activities	7,158			1,065			5,338			(18,050		)
Other	570			737			2,743			2,191
Total revenues	718,255			666,800			2,215,774			2,215,397

Costs and expenses:
Product purchases	585,774			566,937			1,845,282			1,898,375
Plant and transportation operating expense	23,976			21,944			68,165			66,478
Oil and gas exploration and production expense	18,510			13,029			55,432			38,830
Depreciation, depletion and amortization	22,039			17,477			67,013			53,305
(Gain) loss on sale of assets	(230		)	56			1,409			142
Selling and administrative expense	10,305			8,972			37,506			29,487
Earnings from equity investments	(1,542		)	(1,780		)	(5,244		)	(5,209		)
Loss from early extinguishment of debt	—			—			10,662			—
Interest expense	3,912			6,449			15,065			19,692
Total costs and expenses	662,744			633,084			2,095,290			2,101,100

Income before income taxes	55,511			33,716			120,484			114,297
Provision for income taxes:
Current	1,949			544			4,484			3,137
Deferred	18,444			12,283			42,533			39,272
Total provision for income taxes	20,393			12,827			47,017			42,409

Income before cumulative effect of change in accounting principle	35,118			20,889			73,467			71,888

Cumulative effect of changes in accounting principles net of tax of $2,710 and net of tax benefit of $3,967, respectively	—			—			4,714			(6,724		)

Net income	35,118			20,889			78,181			65,164

Preferred stock requirements	—			(1,811		)	(835		)	(5,434		)

Income attributable to common stock	$	35,118		$	19,078		$	77,346		$	59,730

Net income per share of common stock before cumulative effect of change in accounting principle	$	.48		$	.29		$	1.01		$	1.00

Cumulative effect of change in accounting principle	$	—		$	—		$	.07		$	(.10	)

Earnings per share of common stock	$	.48		$	.29		$	1.08		$	.90

Weighted average shares of common stock outstanding	73,778,729			66,394,530			71,887,962			66,288,592

Income attributable to common stock – assuming dilution	$	35,118		$	20,889		$	77,346		$	65,164

Earnings per share of common stock – assuming dilution	$	.47		$	.28		$	1.06		$	.87

Weighted average shares of common stock outstanding - assuming dilution	74,998,146			74,690,296			72,934,517			74,541,408

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)

	$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			Total Stock- holders’ Equity

Balance at December 31, 2003	2,060,000		68,271,802	50,032	$	206		$	3,438	$	(788	)	$	385,019		$	173,076		$	1,558		$	562,509
Comprehensive income:
Net income, nine months ended September 30, 2004			—	—	—			—		—			—			78,181			—			78,181
Translation adjustments	—		—	—	—			—		—			—			—			144			144
Other comprehensive income
From equity investees	—		—	—	—			—		—			—			—			(814		)	(814		)
Reclassification adjustment for settled contracts	—		—	—	—			—		—			—			—			1,695			1,695
Changes in fair value of outstanding hedge positions	—		—	—	—			—		—			—			—			(3,124		)	(3,124		)
Hedge ineffectiveness	—		—	—	—			—		—			—			—			(35		)	(35		)
Fair value of new hedge positions	—		—	—	—			—		—			—			—			(4,578		)	(4,578		)
Change in accumulated derivative comprehensive income	—		—	—	—			—		—			—			—			(6,042		)	(6,042		)
Total comprehensive income, net of tax	—		—	—	—			—		—			—			—			—			71,469
Stock options exercised	—		494,256	—	—			36		—			6,724			—			—			6,760
Effect of re-priced options	—		—	—	—			—		—			482			—			—			482
Tax benefit related to stock options	—		—	—	—			—		—			1,938			—			—			1,938
Dividends declared on common stock	—		—	—	—			—		—			—			(9,146		)	—			(9,146		)
Two-for-one common stock split	—		—	—	—			3,683		—			(3,683		)	—			—			—
Dividends declared on $2.625 cumulative convertible preferred stock	—		—	—	—			—		—			—			(789		)	—			(789		)
Conversion of $2.625 cumulative convertible preferred stock	(2,024,404	)	5,125,228	—	(204		)	255		—			(93		)	—			—			(42		)
Redemption of $2.625 cumulative convertible preferred stock	(35,596	)	—	—	(2		)	—		—			(1,918		)	32			—			(1,888		)

Balance at September 30, 2004	—		73,891,286	50,032	$	—		$	7,412	$	(788	)	$	388,469		$	241,354		$	(5,154	)	$	631,293

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

WESTERN GAS RESOURCES, INC.

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, or SEC. 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, 2003. The interim consolidated financial statements as of September 30, 2004 and for the three and nine-month periods ended September 30, 2004 and 2003 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, 2004 are not necessarily indicative of the results of operations expected for the year ended December 31, 2004.

Prior period amounts in the interim consolidated financial statements and notes have been reclassified as appropriate to conform to the presentation used in 2004, including items associated with price risk management activities and the two-for-one common stock split completed on June 18, 2004.

EQUITY TRANSACTIONS

Preferred Stock Conversion/Redemption. In December 2003, we issued a notice of redemption for a total of 800,000 shares of our $2.625 cumulative convertible preferred stock. The holders of these shares had the right to convert them into shares of our common stock in lieu of receiving the redemption price in cash. In January 2004, we issued an additional 1,979,244 shares of common stock to holders who elected to convert their shares and paid $672,000 in cash proceeds to complete this redemption. In March 2004, we issued an additional notice of redemption for the remaining 1,260,000 shares of our $2.625 cumulative convertible preferred stock. In April 2004, we issued an additional 3,113,582 shares of common stock to holders who elected to convert their shares and paid $391,000 in cash proceeds to complete this redemption. After these redemptions, the $2.625 cumulative convertible preferred stock was delisted from trading on the New York Stock Exchange and application was made to the SEC to deregister such stock.

Common Stock Split. On June 18, 2004, we completed a two-for-one split of our common stock, which was distributed in the form of a stock dividend. Shareholders of our common stock received one additional share for every share of common stock held on the record date of June 4, 2004. After the stock split, each share of common stock outstanding or thereafter issued includes or will include one-half of a Series A Junior Participating Preferred Stock purchase right. We have restated our financial information to reflect this split for all periods presented.

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 net income less preferred stock dividends. The following table presents the dividends declared by us for each class of our outstanding equity securities (dollars in thousands, except per share amounts):

	Quarter Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
Common Stock	$	3,697	$	1,661	$	9,146	$	4,977
Preferred Stock	—		1,811		789		5,434
Total Dividends Declared	$	3,697	$	3,472	$	9,935	$	10,411

Dividends Declared Per Share:
Common Stock	$	0.05	$	0.05	$	0.15	$	0.15
Preferred Stock	$	—	$	0.66	$	0.66	$	1.97

Common stock options and, until the final conversion or redemption in April 2004, 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. The share information presented reflects the two-for-one common stock split.

	Quarter Ended September 30,		Nine months Ended September 30,
	2004	2003	2004	2003
Weighted average shares of common stock outstanding	73,778,729	66,394,530	71,887,962	66,288,592
Potential common shares from:
Common stock options	1,219,417	1,352,370	1,046,555	1,309,420
$2.625 Cumulative Convertible Preferred Stock	—	6,943,396	—	6,943,396
Weighted average shares of common stock outstanding - assuming dilution	74,998,146	74,690,296	72,934,517	74,541,408

The numerators and the denominators for the prior periods were adjusted to reflect these potential common 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, 2004 were unrealized losses of $8.3 million from the fair value of derivatives designated as cash flow hedges and unrealized gains of $3.1 million of cumulative foreign currency translation adjustments. In the first quarter of 2004, we discontinued cash flow hedge accounting treatment on our hedges of equity butane production which utilized crude oil puts as a surrogate. The value of these hedging instruments will remain in Accumulated other comprehensive income and will be reclassified to our results of operations as the underlying transactions occur. A loss of $107,000 was included in Accumulated other comprehensive income at September 30, 2004 for these items.

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.

REVENUE RECOGNITION

In the Gas Gathering, Processing and Treating segment, we recognize revenue for our services at the time the service is performed. We record revenue from our gas and NGL marketing activities, including sales of our equity production, upon transfer of title to the product. These revenues are recorded on a gross sales versus sales net of purchases basis as we obtain title to all the gas and NGLs that we buy including third-party purchases, and bear the risk of loss and credit exposure on these transactions. Gas imbalances on our production are accounted for using the sales method. For our marketing activities, we utilize mark-to-market accounting. Under mark-to-market accounting, the expected margin to be realized over the term of the transaction is recorded in the month of origination. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods. In the Transportation 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.

