WESTERN GAS RESOURCES INC - 10-Q Quarterly Report

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 JUNE 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 August 1, 2004, there were 73,760,311 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 - June 30, 2004 and December 31, 2003

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

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

		Consolidated Statement of Changes in Stockholders’ Equity - Three Months Ended June 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 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

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

	Item 6.	Exhibits and Reports on Form 8-K

Signatures

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Dollars in thousands, except share data)

	June 30, 2004			December 31, 2003
	(unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	2,886		$	26,116
Trade accounts receivable, net	285,556			262,509
Inventory	74,743			70,304
Assets from price risk management activities	12,884			17,149
Other	12,978			11,225
Total current assets	389,047			387,303
Property and equipment:
Gas gathering, processing and transportation	1,063,896			1,028,176
Oil and gas properties and equipment (successful efforts method)	362,443			329,555
Construction in progress	143,240			134,751
	1,569,579			1,492,482
Less: Accumulated depreciation, depletion and amortization	(529,439		)	(495,721		)
Total property and equipment, net	1,040,140			996,761
Other assets:
Gas purchase contracts (net of accumulated amortization of $39,794 and $38,937, respectively)	28,361			29,219
Assets from price risk management activities	1,309			1,466
Equity investments	36,783			39,289
Other	4,197			6,486
Total other assets	70,650			76,460
TOTAL ASSETS	$	1,499,837		$	1,460,524
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	333,432		$	303,186
Accrued expenses	38,201			42,136
Liabilities from price risk management activities	13,620			10,603
Dividends payable	3,684			3,056
Total current liabilities	388,937			358,981
Long-term debt	285,000			339,000
Liabilities from price risk management activities	1,281			1,304
Other long-term liabilities	23,749			22,057
Deferred income taxes payable, net	202,782			176,673
Total liabilities	901,749			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; 73,672,428 and 68,271,802 shares issued, respectively	7,390			6,876
Treasury stock, at cost; 50,032 common shares in treasury	(788		)	(788		)
Additional paid-in capital	383,279			381,581
Retained earnings	209,933			173,076
Accumulated other comprehensive income	(1,726		)	1,558
Total stockholders’ equity	598,088			562,509
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,499,837		$	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)

	Six Months Ended June 30,
	2004			2003
Reconciliation of net income to net cash provided by operating activities:
Net income	$	43,063		$	44,275
Add income items that do not affect cash:
Depreciation, depletion and amortization	44,974			35,828
Loss on the sale of property and equipment	1,639			86
Cumulative effect of a change in accounting principle	(4,714		)	6,724
Deferred income taxes	24,089			26,989
Non-cash change in fair value of derivatives	4,696			480
Other non-cash items, net	2,291			1,015

Adjustments to working capital to arrive at net cash provided by operating activities:
Increase in trade accounts receivable	(22,016		)	(29,987		)
Increase product inventory	(3,008		)	(16,410		)
(Increase) decrease in other current assets	(3,856		)	18,958
(Increase) decrease in other assets and liabilities, net	322			(298		)
Increase in accounts payable	30,246			62,811
Decrease in accrued expenses	(2,323		)	(8,821		)

Net cash provided by operating activities	115,403			141,650

Cash flows from investing activities:
Purchases of property and equipment	(80,651		)	(79,551		)
Proceeds from the dispositions of property and equipment	697			3,564
Distributions from equity investees	1,196			—

Net cash used in investing activities	(78,758		)	(75,987		)

Cash flows from financing activities:
Net proceeds from exercise of common stock options	3,492			2,618
Payments for the redemption of preferred stock	(1,930		)	—
Debt issue costs paid	(1,827		)	(1,829		)
Borrowings of long-term debt	100,000			25,000
Payments on long-term debt	(155,000		)	—
Payments on revolving credit facility	(809,630		)	(625,500		)
Borrowings under revolving credit facility	810,630			573,900
Dividends paid	(5,610		)	(6,933		)