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES

Depreciation, Depletion and Amortization for Oil and Gas Properties. We follow the successful efforts method of accounting for oil and gas exploration and production activities. Producing properties and related equipment are depreciated and depleted by the units-of-production method based on estimated proved reserves. Effective January 1, 2004, we redefined the asset groupings for the calculation of depreciation and depletion from a well-by-well basis to a field wide basis for each of the Jonah, Pinedale and Sand Wash fields and to a grouping of all wells drilled into related coal seams for the Powder River Basin.

The change in the asset groupings for depreciation and depletion purposes is treated as a change in accounting principle. Accordingly, the Accumulated depreciation, depletion and amortization for these assets has been recalculated under the new asset groupings. The cumulative effect of the change in depreciation and depletion method of $4.7 million, net of tax, or $0.07 per share of common stock and $0.06 per share of common stock-assuming dilution, is presented in the Consolidated Statement of Operations under the caption Cumulative effect of changes in accounting principles, net of tax. This change resulted in an increase in Depreciation, depletion and amortization expense of $422,000, or $0.01 per share of common stock and per share of common stock-assuming dilution, in the third quarter of 2004 and $2.0 million, or $0.03 per share of common stock and per share of common stock-assuming dilution, in the nine months ended September 30, 2004.

If we had adopted the change in asset groupings for depreciation and depletion purposes on January 1, 2003, we estimate that Depreciation, depletion and amortization expense would have been $378,000 higher in the third quarter of 2003 than reported on the Consolidated Statement of Operations and $612,000 higher in the nine months ended September 30, 2003. The estimated pro forma cumulative effect of a January 1, 2003 change in our depreciation and depletion methodology would have been an increase of $5.5 million in net income, or $0.08 in earnings per share of common stock and $0.07 per share of common stock-assuming dilution.

Earnings per share of common stock in the third quarter ended September 30, 2003 was $0.29 per share of common stock and $0.28 per share of common stock-assuming dilution. If we had adopted the change in asset groupings for depreciation and depletion purposes on January 1, 2003, earnings per share of common stock for the third quarter ended September 30, 2003 would not have changed. Earnings per share of common stock in the nine months ended September 30, 2003 was $0.90 per share of common stock and $0.87 per share of common stock-assuming dilution. If we had adopted the change in asset groupings for depreciation and depletion purposes on January 1, 2003, earnings per share of common stock in the nine months ended September 30, 2003 would have been $0.97 per share of common stock and $0.93 per share of common stock-assuming dilution.

Accounting for Asset Retirement Obligations. 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 established 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 an $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, net of tax, loss from the Cumulative effect of a change in accounting principle.

POST RETIREMENT BENEFITS

In July 2004, our board of directors authorized the development of an amendment to the board’s existing health care plan to provide for health care benefits for qualifying members, and their spouses, after their retirement from our board of directors. The terms of the plan have not yet been finalized and, accordingly, no accrual for the future cost of this benefit has been made in the financial statements for the quarter and nine months ended September 30, 2004.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The net loss recognized in earnings through Sale of gas and Sale of natural gas liquids during the first nine months of 2004 from hedging activities was $6.3 million, and we recognized a loss from hedge ineffectiveness of $56,000. In the first quarter of 2004, we determined in our quarterly effectiveness testing that our hedges of equity butane production which utilized crude oil puts as a surrogate were no longer effective hedges. Therefore, in the first quarter of 2004, we discontinued cash flow hedge accounting treatment on these instruments. The value of these hedging instruments will remain in Accumulated other comprehensive income and will be reclassified to our results of operations as the underlying transactions occur. A loss of $107,000 was included in Accumulated other comprehensive income at September 30, 2004 for these items. Our remaining hedges for our other products are expected to continue to be “highly effective” under SFAS No. 133 in the future.

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, 2004, approximately $3.9 million and $4.4 million of losses in Accumulated other comprehensive income will be reclassified to earnings in 2004 and 2005, respectively.

SUPPLEMENTARY CASH FLOW INFORMATION

Interest paid was $17.6 million and $16.9 million for the nine months ended September 30, 2004 and 2003, respectively. A total of $7.7 million and $6.0 million was paid in income taxes in the nine months ended September 30, 2004 and 2003, respectively.

The Total provision for income taxes, as a percentage of Income before income taxes was approximately 39.0% during the nine months ended September 30, 2004 as compared to 37.1% in same period of 2003. This increase is due to the civil penalty paid to the CFTC, which was non-deductible for tax purposes. The provision for income taxes as a percentage of Income before income taxes was approximately 36.7% during the quarter ended September 30, 2004.

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 $10.50 per share. We had options covering 27,000 and 49,438 common shares outstanding at September 30, 2004 and 2003, respectively, which were treated as repriced options. Based on our stock price at September 30, 2004 of $28.59 per share and our stock price at September 30, 2003 of $19.00 per share, compensation expense of $182,791 and $301,000, respectively, was recorded in the nine months ended September 30, 2004 and 2003.

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 nine months ended September 30, 2004 and 2003, respectively.

	Nine Months Ended September 30,
	2004	2003
1999 Plan	140,876	—
2002 Plan	920,841	1,089,900
2002 Directors’ Plan	32,000	32,000
Total options granted	1,093,717	1,121,900

The following is a summary of the weighted average fair value per share of the options granted during the nine months ended September 30, 2004 and 2003, respectively.

	Nine Months Ended September 30,
	2004		2003
1999 Plan	$	13.12	$	—
2002 Plan	$	13.09	$	9.76
2002 Directors’ Plan	$	12.13	$	10.70

During the nine months ended September 30, 2004, the values for the options granted were estimated using the Black-Scholes option-pricing model with the following assumptions:

	Nine Months Ended September 30, 2004
	1999 Plan			2002 Plan			2002 Directors’ Plan
Risk-free interest rate	3.74		%	3.76		%	4.46		%
Expected life (in years)	4			7			7
Expected volatility	39		%	39		%	40		%
Expected dividends (quarterly)	$	0.05		$	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):

	Nine Months Ended September 30,
	2004 As Reported		2004 Pro Forma		2003 As Reported		2003 Pro Forma
Net income	$	78,181	$	74,194	$	65,164	$	62,578
Net income attributable to common stock	77,346		73,359		59,730		57,144
Earnings per share of common stock	1.08		1.02		0.90		0.86
Earnings per share of common stock - assuming dilution	1.06		1.01		0.87		0.84
Stock-based employee compensation cost, net of related tax effects, included in net income	305		—		367		—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	4,292	$	—	$	2,953

SUBSEQUENT EVENTS

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 forecasts, 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 the Gas Gathering, Processing and Treating segment, collectively with the Marketing and Transportation segments referred to as the midstream operations, 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 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. Included in this segment is our Powder River coal bed methane gathering operation, which gathers gas from producers, including our Exploration and Production segment. In 2003, this service for the Exploration and Production segment was performed under a percentage-of-proceeds contract and in 2004, this service was performed under a fee-based contract. The change of contract type has no effect on the Operating profit of either the Gas Gathering, Processing and Treating segment or the Exploration and Production segment.

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 56% of our plant facilities’ gross margin, or revenues at the plant less product purchases, for the month of September 2004 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 33% of our plant facilities’ gross margin for the month of September 2004 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 11% of our plant facilities’ gross margin for the month of September 2004 was under contracts with “keepwhole” arrangements or wellhead purchase contracts. Under these 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 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, also referred to as upstream operations, 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 markets gas and NGLs extracted at our gathering, processing and treating facilities and produced from our exploration and production assets and 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. Also included in this segment are our Canadian marketing operations, which are conducted through our wholly-owned subsidiary WGR Canada, Inc. and which are immaterial for separate presentation.

Transportation. The Transportation segment reflects the operations of our MIGC, Inc. and MGTC, Inc. pipelines. The revenue presented in this segment is derived from transportation of 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 segment’s capacity contracts range in duration from one month to fourteen years.

Segment Information. The following tables set forth our segment information as of and for the quarter and nine months ended September 30, 2004 and 2003 (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 2004.

Quarter Ended September 30, 2004:

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	878		$	2,375		$	557,141		$	282		$	—		$	—		$	560,676
Sale of natural gas liquids	(559		)	—			130,057			—			—			—			129,498
Equity hedges:
Gas	(16		)	324			—			—			—			—			308
Liquids	(5,035		)	—			—			—			—			—			(5,035		)
Gathering, processing and transportation revenue	23,469			—			—			1,611			—			—			25,080
Total revenues from unaffiliated customers	18,737			2,699			687,198			1,893			—			—			710,527
Inter-segment revenues	257,310			62,547			12,601			3,560			—			(336,018		)	—
Price risk management activities	(30		)	—			7,188			—			—			—			7,158
Interest income	—			1			—			1			5,460			(5,462		)	—
Other, net	112			9			(42		)	2			489			—			570
Total revenues	276,129			65,256			706,945			5,456			5,949			(341,480		)	718,255

Product purchases	210,347			636			700,209			867			—			(326,285		)	585,774
Plant operating and transportation expense	22,976			7			4			1,848			—			(859		)	23,976
Oil and gas exploration and production expense	—			27,468			—			—			—			(8,958		)	18,510
Earnings from equity investments	(1,542		)	—			—			—			—			—			(1,542		)
Operating profit	44,348			37,145			6,732			2,741			5,949			(5,378		)	91,537

Depreciation, depletion and amortization	9,769			10,245			35			415			1,575			—			22,039
Selling and administrative expense	—			—			—			—			10,315			(10		)	10,305
(Gain) loss from sale of assets	(20		)	(218		)	—			—			8			—			(230		)
Interest expense	—			(1		)	115			(91		)	9,351			(5,462		)	3,912
Segment profit	$	34,599		$	27,119		$	6,582		$	2,417		$	(15,300	)	$	94		$	55,511

Identifiable assets:
Other allocated assets	$	6,214		$	5,059		$	61,254		$	24,598		$	385,054		$	(52,446	)	$	429,733
Equity investment	38,021			—			—			3,822			698,127			(701,949		)	38,021
Property and equipment	641,898			354,044			18			37,226			52,986			—			1,086,172
Total identifiable assets	$	686,133		$	359,103		$	61,272		$	65,646		$	1,136,167		$	(754,395	)	$	1,553,926

Quarter Ended September 30, 2003:

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	928		$	689		$	561,301		$	219		$	—		$	—		$	563,137
Sale of natural gas liquids	3			—			87,861			—			—			—			87,864
Equity hedges:
Gas	(540		)	(5,492		)	—			—			—			—			(6,032		)
Liquids	(1,854		)	—			—			—			—			—			(1,854		)
Gathering, processing and transportation revenue	20,128			—			—			1,756			—			—			21,884
Total revenues from unaffiliated customers	18,665			(4,803		)	649,162			1,975			—			—			664,999
Inter-segment revenues	268,172			54,825			8,224			3,422			—			(334,643		)	—
Price risk management activities	186			572			306			—			—			—			1,064
Interest income	(2		)	16			—			—			3,361			(3,375		)	—
Other, net	500			8			(277		)	—			506			—			737
Total revenues	287,521			50,618			657,415			5,397			3,867			(338,018		)	666,800

Product purchases	237,865			685			652,697			1,108			—			(325,418		)	566,937
Plant operating and transportation expense	20,359			100			79			2,058			—			(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	31,077			28,238			4,639			2,231			3,867			(3,382		)	66,670

Depreciation, depletion and amortization	7,485			7,393			35			413			2,151			—			17,477
Selling and administrative expense	—			—			—			—			8,986			(13		)	8,973
(Gain) loss from sale of assets	56			2			—			(5		)	3			—			56
Interest expense	—			24			93			(47		)	9,754			(3,375		)	6,449
Segment profit	$	23,536		$	20,819		$	4,511		$	1,870		$	(17,027	)	$	6		$	33,715
Identifiable assets:
Other allocated assets	$	2,834		$	7,207		$	110,219		$	34,310		$	337,285		$	(66,891	)	$	424,964
Equity investment	34,822			—			—			3,751			495,297			(499,048		)	34,822
Property and equipment	592,405			263,549			1,566			39,558			57,735			7			954,820
Total identifiable assets	$	630,061		$	270,756		$	111,785		$	77,619		$	890,317		$	(565,932	)	$	1,414,606

Nine Months Ended September 30, 2004:

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	2,767		$	6,158		$	1,808,212		$	1,147		$	—		$	—		$	1,818,284
Sale of natural gas liquids	(556		)	—			329,968			—			—			—			329,412
Equity hedges:
Gas	249			3,441			—			—			—			—			3,690
Liquids	(10,012		)	—			—			—			—			—			(10,012		)
Gathering, processing and transportation revenue	61,311			—			—			5,008			—			—			66,319
Total revenues from unaffiliated customers	53,759			9,599			2,138,180			6,155			—			—			2,207,693
Inter-segment revenues	766,734			178,903			40,202			10,705			—			(996,544		)	—
Price risk management activities	(56		)	—			5,394			—			—			—			5,338
Interest income	—			4			—			1			13,802			(13,807		)	—
Other, net	924			10			(37		)	49			1,797			—			2,743
Total revenues	821,361			188,516			2,183,739			16,910			15,599			(1,010,351		)	2,215,774

Product purchases	638,467			1,568			2,170,903			3,822			—			(969,478		)	1,845,282
Plant operating and transportation expense	65,264			77			(168		)	5,420			—			(2,428		)	68,165
Oil and gas exploration and production expense	—			80,053			—			—			—			(24,621		)	55,432
Earnings from equity investments	(5,244		)	—			—			—			—			—			(5,244		)
Operating profit	122,874			106,818			13,004			7,668			15,599			(13,824		)	252,139

Depreciation, depletion and amortization	27,981			32,111			87			1,239			5,595			—			67,013
Selling and administrative expense	—			—			—			—			37,542			(36		)	37,506
(Gain) loss from sale of assets	224			(414		)	—			—			300			1,299			1,409
Loss from early extinguishment of debt	—			—			—			—			10,662			—			10,662
Interest expense	—			41			292			(224		)	28,763			(13,807		)	15,065
Segment profit	$	94,669		$	75,080		$	12,625		$	6,653		$	(67,263	)	$	(1,280	)	$	120,484

Identifiable assets:
Other allocated assets	$	6,214		$	5,059		$	61,254		$	24,598		$	385,054		$	(52,446	)	$	429,733
Equity investment	38,021			—			—			3,822			698,127			(701,949		)	38,021
Property and equipment	641,898			354,044			18			37,226			52,986			—			1,086,172
Total identifiable assets	$	686,133		$	359,103		$	61,272		$	65,646		$	1,136,167		$	(754,395	)	$	1,553,926

Nine Months Ended September 30, 2003:

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	2,799		$	2,830		$	1,922,100		$	653		$	—		$	—		$	1,928,382
Sale of natural gas liquids	9			—			267,387			—			—			—			267,396
Equity hedges:
Gas	(2,101		)	(16,985		)	—			—			—			—			(19,086		)
Liquids	(8,555		)	—			—			—			—			—			(8,555		)
Gathering, processing and transportation revenue	57,834			—			—			5,285			—			—			63,119
Total revenues from unaffiliated customers	49,986			(14,155		)	2,189,487			5,938			—			—			2,231,256
Inter-segment revenues	832,328			171,951			26,849			10,651			—			(1,041,779		)	—
Price risk management activities	(284		)	(1,262		)	(16,504		)	—			—			—			(18,050		)
Interest income	4			29			—			2			8,678			(8,713		)	—
Other, net	1,618			21			4			42			506			—			2,191
Total revenues	883,652			156,584			2,199,836			16,633			9,184			(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	88,947			90,154			28,230			9,238			9,184			(8,830		)	216,923

Depreciation, depletion and amortization	22,603			23,421			106			1,275			5,900			—			53,305
Selling and administrative expense	—			—			—			—			29,527			(41		)	29,486
(Gain) loss from sale of assets	210			2			—			(123		)	53			—			142
Interest expense				24			134			(103		)	28,350			(8,713		)	19,692
Segment profit	$	66,134		$	66,707		$	27,990		$	8,189		$	(54,646	)	$	(76	)	$	114,298

Identifiable assets:
Other allocated assets	$	2,834		$	7,207		$	110,219		$	34,310		$	337,285		$	(66,891	)	$	424,964
Equity investment	34,822			—			—			3,751			495,297			(499,048		)	34,822
Property and equipment	592,405			263,549			1,566			39,558			57,735			7			954,820
Total identifiable assets	$	630,061		$	270,756		$	111,785		$	77,619		$	890,317		$	(565,932	)	$	1,414,606

LEGAL PROCEEDINGS

Cornerstone Propane Partners, L.P. et al. v. Western Gas Resources, Inc. et al., United States District Court, Southern District of New York, Civil Action No. 04-CV-7415. On September 17, 2004, the plaintiffs, traders of natural gas futures contracts on the New York Mercantile Exchange, or NYMEX, filed this action on behalf of themselves and a putative class of others similarly situated. In the complaint, the plaintiffs claim that we manipulated the prices of natural gas futures on the NYMEX in violation of the Commodity Exchange Act, or CEA by reporting allegedly “inaccurate, misleading and false trading information” to trade publications that compile and publish indices of natural gas spot prices. In addition, the complaint asserts that we aided and abetted the alleged CEA violations of others. The plaintiffs seek to recover actual damages on behalf of themselves and a class of natural gas futures traders, and their costs of litigation including attorney’s fees. We believe that the claims are without merit and intend to vigorously contest the allegations in this case.