Net cash used in financing activities	(59,875		)	(32,744		)
Net increase (decrease) in cash and cash equivalents	(23,230		)	32,919
Cash and cash equivalents at beginning of period	26,116			7,312
Cash and cash equivalents at end of period	$	2,886		$	40,231

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 June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Revenues:
Sale of gas	$	595,793		$	558,921		$	1,260,991		$	1,352,191
Sale of natural gas liquids	102,021			80,783			194,936			172,832
Gathering, processing and transportation revenue	24,410			21,458			41,239			41,235
Price risk management activities	3,548			(1,421		)	(1,820		)	(19,115		)
Other	531			750			2,173			1,454
Total revenues	726,303			660,491			1,497,519			1,548,597

Costs and expenses:
Product purchases	602,166			559,836			1,259,508			1,331,438
Plant and transportation operating expense	22,255			22,612			44,189			44,534
Oil and gas exploration and production expense	19,812			13,290			36,922			25,801
Depreciation, depletion and amortization	22,348			17,685			44,974			35,828
(Gain) loss on sale of assets	1,639			(195		)	1,639			86
Selling and administrative expense	17,255			9,923			27,201			20,515
Earnings from equity investments	(1,776		)	(1,867		)	(3,702		)	(3,429		)
Loss from early extinguishment of debt	10,662			—			10,662			—
Interest expense	5,351			6,429			11,153			13,243
Total costs and expenses	699,712			627,713			1,432,546			1,468,016

Income before income taxes	26,591			32,778			64,973			80,581
Provision for income taxes:
Current	(1,008		)	2,072			2,535			2,593
Deferred	13,624			9,806			24,089			26,989
Total provision for income taxes	12,616			11,878			26,624			29,582

Income before cumulative effect of change in accounting principle	13,975			20,900			38,349			50,999

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	13,975			20,900			43,063			44,275

Preferred stock requirements	(19		)	(1,811		)	(835		)	(3,623		)

Income attributable to common stock	$	13,956		$	19,089		$	42,228		$	40,652

Net income per share of common stock before cumulative effect of change in accounting principle	$	.19		$	.29		$	.53		$	.71

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

Earnings per share of common stock	$	.19		$	.29		$	.60		$	.61

Weighted average shares of common stock outstanding(1)	73,158,240			66,295,886			70,514,420			66,235,624

Income attributable to common stock – assuming dilution	$	13,975		$	20,900		$	42,228		$	44,275

Earnings per share of common stock – assuming dilution	$	.19		$	.28		$	.58		$	.59

Weighted average shares of common stock outstanding - assuming dilution	75,329,143			74,526,718			72,820,040			74,416,882

(1) Common stock outstanding reflects the effect of a stock split.

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(1)	Shares of Common Stock in Treasury(1)	$2.625 Cumulative Convertible Preferred Stock			Common Stock(1)		Treasury Stock			Additional Paid-In Capital(1)			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, six months ended June 30, 2004	—		—	—	—			—		—			—			43,063			—			43,063
Translation adjustments	—		—	—	—			—		—			—			—			(1,104		)	(1,104		)
Other comprehensive income
From equity investees	—		—	—	—			—		—			—			—			(976		)	(976		)
Reclassification adjustment for settled contracts	—		—	—	—			—		—			—			—			1,483			1,483
Changes in fair value of outstanding hedge positions	—		—	—	—			—		—			—			—			(2,500		)	(2,500		)
Reduction to estimated ineffectiveness	—		—	—	—			—		—			—			—			(16		)	(16		)
Fair value of new hedge positions	—		—	—	—			—		—			—			—			(171		)	(171		)
Change in accumulated derivative comprehensive income	—		—	—	—			—		—			—			—			(1,204		)	(1,204		)
Total comprehensive income, net of tax	—		—	—	—			—		—			—			—			—			39,779
Stock options exercised	—		275,398	—	—			14		—			3,478			—			—			3,492
Effect of re-priced options	—		—	—	—			—		—			476			—			—			476
Officer loans forgiven	—		—	—	—			—		—			—			—			—			—
Tax benefit related to stock options exercised	—		—	—	—			—		—			—			—			—			—
Dividends declared on common stock	—		—	—	—			—		—			—			(5,449		)	—			(5,449		)
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		)
Two-for-one common stock split	—		—	—	—			3,683		—			(3,683		)	—			—			—
Redemption of $2.625 cumulative convertible preferred stock	(35,596	)	—	—	(2		)	—		—			(1,918		)	32			—			(1,888		)