United States of America and ex rel. Jack J. Grynberg v. Western Gas Resources, Inc., et al., United States District Court, District of Colorado, Civil Action No. 97-D-1427. As reported in our Form 10-Q for the quarter ended March 31, 2004 and in previous periodic reports, we, along with over 300 natural gas companies, are defendants in litigation filed on September 30, 1997, in 72 separate actions filed by Mr. Grynberg on behalf of the federal government. The allegations made by Mr. Grynberg are that established gas measurement and royalty calculation practices improperly deprived the federal government of appropriate natural gas royalties and violate 31 U. S. C. 3729 (a) (7) of the False Claims Act. The cases have been consolidated to the United States District Court for the District of Wyoming. Discovery on the jurisdictional issues is being completed to determine if this matter qualifies as a qui tam (or class) action. We

believe that Mr. Grynberg’s claims are baseless and without merit and intend to vigorously contest the allegations in this case.

Price, et al. v. Gas Pipelines, Western Gas Resources, Inc., et al., District Court, Stevens County, Kansas, Case No. 99-C-30. As reported in our Form 10-Q for the quarter ended March 31, 2004 and in previous periodic reports, Western is a defendant in litigation filed on September 23, 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 third 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.

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, results of operations or cash flow.

Retirement Plan. As reported in our Form 10-Q for the quarter ended March 31, 2004 and in previous periodic reports, we provide a Retirement Plan for our present and past employees, or participants. The purpose of the Retirement Plan is to provide a method for participants to save toward their retirement. Beginning in January 1989, participants were given the option to invest their contributions in the Western Gas Fund. The Western Gas Fund is comprised of shares of our common stock, purchased in the open market by the trustee, Fidelity Management Trust Company, and short-term investments. A participant’s ownership in the Western Gas Fund is measured in Units rather than in shares of common stock. To effectuate participant investment elections and therefore purchases and sales of Units, the trustee purchases and sells the common stock in the open market at market prices.

We are required to register the shares of our common stock purchased by the trustee of the Retirement Plan under the Securities Act. Although all the purchases by the trustee were made in the open market and in a manner consistent with the Retirement Plan and the investment elections of the participants, we have determined that approximately 934,000 shares of our common stock purchased by the trustee beginning August 14, 2001 and ending August 14, 2002 (the “Rescission Period”) may not have been properly registered in accordance with the Securities Act. These shares were purchased at an average price of $15.96 per share for total value of $14.9 million. As a result of this determination, we filed a registration statement on Form S-3 with the SEC providing for a rescission offer to certain of the plan participants as described below. This registration statement was filed in April 2004 and has not been declared effective by the SEC.

Any participant who elected to allocate a percentage of his or her funds in the Retirement Plan to purchase of Units in the Western Gas Fund at any time during the Rescission Period, and who still holds those Units during the period of the rescission offer, may direct a sale of those Units to us at the price the participant paid for the Units, plus interest. This election would be beneficial to any participant who purchased Units at a price higher than our stock price at the end of the period of the rescission offer. If a participant has already directed and caused the sale of those Units purchased during the Rescission Period at a loss, then the trustee or the participant may receive from us, the price paid for those Units less the sale proceeds, plus interest. This election would be beneficial to any participant who sold Units at a loss.

While we are unable to estimate the cost or results of the rescission offer, we do not expect the costs to have a material adverse effect on our financial position, results of operations or cash flows. We also believe that the amounts subject to the rescission offer are immaterial for separate classification as temporary equity on the Consolidated Balance Sheet at September 30, 2004 or at December 31, 2003.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS OR OTHER MATTERS.

In October 2004, the “American Jobs Creation Act of 2004” was signed into law. Among other things, this bill included modifications to tax deductions for manufacturing activities in the United States and is effective in 2005. Manufacturing activities includes oil and gas extraction and processing and, as a result, these tax deductions will apply to our operations. We have not yet determined the impact of this bill on our balance sheet, results of operations, or cash flows for 2004.

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

The following discussion and analysis relates to factors that have affected our consolidated financial condition and results of operations for the three and nine months ended September 30, 2004 and 2003. Certain prior year amounts have been reclassified to conform to the presentation used in 2004. These reclassifications had no effect on net income. You should also refer to our interim consolidated financial statements and notes thereto included elsewhere in this document. This section, as well as other sections in this Form 10-Q, contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by the use of forward-looking terminology, such as “may,” “intend,” “will,” “expect,” “anticipate,” “estimate,” or “continue” or the negative thereof or other variations thereon or comparable terminology. In addition to the important factors referred to herein, numerous factors affecting the gas processing industry generally and in the specific markets for gas and natural gas liquids, NGLs, in which we operate could cause actual results to differ materially from those in such forward-looking statements.

COMPANY OVERVIEW

Business Strategy. Maximizing the value of our existing core assets is the focal point of our business strategy. Our core assets are our fully integrated upstream and midstream assets in the Powder River and Green River Basins in Wyoming, the San Juan Basin in New Mexico, the Sand Wash Basin in Colorado and our midstream operations in west Texas and Oklahoma. Our long-term business plan is to increase stockholder value by: (i) doubling proven reserves and equity production of natural gas from the levels achieved in 2001 over a five year period; (ii) meeting or exceeding throughput projections in our midstream operations; and (iii) optimizing annual returns.

Industry and Company Overview. In North America, our industry has experienced several consecutive years of declining natural gas production. Most of the major gas producing areas, such as the Gulf of Mexico, are mature and are in production decline. We are concentrating our efforts in the Rocky Mountain gas producing basins where there are estimated to be large quantities of undeveloped gas. The U.S. government largely retains the mineral rights to these undeveloped reserves; accordingly, the development and production of these reserves require permits from several governmental agencies including the Bureau of Land Management, or BLM. We are well positioned for future production growth with a large inventory of undeveloped drilling locations in the Powder River and Greater Green River Basins to meet the growing demand for clean burning natural gas. In addition, our experience and technical expertise position us to acquire new opportunities to develop natural gas in the Rocky Mountain region. Our challenges will be to accomplish these goals with the difficulties encountered by the industry in obtaining the necessary permits from the BLM, and state agencies such as the Wyoming Department of Environmental Quality, or DEQ. We believe that our technical expertise in developing environmentally responsible solutions to the problems encountered in the development of gas reserves will be a competitive advantage in overcoming these challenges.

Our operations are conducted through the following four business segments:

Exploration and Production. We explore for, develop and produce natural gas reserves independently and to enhance and support our existing gathering and processing operations. Our producing properties are primarily located in the Powder River and Green River Basins of Wyoming, and the Sand Wash Basin in Colorado. In addition, in October 2004, we acquired properties in the San Juan Basin of New Mexico. These plays are low-risk, long-lived development projects. These provide us with the opportunity to steadily increase our production volume over time at reasonable operating and low finding and development costs. In the third quarter of 2004 our average production sold was 155 MMcfe per day, which is a 4% increase over the average production volume sold in the third quarter of 2003.

We continue to seek 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 unconventional gas reservoirs including tight-gas sands, coal bed methane, biogenic, and shale gas plays to evaluate acquisitions of either additional leaseholds, proven and undeveloped reserves or companies with operations primarily focused in the Rockies. We may also evaluate unconventional gas reservoirs in areas outside the Rockies where we can leverage our related exploration, production and gathering expertise. Through September 30, 2004, we have acquired the drilling rights on approximately 502,000 net acres, in other Rocky Mountain basins and continue to expand our leasehold positions. In addition, in July 2004, we signed a purchase and sale agreement to acquire oil and gas assets in the San Juan Basin of New Mexico for approximately $82.2 million. This acquisition closed on October 1, 2004.

Gathering, Processing and Treating. Our core operations are in well-established areas such as the Permian, Anadarko, Powder River, Greater Green River, and San Juan Basins. We connect natural gas from gas and oil wells to our gathering systems for delivery to our processing or treating plants under long-term contracts. At our plants we process natural gas to

extract NGLs and treat natural gas in order to meet pipeline specifications. We provide these services to major oil and gas companies, to independent producers of various sizes and for our own production. We believe that our low cost of operations, our high on-line time, and our safety records are key elements in our ability to compete effectively and provide service to our customers. Our expertise in gathering, processing and treating operations can enhance the economics of developing new upstream projects.

This segment of our operations has provided a stream of operating profit that is available for reinvestment into other projects or other segments of our business. Overall throughput in our facilities during the third quarter of 2004 has remained relatively constant as compared to the third quarter of 2003 and averaged a total of 1.4 Bcf per day.

Transportation. In the Powder River Basin, we own one interstate pipeline, MIGC, Inc., and one intrastate pipeline, MGTC, Inc., which transport natural gas for producers and energy marketers under fee schedules regulated by state or federal agencies.

Marketing. Our gas marketing segment is an outgrowth of our gas processing and upstream activities. One of the primary goals of our gas marketing operations is 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 NGLs and through the use of firm transportation capacity. We also buy and sell natural gas and NGLs in the wholesale market in the United States and in Canada. These third-party sales, our 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.

RESULTS OF OPERATIONS

Three and nine months ended September 30, 2004 compared to the three and nine months ended September 30, 2003

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

	Three Months Ended September 30,								Nine Months Ended September 30,
	Three Months Ended September 30,						Percent		Nine Months Ended September 30,						Percent
	2004			2003			Change		2004			2003			Change

Financial results:
Revenues	$	718,255		$	666,800		8		$	2,215,774		$	2,215,397		—
Net income	35,118			20,889			68		78,181			65,164			20
Earnings per share of common stock	0.48			0.29			66		1.08			0.90			20
Earnings per share of common stock - diluted	0.47			0.28			68		1.06			0.87			22
Net cash (used in) provided by operating activities	34,332			68,823			(50	)	149,736			210,473			(29	)
Net cash (used in) provided by investing activities	(66,561		)	(56,116		)	(18	)	(145,319		)	(132,103		)	(10	)
Net cash (used in) provided by financing activities	$	32,061		$	4,952		547		$	(27,814	)	$	(27,792	)	—

Operating data:
Average gas sales (MMcf/D)	1,130			1,285			(12	)	1,229			1,374			(11	)
Average NGL sales (MGal/D)	1,741			1,639			6		1,665			1,640			(2	)
Average gas prices ($/Mcf)	$	5.38		$	4.70		14		$	5.39		$	5.08		6
Average NGL prices ($/Gal)	$	0.78		$	0.57		37		$	0.70		$	0.58		21

Net income increased $14.2 million for the three months ended September 30, 2004 compared to the same period in 2003. The increase in net income was primarily attributable to higher product prices and slightly higher equity production of natural gas.

Net income increased $13.0 million for the nine months ended September 30, 2004 compared to the same period in 2003. This increase was primarily attributable to higher product prices. The price increases were somewhat offset by reduced operating profit from the marketing segment and after-tax charges associated with a settlement with the Commodity Futures Trading Commission, or CFTC, of $7.0 million and the early extinguishment of long-term debt of $6.7 million. Additionally, the nine months ended September 30, 2004 included a change in accounting principle that resulted in a cumulative reduction of depreciation for periods prior to 2004 of $4.7 million, net of tax, and the nine months ended

September 30, 2003 included 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 $3.9 million to $561.0 million for the three months ended September 30, 2004 compared to the same period in 2003. 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, 2004. Average gas prices realized by us increased $0.68 per Mcf to $5.38 per Mcf for the quarter ended September 30, 2004 compared to the same period in 2003. Included in the realized gas price were approximately $308,000 of gains recognized in the three months ended September 30, 2004 related to futures positions on equity gas volumes. We have entered into additional futures positions for a portion of our equity gas for the remainder of 2004 and in 2005. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average gas sales volumes decreased to 1,130 MMcf per day for the quarter ended September 30, 2004 from 1,285 MMcf per day in the same period in 2003. This decrease was the result of our reduction in third party sales volume due to the increase in product prices and related credit exposure.

Revenues from the sale of gas decreased $87.3 million to $1,822.0 million for the nine months ended September 30, 2004 compared to the same period in 2003. This decrease was primarily due to a decrease in sales volume, which more than offset an increase in product prices in the nine months ended September 30, 2004. Average gas prices realized by us increased $0.31 per Mcf to $5.39 per Mcf for the nine months ended September 30, 2004 compared to the same period in 2003. Included in the realized gas price were approximately $3.7 million of gains recognized in the nine months ended September 30, 2004 related to futures positions on equity gas volumes. Average gas sales volumes decreased to 1,229 MMcf per day for the nine months ended September 30, 2004 from 1,374 MMcf per day in the same period in 2003. This decrease was the result of our reduction in third party sales volume due to the increase in product prices and related credit exposure.

Revenues from the sale of NGLs increased $38.5 million to $124.5 million for the three months ended September 30, 2004 compared to the same period in 2003. This is primarily due to a significant increase in product prices as sales volumes were relatively constant. Average NGL prices realized by us increased $0.21 per gallon to $0.78 per gallon for the three months ended September 30, 2004 compared to the same period in 2003. Included in the realized NGL price were approximately $5.0 million of losses recognized in the three months ended September 30, 2004 related to futures positions on equity NGL volumes. We have entered into additional futures positions for a portion of our equity NGL production for the remainder of 2004 and in 2005. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average NGL sales volumes increased 102 MGal per day to 1,741 MGal per day for the three months ended September 30, 2004 compared to the same period in 2003.

Revenues from the sale of NGLs increased approximately $60.6 million to $319.4 million for the nine months ended September 30, 2004 compared to the same period in 2003. This is primarily due to a significant increase in product prices as sales volumes were relatively constant. Average NGL prices realized by us increased $0.12 per gallon to $0.70 per gallon for the nine months ended September 30, 2004 compared to the same period in 2003. Included in the realized NGL price were approximately $10.0 million of losses recognized in the nine months ended September 30, 2004 related to futures positions on equity NGL volumes. Average NGL sales volumes increased 25 MGal per day to 1,665 MGal per day for the nine months ended September 30, 2004 compared to the same period in 2003.

Product purchases increased by $18.8 million and decreased by $53.1 million for the quarter and nine months ended September 30, 2004 compared to the same periods in 2003. The increase in product purchases in the third quarter of 2004 compared to the same period in 2003 was the result of an increase in product prices. The decrease in product purchases for the nine months ended September 30, 2004 compared to the same period in 2003 was the result of the reduction in third party sales volume which more than offset an increase in product prices. Overall, combined product purchases as a percentage of sales of all products decreased to approximately 85% in the quarter and approximately 86% in the nine months ended September 30, 2004 from 88% in both of the 2003 comparable periods. The reduction in this percentage is primarily the result of a decrease in the sale of third party product.

Oil and gas exploration and production expenses increased by $5.5 million and $16.6 million, respectively, for the three and nine months ended September 30, 2004 compared to the same periods in 2003. These increases were substantially due to increased lease operating expenses, or LOE, in the Powder River Basin coal bed development. Overall, LOE averaged $0.61 per Mcf and $0.64 per Mcf for the quarter and nine months ended September 30, 2004 compared to $0.47 per Mcf and $0.43 per Mcf for the quarter and nine months ended September 30, 2003. The increases in LOE are substantially due to higher water handling charges, contract labor, and fuel and operating costs of wellhead blowers in the Powder River Basin.

Depreciation, depletion and amortization increased by $4.6 million and $13.7 million, respectively, for the three and nine months ended September 30, 2004 as compared to the same periods in 2003. These increases are the result of additional capital expenditures and depreciation and depletion on our oil and gas assets. Effective January 1, 2004, we redefined the asset groupings for the calculation of depreciation and depletion on our oil and gas properties from a well-by-well basis to a field wide basis for each of the Jonah, Pinedale and Sand Wash fields and to a grouping of all wells drilled into related coal seams for the Powder River Basin. This change resulted in an increase in Depreciation, depletion and amortization expense of $422,000 and $2.0 million in the third quarter and nine months ended September 30, 2004, respectively.

The change in the depreciation and depletion methodology is treated as a change in accounting principle. Accordingly, the Accumulated depreciation, depletion and amortization for these assets has been recalculated under the new methodology. The cumulative effect of the change in depreciation and depletion methodology is a benefit of $4.7 million, net of tax, and is presented in the Consolidated Statement of Operations under the caption Cumulative effect of changes in accounting principles, net of tax.

Selling and administrative expenses increased by $1.3 million and $8.0 million for the three and nine months ended September 30, 2004 as compared to the same period in 2003. The increase in selling and administrative expenses was the result of the July 2004 settlement with the CFTC related to reporting of price information to industry publications.

Cash Flow Information.

Cash flows from operating activities decreased by $61.2 million in the first nine months of 2004 compared to the first nine months of 2003. This decrease was primarily due to the timing of cash receipts and payables and an increase in our inventory of products held for future resale.

Cash flows used in investing activities increased by $12.8 million in the first nine months of 2004 compared to the first nine months of 2003. This increase was due to an increase in capital expenditures in 2004.

Cash flows used in financing activities remained relatively constant in the first nine months of 2004 compared to the first nine months of 2003.

Segment Information.