Balance at June 30, 2004	—		73,672,428	50,032	$	—		$	7,390	$	(788	)	$	383,279		$	209,933		$	(1,726	)	$	598,088

(1) Reflects the effect of a stock split.

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 June 30, 2004 and for the three and six-month periods ended June 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 six-months ended June 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 common stock split.

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 the redemption, 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 June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
Common Stock	$	3,684	$	1,657	$	5,449	$	3,315
Preferred Stock	19		1,811		835		3,623
Total Dividends Declared	$	3,703	$	3,468	$	6,284	$	6,938

Dividends Declared Per Share:
Common Stock	$	0.05	$	0.03	$	0.08	$	0.05
Preferred Stock	$	0.66	$	0.66	$	1.31	$	1.31

Common stock options and, up until it’s 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 common stock split.

	Quarter Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
Weighted average shares of common stock outstanding	73,158,240	66,295,886	70,942,578	66,235,624
Potential common shares from:
Common stock options	1,921,653	1,286,924	1,877,462	1,237,668
$2.625 Cumulative Convertible Preferred Stock	249,250	6,943,908	—	6,943,590
Weighted average shares of common stock outstanding - assuming dilution	75,329,143	74,526,718	72,820,040	74,416,882

The numerators and the denominators for these periods were adjusted to reflect these potential common shares and any related preferred dividends in calculating fully diluted earnings per share. Our $2.625 cumulative convertible preferred stock was antidilutive to earnings per share in the six months ended June 30, 2004 and as such are not considered potential common shares in that period.

ACCUMULATED OTHER COMPREHENSIVE INCOME

Included in Accumulated other comprehensive income at June 30, 2004 were unrealized losses of $3.5 million from the fair value of derivatives designated as cash flow hedges and unrealized gains of $1.7 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 $213,000 was included in Accumulated other comprehensive income at June 30, 2004 for these items.

Included in Accumulated other comprehensive income at June 30, 2003 were unrealized losses of $11.8 million from the fair value of derivatives designated as cash flow hedges and unrealized gains of $3.3 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 $653,000, or $0.01 per share of common stock dilution, in the second quarter of 2004 and $1.6 million, or $0.02 per share of common stock and per share of common stock - assuming, in the six months ended June 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 $162,000 higher in the second quarter of 2003 than reported on the Consolidated Statement of Operations and $399,000 lower in the six months ended June 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 second quarter ended June 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 second quarter ended June 30, 2003 would not have changed. Earnings per share of common stock in the six months ended June 30, 2003 was $0.61 per share of common stock and $0.59 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 six months ended June 30, 2003 would have been $0.70 per share of common stock and $0.67 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.

The following is a reconciliation of the asset retirement obligation for the six months ended June 30, 2004 (dollars in thousands):

Asset retirement obligation as of December 31, 2003	$	20,644
Liability accrued upon capital expenditures	688
Liability settled	(2		)
Accretion of discount expense	610
Asset retirement obligation as of June 30, 2004	$	21,940

SUBSEQUENT EVENTS

Price Reporting to Gas Trade Publications. As previously reported, in the third quarter of 2003, we learned that several employees in our marketing department furnished inaccurate information regarding natural gas transactions to energy publications, which compile and report energy index prices. We discovered the inaccuracies during a review of our marketing activities, which was being conducted in response to a subpoena issued by the Commodity Futures Trading Commission, or CFTC. These employees have identified inaccuracies associated with reporting of natural gas transactions primarily related to points in Texas. We have discontinued the practice of reporting pricing information to industry publications. In conjunction with our investigation into this matter, we have taken appropriate disciplinary actions including the release of one manager in our marketing department. In July 2004, we reached a settlement of this matter with the CFTC. In conjunction with this settlement, we paid a civil penalty of $7.0 million, and as a result our earnings per common share in the second quarter and six months ended June 30, 2004 were reduced by $0.09 and $0.10, respectively.

The Total provision for income taxes, as a percentage of Income before income taxes, was approximately 47.4% during the quarter ended June 30, 2004 as compared to 36.2% in the same period of 2003. This increase is due to the civil penalty paid to the CFTC, which was non-deductible for tax purposes.

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 been made in the financial statements for the quarter and six months ended June 30, 2004.

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 is expected to occur on October 1, 2004 and is subject to due diligence. We expect to fund this acquisition with amounts available under our revolving credit facility. In conjunction with signing the agreement, we paid a deposit of $4.1 million to be applied against the purchase price at closing.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The net loss recognized in earnings through Sale of gas and Sale of natural gas liquids during the first six months of 2004 from hedging activities was $1.6 million, and we recognized a loss from hedge ineffectiveness of $26,000. 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 $213,000 was included in Accumulated other comprehensive income at June 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 June 30, 2004, approximately $3.3 million and $200,000 of losses in Accumulated other comprehensive income will be reclassified to earnings in 2004 and 2005, respectively.

SUPPLEMENTARY CASH FLOW INFORMATION

Interest paid was $13.3 million and $13.7 million for the six months ended June 30, 2004 and 2003, respectively. A total of $7.7 million and $6.0 million was paid in income taxes in the six months ended June 30, 2004 and 2003, respectively.

STOCK COMPENSATION

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

We are required to record compensation expense (if not previously accrued) equal to the number of unexercised re-priced options multiplied by the amount by which our stock price at the end of any quarter exceeds $10.50 per share. We had options covering 28,438 and 81,500 common shares outstanding at June 30, 2004 and 2003, respectively, which were treated as repriced options. Based on our stock price at June 30, 2004 of $32.48 per share and our stock price at June 30, 2003 of $19.80 per share, expense of $288,000 and $340,000, respectively, was recorded in the six months ended June 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 quarters and six months ended June 30, 2004 and 2003, respectively.

	Quarter Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
2002 Plan	40,000	30,000	75,000	90,000
2002 Directors’ Plan	32,000	36,000	32,000	36,000
Total options granted	72,000	66,000	107,000	126,000

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

	Quarter Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
2002 Plan	$	14.89	$	11.00	$	13.20	$	9.76
2002 Directors’ Plan	$	12.13	$	10.70	$	12.13	$	10.70

These values for the options granted during the quarter and six months ended June 30, 2004 were estimated using the Black-Scholes option-pricing model with the following assumptions:

	Quarter Ended June 30, 2004						Six Months Ended June 30, 2004
	2002 Plan			2002 Directors’ Plan			2002 Plan			2002 Directors’ Plan
Risk-free interest rate	4.42		%	4.46		%	4.02		%	4.46		%
Expected life (in years)	7			7			7			7
Expected volatility	40		%	40		%	42		%	40		%
Expected dividends (quarterly)	$	0.05		$	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):

	Quarter Ended June 30,
	2004		2004		2003		2003
	As Reported		Pro Forma		As Reported		Pro Forma
Net income	$	13,975	$	12,808	$	20,900	$	20,144
Net income attributable to common stock	13,956		12,789		19,089		18,333
Earnings per share of common stock	0.19		0.17		0.29		0.28
Earnings per share of common stock - assuming dilution	0.19		0.17		0.28		0.27
Stock-based employee compensation cost, net of related tax effects, included in net income	186		—		241		—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	1,353	$	—	$	997