Gas Gathering, Processing and Treating. The Gas Gathering, Processing and Treating segment realized segment-operating profit of $122.9 million for the nine months ended September 30, 2004 as compared to $88.9 million for the same period in 2003. The increase in operating profit in this segment in the 2004 period is primarily due to higher realized prices and improved contractual terms on gas gathered in the Powder River Basin.

Exploration and Production. The Exploration and Production segment realized segment-operating profit of $106.8 million for the nine months ended September 30, 2004 compared to $90.2 million in the same period of 2003. The increase is due to an improvement in realized prices. The following table sets forth the average sales price received for our oil and gas products and production costs per Mcfe for the third quarter and nine months ended September 30, 2004 and 2003.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
Average sales price: (1)
Oil ($/Bbl), excluding the effect of hedging positions	$	35.32	$	28.73	$	35.34	$	29.48
Oil ($/Bbl), including the effect of hedging positions	35.32		28.73		35.34		29.48

Gas ($/Mcf),excluding the effect of hedging positions	4.53		4.03		4.50		4.31
Gas ($/Mcf), including the effect of hedging positions	4.55		3.63		4.59		3.86

Production and other costs:
Lease operating expense ($/Mcfe)	0.61		0.47		0.64		0.43
Production tax expense ($/Mcfe)	0.46		0.43		0.48		0.46
Gathering and transportation expense ($/Mcfe)	0.78		0.69		0.74		0.68
Other expenses ($/Mcfe)	0.03		0.02		0.02		0.03
Total costs ($/Mcfe)	$	1.88	$	1.61	$	1.88	$	1.60

(1) The prices received for NGLs are included in the price received for gas.

Marketing. The Marketing segment realized segment-operating profit of $13.0 million for the nine months ended September 30, 2004 compared to $28.2 million in the same period of 2003. The decrease in the marketing profit is primarily due to lower profitability in transactions associated with our firm transportation capacity from the Rocky Mountain region to the Mid-Continent.

Transportation. The Transportation segment realized segment-operating profit of $7.7 million for the nine months ended September 30, 2004 compared to $9.2 million in the same period of 2003. The transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin. The decrease in profit in this segment is due to lower interruptible transportation volume in the 2004 periods as more gas was transported out of the basin through other pipelines.

Recently Issued Accounting Pronouncements. We continually monitor and revise our accounting policies as new rules are issued. See Notes to Consolidated Financial Statements (Unaudited) in Item 1 of this Form 10-Q for a detailed description of recently issued accounting pronouncements.

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, hedges of equity production, sales of inventory, the volume 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 are all expected to have significant influences on our 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.

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.

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. 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, the pace at which drilling permits are received, 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.

We believe that the amounts available to be borrowed under our financing facilities, 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 use a combination of alternatives. While we believe that we would be able to secure additional financing, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing.

We utilized amounts available under the revolving credit facility together with an additional $100.0 million borrowing under the master shelf agreement, to redeem our $155.0 million, 10% senior subordinated notes in June 2004, to pay a $7.8 million prepayment penalty on this redemption, and to meet scheduled principal repayments during the first ten months of 2004 of $35.0 million under the master shelf agreement.

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.

Common Stock Split. On June 18, 2004, we completed a two-for-one split of our common stock, which was distributed in the form of a stock dividend. Shareholders of our common stock received one additional share for every share of common stock held on the record date of June 4, 2004. Upon completion of the stock split, we had approximately 73.6 million shares of common stock outstanding. After the stock split, each share of common stock outstanding or thereafter issued includes or will include one-half of a Series A Junior Participating Preferred Stock purchase right. We have restated our financial information to reflect this split for all periods presented.

Post Retirement Benefits. In July 2004, the board of directors authorized the development of an amendment to the board’s existing health care plan to provide for health care benefits for qualifying members, and their spouses, after their retirement from our board of directors. The terms of the plan have not yet been finalized and, accordingly, no accrual for the future cost of this benefit has yet been made.

Capital Investment Program. We currently anticipate capital expenditures in 2004 of approximately $352.4 million. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2004 will be fully expended. This budget may be further increased to provide for acquisitions if approved by our board of directors.

The 2004 capital budget and our capital expenditures during the nine months ended September 30, 2004 are presented in the following table (dollars in thousands).

Type of Capital Expenditure	2004 Capital Budget			Capital Expenditures During the Nine months Ended September 30, 2004
Gathering, processing, treating and pipeline assets	$	112.8	*	$	50.6	*
Exploration and production and lease acquisition activities	146.6			84.8
Acquisition of San Juan Basin oil and gas properties	82.2			4.1
Information technology and other items	3.0			2.4
Capitalized interest and overhead	7.8			4.5
Total Capital Expenditures	$	352.4		$	146.4

* Includes $14.6 million budgeted in 2004 and $7.0 million expended in the first nine months of 2004 for maintaining existing facilities.

Contractual Commitments and Obligations.

Contractual Cash Obligations. A summary of our contractual cash obligations as of September 30, 2004 is as follows (dollars in thousands):

				Payments by Period
Type of Obligation	Total Obligations			Due in 2004		Due in 2005 – 2006			Due in 2007 – 2008			Due Thereafter
Guarantee of Fort Union Project Financing	$		4,949	$	206	$		1,795	$	2,081		$		867
Operating Leases	75,758			3,636		29,005			25,502			17,615
Firm Transportation Capacity Agreements	260,280			9,305		75,224			68,259			107,492
Firm Storage Capacity Agreements	31,487			2,390		12,181			5,903			11,013
Long-term Debt	317,500			25,000		20,000			35,000			237,500
Total Contractual Cash Obligations	$	689,974		$	40,537	$	138,205		$		136,745	$	374,487

Guarantee of Fort Union Project Financing. We own a 13% equity interest in 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 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. 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, and for office, communication, transportation and 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 $44.4 million between 2007 and 2013.

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 in our marketing segment when pricing differentials between physical locations occur. These agreements are not reflected on our Consolidated Balance Sheet.

The fixed fees associated with our existing contracts for firm transportation capacity during the remainder of 2004 will average approximately $0.14 per Mcf. The associated contract periods range from one month to thirteen 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.

The fees associated with these storage contracts in the remainder of 2004 will average $0.52 per Mcf of annual capacity. The associated contract periods at September 30, 2004 have an average term of 34 months. At September 30, 2004, we held gas in our contracted storage facilities and in pipeline imbalances of approximately 19.6 Bcf at an average cost of $5.39 per Mcf compared to 14.5 Bcf at an average cost of $4.56 per Mcf at September 30, 2003. Our current positions are for storage withdrawals within the next six months. At the time we place product into storage, we contract for the sale of that product, physically or financially, and do not speculate on its future value. 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, 2004, we held NGLs in storage at various third-party facilities of 2,877 MGal, consisting primarily of propane and ethane, at an average cost of $0.32 per gallon compared to 2,687 MGal at an average cost of $0.26 per gallon at September 30, 2003. These agreements for storage capacity are not reflected on our Consolidated Balance Sheet.

Long-term Debt

Revolving Credit Facility. The revolving credit facility is a five-year, $400 million revolving credit facility maturing in June 2009. At September 30, 2004, $137.5 million was outstanding under this facility. On October 1, 2004, we drew on the credit facility to fund the acquisition of the San Juan properties. 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 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 commitment fee ranging between 0.20% and 0.375%, depending on our debt to capitalization ratio. This fee is paid on unused amounts of the commitment. At September 30, 2004, the interest rate payable on borrowings under this facility was approximately 3.0%. 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%; and maintaining a ratio of EBITDA, as defined in the credit facility, to interest over the last four quarters in excess of 3.0 to 1.0. 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 at October 31, 2004 are as indicated in the following table (dollars in thousands):

Issue Date	Amount		Interest Rate		Final Maturity	Principal Repayment Schedule
July 28, 1995	$	30,000	7.61	%	July 28, 2007	$ 10,000 on each of July 28, 2005 through 2007
January 17, 2003	25,000		6.36	%	January 17, 2008	Single payment at maturity
June 30, 2004	100,000		5.92	%	June 30, 2011	Single payment at maturity
Total	$	155,000

Our borrowings under the master shelf agreement are secured by a pledge of the capital stock of our significant subsidiaries. These subsidiaries also guaranty the borrowings under the facility. All of the borrowings under the master shelf agreement can be prepaid prior to their final maturity by paying a yield-maintenance fee. Under our master shelf agreement, we are subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55%; and maintaining a quarterly test of EBITDA, as defined in the master shelf agreement, to interest for the last four quarters in excess of 3.0 to 1.0.

EXPLORATION AND PRODUCTION

A vital aspect of our long-term business plan is to double proven reserves and equity production of natural gas from the level at December 31, 2001 over a five year period. In order to achieve this goal, we will continue to focus on the development of our leasehold positions in the Powder River CBM development and the Green River Basin. Each of our existing upstream projects is 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	Gross Acres Under Lease At September 30, 2004	Net Acres Under Lease At September 30, 2004	Gross Productive Gas Wells at September 30, 2004	Net Productive Gas Wells at September 30, 2004
Powder River Basin CBM	1,048,000	533,000	3,792	1,796
Pinedale/Jonah Basin	167,000	29,000	178	19
Sand Wash Basin	162,000	137,000	19	19
Northeast Colorado	394,000	340,000	—	—
Other	186,000	168,000	10	2

Production and Drilling Results. The following table sets forth the average net production volume of natural gas sold and the number of wells we drilled during each of the nine month periods ended September 30, 2004 and 2003 in each of our major producing areas. This information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are defined as those that produce commercial quantities of hydrocarbons whether or not they produce a reasonable rate of return.

	Nine Months Ended September 30,
	2004			2003
	Net Production Sold in MMcfe	Gross	Net	Net Production Sold in MMcfe	Gross	Net
Powder River Basin CBM	31,784			33,973
Productive wells drilled		512	246		467	224
Dry development wells drilled		0	0		0	0

Pinedale/Jonah Basin	7,210			5,502
Productive wells drilled		50	5		43	4
Dry development wells drilled		0	0		0	0

Sand Wash Basin	1,806			986
Productive wells drilled		5	5		2	2
Dry development wells drilled		0	0		0	0
Dry exploratory wells drilled		1	1		1	1

Powder River Basin Coal Bed Methane. Historically, the drilling operations in the Powder River Basin were focused on developing reserves in the Wyodak and related coals, which are located on the east side of the coal bed development. Our net production sold from the Wyodak coal averaged 94 MMcfd in the third quarter ended September 30, 2004. Overall, we believe the Wyodak coals have reached their peak production and will decline over the next several years.

The majority of future development will be concentrated on developing the Big George and related coal seams in the western and northern parts of the Powder River Basin. Our net production from the Big George coal continues to increase and averaged 65 MMcfd in October 2004 from the All Night Creek Unit, Pleasantville, SG Palo, Bullwhacker, Schoonover and Kingsbury Unit areas. In these development areas and our areas of exploration, as of August 31, 2004, we had 539 Big George wells dewatering and producing gas, 217 Big George wells dewatering and 350 Big George wells drilled and in various stages of completion and hook-up in preparation for dewatering and production. There is, however, no assurance as to the timing of the receipt of drilling and water discharge permits, the success of our drilling program, and the dewatering time as our development progresses into the western and northern parts of the Powder River Basin.

Drilling in the Powder River Basin is dependant on the receipt of various regulatory permits, including BLM drilling permits and DEQ water discharge permits. Most of our undeveloped prospects from the Big George formation are located in the Powder River drainage area. The DEQ has not finalized their required water management techniques to be used across the basin. Techniques utilized by us, and approved by the DEQ on a location-by-location basis, have included containment or treating. In order to facilitate the processing of our water discharge permit applications on the west side of the basin, and in advance of the final requirements of the DEQ, we have installed and tested various types of water treatment facilities and are treating the water produced in some areas of the basin and, with the approval of the DEQ, discharging into the Powder River. We believe future developments in the Big George coal may require water treatment facilities. These treating operations have added and will add to the cost of development and operations in these areas. We continue to evaluate several options for water treatment to identify alternative methodologies, which may be more effective and cost efficient.

The pace of our development of this play has been delayed due to the timing and receipt of drilling and water discharge permits, and we are unable to predict the timing and rate at which permits will be granted to accomplish our drilling and production targets and fully develop our leasehold in future years. As of October 31, 2004, we have received a sufficient number of drilling permits to complete our 2004 drilling program of 760 wells, and prior to year-end, we anticipate receiving the required water discharge permits for this program.

On August 10, 2004, the Tenth Circuit Court of Appeals in Denver, Colorado issued its decision in Pennaco Energy, Inc. v. United States Department of the Interior, 377 F.3d 1147 (10^th Cir. 2004). The court upheld a decision by the Interior Board of Land Appeals, or IBLA, that the Bureau of Land Management had not complied with the National Environmental Policy Act in issuing three federal oil and gas leases to Pennaco Energy, Inc. in the Powder River Basin of Wyoming for coalbed methane development. We are not a party to the case, and the IBLA and Tenth Circuit decisions do not directly address any federal oil and gas leases held by us. However, we hold approximately 70,000 net acres of federal oil and gas leases in the Powder River Basin, some of which may potentially be affected by the response to the Pennaco case. The matter is presently before the Department of the Interior, which is evaluating this decision. We cannot predict what action the Department of Interior or third parties might take in response to this matter, or how the decision may affect the pace of federal leasing or permitting and development in the Powder River Basin.

Jonah/Pinedale Fields. Our exploration and production assets in the Green River Basin of southwest Wyoming are located in the Jonah Field and Pinedale Anticline areas. During 2004, we expect to participate in the drilling of 68 gross wells, or approximately seven net wells, on the Pinedale Anticline. Due to drilling and regulatory uncertainties, which are beyond our control, there can be no assurance that we will participate in the drilling of the total planned wells during 2004. Drilling to date on the Pinedale Anticline has been allowed on one well per 40-acre tract. In the third quarter of 2004, the State of Wyoming approved the drilling of two wells per 40-acre tract on approximately half of the Pinedale Anticline. If this spacing were approved along the expanse of the Pinedale Anticline and proves successful, we would significantly increase our number of drilling locations. The timing of the drilling of these additional locations would be subject to the completion of any required regulatory and environmental reviews.

Acquisition of San Juan Basin Properties. In July 2004, we signed a purchase and sale agreement to acquire oil and gas assets in the San Juan Basin of New Mexico for approximately $82.2 million. Closing occurred on October 1, 2004. We funded this acquisition with amounts available under our revolving credit facility. The purchase includes 32,000 gross acres, or 24,000 net acres, with approximately 100 wells producing 15 MMcf per day gross, or 11 MMcf per day net, of coal bed methane. Proved reserves as of December 31, 2003 were estimated to be approximately 60 Bcfe. The purchase also includes approximately 130 miles of related gathering systems, which are currently connected to our existing San Juan River plant. Approximately 30% of the properties are subject to a preferential right to purchase by a third party. This right will expire in February 2005 if not exercised.

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. We operate a variety of gathering, processing and treating facilities, or plant operations, as presented on the Principal Gathering and Processing Facilities Table set forth below. 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, and in the San Juan Basin in New Mexico, 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.

Principal Gathering and Processing Facilities Table. The following table provides information concerning our principal gathering, processing and treating facilities at September 30, 2004.

	Year Placed in Service	Gas Gathering System Miles	Gas Throughput Capacity (MMcf/D) (2)	Average for the Nine Months Ended September 30, 2004
Facilities (1)	Year Placed in Service	Gas Gathering System Miles	Gas Throughput Capacity (MMcf/D) (2)	Gas Throughput (MMcf/D) (3)	Gas Production (MMcf/D) (4)	NGL Production (MGal/D) (4)

Texas
Gomez Treating (5)	1971	389	280	97	88	—
Midkiff/Benedum	1949	2,326	165	139	91	836
Mitchell Puckett Treating (5)	1972	126	120	48	31	1
Wyoming
Coal Bed Methane Gathering	1990	1,369	525	396	374	—
Desert Springs Gathering	1979	65	10	6	6	24
Fort Union Gas Gathering	1999	167	635	454	454	—
Granger Complex (6)(7)(8)	1987	710	285	260	207	332
Hilight Complex (6)	1969	657	124	19	14	63
Kitty/Amos Draw (6)	1969	321	17	6	4	26
Newcastle (6)	1981	146	5	3	2	22
Red Desert (6)	1979	122	42	40	29	52
Rendezvous (10)	2001	238	275	235	235	—
Reno Junction (7)	1991	—	—	—	—	129
Table Rock Gathering	1979	100	20	14	14	—
Wamsutter Gathering (11)	1979	239	50	44	40	21
Wind River Gathering	1979	111	80	51	50	—
Oklahoma
Chaney Dell/Westana	1966	3,267	175	182	158	305
New Mexico
San Juan River (5)(9)	1955	140	60	27	22	41
Utah
Four Corners Gathering	1988	104	15	2	2	11
Total		10,597	2,883	2,023	1,821	1,863

(1) Our interest in all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%); Fort Union (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 throughput capacity is as of September 30, 2004 and represents capacity in accordance with design specifications unless other constraints exist, including permitting or field compression limits.

(3) Aggregate natural gas volumes delivered into our gathering systems.

(4) 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.

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

(6) Processing facility that includes fractionation (capable of fractionating raw NGLs into end-use products).

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

(8) The Granger Complex includes the Lincoln Road facility. As of January 1, 2004, the volume information for this facility is reported with the volume information reported for Granger.

(9) Excludes the acquisition of gathering assets, which closed on October 1, 2004.

(10) The majority of the gas gathered by the Rendezvous gas gathering system is delivered to our Granger facility and is included with the volume information reported for Granger.

(11) A portion of the gas gathered by the Wamsutter gas gathering system is delivered to our Red Desert facility and is included with the volume information reported for Red Desert.

Transportation Operations. 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. 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 with third parties for capacity on MIGC range in duration from one month to five years and the fees charged averaged $0.35 per Mcf in the first nine months of 2004. 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, 2004.

	Year PlacedIn	Transportation	Average for the Nine Months Ended September 30, 2004
Transportation Facilities (1)	Service	Miles	Pipeline Capacity (MMcf/D) (2)	Gas Throughput (MMcf/D) (3)

MIGC (4)	1970	263	130	148
MGTC (5)	1963	251	18	8
Total		514	148	156

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

(2) 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 FERC.

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

Marketing Operations.

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 marketing offices in 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. 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.

NGLs. We market NGLs, including 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. 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. Further, consumers use propane for home heating, transportation and agricultural applications. Price, seasonality and the economy primarily affect the demand for NGLs.

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 with the same counterparty. 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 November 3, 2004, we had $36.7 million of margin deposits outstanding.

We continually monitor and review the credit exposure to our marketing counterparties. In recent months the prices of natural gas and NGLs, and therefore our credit exposures, have increased significantly. 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 increased the amount of credit which we make available to substantial companies which meet our credit requirements. 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 September 30, 2004, we have hedged approximately 48% of our projected fourth quarter 2004 equity natural gas volumes and approximately 46% of our projected fourth quarter 2004 equity production of crude oil, condensate, and NGLs. We have also entered into hedges for a portion of our projected 2005 equity natural gas volumes and 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. Realized gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Sale of gas or Sale of natural gas liquids when the hedged transactions occur.

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 the price of the commodity and, if applicable, 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 natural gasoline and condensate. Our hedges are tested for effectiveness at inception and on a quarterly basis thereafter. We use regression analysis based on a five-year period of time for this test.

In the first quarter of 2004, we determined in our quarterly effectiveness testing that our hedges of equity butane production which utilized crude oil puts as a surrogate are no longer effective hedges. Therefore, in the first quarter, we discontinued cash flow hedge accounting treatment on these instruments. The value of these financial instruments will remain in Accumulated other comprehensive income and will be reclassified to our results of operations as the underlying transactions occur. A loss of $107,000 was included in Accumulated other comprehensive income at September 30, 2004 for these items. Our remaining hedges for our other products are expected to continue to be “highly effective” under SFAS No. 133 in the future. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Price risk management activities. During the nine months ended September 30, 2004, we recognized a loss of $56,000 from the ineffective portions of our hedges.

Outstanding Equity Hedge Positions and the Associated Basis for 2004 and 2005. The following table details our hedge positions as of September 30, 2004. 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 $933,000 as of September 30, 2004. There is no associated cost for the natural gas hedges.

Product	Year	Quantity and Settle Price	Hedge of Basis Differential
Natural gas	2004	70,000 MMBtu per day with a minimum price of $4.00 and a maximum price ranging from $6.50 to $9.45 per MMBtu (average of $7.81 per MMBtu.)	Mid-Continent – 55,000 MMBtu per day with an average basis price of $0.27 per MMBtu. Permian – 5,000 MMBtu per day with an average basis price of $0.34 per MMBtu. Rocky Mountain – 10,000 MMBtu per day with an average basis price of $0.74 per MMBtu.

	2005	80,000 MMBtu per day with an average minimum price of $4.75 and an average maximum price of $8.88 per MMBtu.	Mid-Continent – 60,000 MMBtu per day with an average basis price of $0.42 per MMBtu. Permian – 5,000 MMBtu per day with an average basis price of $0.48 per MMBtu. Rocky Mountain – 15,000 MMBtu per day with an average basis price of $0.72 per MMBtu.

Crude, Condensate, Natural Gasoline	2004	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

	2005	50,000 Barrels per month with an average minimum price of $31.00 per barrel and an average maximum price of $48.01 per barrel.	Not Applicable

Propane	2004	90,000 Barrels per month with a minimum price of $0.42 per gallon and a maximum price of $0.56 per gallon.	Not Applicable

	2005	75,000 Barrels per month with an average minimum price of $0.52 per gallon and an average maximum price of $0.88 per gallon.	Not Applicable

Ethane	2004	50,000 Barrels per month. Floor at $0.31 per gallon.	Not Applicable

	2005	75,000 Barrels per month. Floor at $0.38 per gallon.	Not Applicable

Account balances related to hedging transactions (designated as hedges under SFAS 133) at September 30, 2004 were $2.8 million in Current assets from price risk management activities, $14.7 million in Current Liabilities from price risk management activities, $1.3 million in long-term Liabilities from price risk management activities, ($4.8) million in Deferred income taxes payable, net, and a $8.3 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Stockholders’ Equity. Based on prices as of September 30, 2004, approximately $3.9 million of losses in Accumulated other comprehensive income will be reclassified to earnings in the fourth quarter of 2004 and $4.4 million of losses in Accumulated other comprehensive income will be reclassified to earnings in 2005.

Summary of Derivative Positions. A summary of the change in our derivative position from December 31, 2003 to September 30, 2004 is as follows (dollars in thousands):

Fair value of contracts outstanding at December 31, 2003	$	6,707
Decrease in value due to change in price	(9,637)
Increase in value due to new contracts entered into during the period	3,683
Gains realized during the period from existing and new contracts	(944)
Changes in fair value attributable to changes in valuation techniques	—
Fair value of contracts outstanding at September 30, 2004	($191)

A summary of our outstanding derivative positions at September 30, 2004 is as follows (dollars in thousands):

	Fair Value of Contracts at September 30, 2004
Source of Fair Value	Total Fair Value			Maturing In 2004				Maturing In 2005-2006			Maturing In 2007-2008	Maturing Thereafter
Exchange published prices	$	(9,450	)	$		(2,872	)	$	(6,578	)	—	—
Other actively quoted prices (1)	22,285			8,606				13,679			—	—
Other valuation methods (2)	(13,026		)	(7,183			)	(5,843		)	—	—
Total fair value	$	(191	)	$	(1,449		)	$	1,258		—	—

(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, 2004, the net notional value of such contracts was approximately $44.3 million in Canadian dollars, and the fair market value of these contracts was $33.3 million in U.S. dollars.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures.

Under the direction of the Chief Executive Officer and President, ("CEO"), and the Executive Vice President and Chief Financial Officer, ("CFO"), we reviewed and evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based on such evaluation, our CEO and CFO concluded, as of the date of such evaluation, that our disclosure controls and procedures are reasonably designed to be effective for the purpose for which they are intended.

Internal Controls over Financial Reporting.

There have not been any changes in our internal control over financial reporting during the quarter ended September 30, 2004, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Reference is made to “Notes to Consolidated Financial Statements (Unaudited) – Legal Proceedings,” in Item 1 of this Form 10-Q and incorporated by reference in this Item 1.

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, Preferences and Rights of Series A Junior Participating Preferred Stock (previously filed as part of Exhibit 1 to our Form 8-A filed on March 30, 2001 and incorporated herein by reference).

3.4		Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on May 7, 2004 (previously filed as Exhibit 99.1 to our Current Report on Form 8-K filed on May 11, 2004 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, 2004, we filed or furnished the following Form 8-K reports:

• Current Report on Form 8-K filed on July 1, 2004, announcing completion of an amended credit facility and master shelf agreement.

• Current Report on Form 8-K filed on July 1, 2004, announcing settlement with the Commodity Futures Trading Commission.

• Current Report on Form 8-K filed on July 22, 2004, announcing the purchase of San Juan Basin assets.

• Current Report on Form 8-K furnished on August 5, 2004, announcing our financial results for the quarter ended June 30, 2004.

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 8, 2004	By:	/s/ PETER A. DEA
		Peter A. Dea
		Chief Executive Officer and President


Date: November 8, 2004	By:	/s/ WILLIAM J. KRYSIAK
		William J. Krysiak
		Executive Vice President - Chief Financial Officer
		(Principal Financial and Accounting Officer)

INDEX TO 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).

3.5		Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock (previously filed as part of Exhibit 1 to our Form 8-A filed on March 30, 2001 and incorporated herein by reference).

3.6		Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on May 7, 2004 (previously filed as Exhibit 99.1 to our Current Report on Form 8-K filed on May 11, 2004 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