	Six Months Ended June 30,
	2004		2004		2003		2003
	As Reported		Pro Forma		As Reported		Pro Forma
Net income	$	43,063	$	40,754	$	44,275	$	42,755
Net income attributable to common stock	42,228		39,919		40,652		39,132
Earnings per share of common stock	0.60		0.57		0.61		0.59
Earnings per share of common stock –assuming dilution	0.58		0.55		0.59		0.57
Stock-based employee compensation cost, net of related tax effects, included in net income	300		—		334		—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	2,609	$	—	$	1,854

SEGMENT REPORTING

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

Gas Gathering, Processing and Treating. In 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 61% of our plant facilities’ gross margin, or revenues at the plant less product purchases, for the month of June 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 26% of our plant facilities’ gross margin for the month of June 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 13% of our plant facilities’ gross margin for the month of June 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 buys and sells gas and NGLs in the United States and Canada from and to a variety of customers. In this segment, revenues for sales of product are recognized at the time the gas or NGLs are delivered to the customer and are sensitive to changes in the market prices of the underlying commodities. The marketing of products purchased from third-parties typically results in low operating margins relative to the sales price. We sell our products under agreements with varying terms and conditions in order to match seasonal and other changes in demand. This segment also markets gas and NGLs produced by our gathering, processing, treating and production assets. Also included in this segment are our Canadian marketing operations, which are conducted through our wholly-owned subsidiary WGR Canada, Inc. and are immaterial for separate presentation.

Transportation. The Transportation segment reflects the operations of Western’s MIGC, Inc. and MGTC, Inc. pipelines. The majority of the revenue presented in this segment is derived from transportation of residue gas for our Marketing segment and other third parties. In this segment, we realize revenue on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from

interruptible contracts where a fee is charged based upon volumes received into the pipeline. The Transportation segment’s firm capacity contracts range in duration from four months to fourteen years.

Segment Information. The following tables set forth our segment information as of and for the quarter and six months ended June 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.

	Gas Gathering, and Processing			Exploration and Production			Marketing		Trans- portation			Corporate			Elim- inating Entries			Total
Quarter Ended June 30, 2004
Revenues from unaffiliated customers
Sale of gas	$	965		$	1,544		$	591,248	$	303		$	—		$	—		$	594,060
Sale of natural gas liquids	2			—			104,613		—			(8		)	—			104,607
Equity hedges:
Gas	116			1,617			—		—			—			—			1,733
Liquids	(2,586		)	—			—		—			—			—			(2,586		)
Gathering, processing and transportation revenue	22,754			—			—		1,654			2			—			24,410
Total revenues from unaffiliated customers	21,251			3,161			695,861		1,957			(6		)	—			722,224
Inter-segment revenues	251,766			60,425			14,796		3,711			6			(330,704		)	—
Price risk management activities	(5		)	—			3,553		—			—			—			3,548
Interest income	—			(3		)	—		—			4,333			(4,336		)	—
Other, net	471			—			7		47			6			—			531
Total revenues	273,483			63,590			714,217		5,715			4,339			(335,040		)	726,303
Product purchases	212,543			304			710,825		1,374			—			(322,880		)	602,166
Plant operating and transportation expense	21,673			(178		)	70		1,812			(484		)	(638		)	22,255
Oil and gas exploration and production expense	—			26,904			—		—			—			(7,092		)	19,812
Earnings from equity investments	(1,776		)	—			—		—			—			—			(1,776		)
Operating profit	41,043			36,559			3,322		2,529			4,823			(4,430		)	83,846

Depreciation, depletion and amortization	9,211			10,875			35		408			1,819			—			22,348
Selling and administrative expense	—			—			—		—			17,266			(11		)	17,255
(Gain) loss from sale of assets	244			(196		)	—		—			292			1,299			1,639
Loss from early extinguishment of debt	—			—			—		—			10,662			—			10,662
Interest expense	—			8			82		(71		)	9,668			(4,336		)	5,351
Income before income taxes	$	31,588		$	25,872		$	3,205	$	2,192		$	(34,884	)	$	(1,382	)	$	26,591

Identifiable assets
Other allocated assets	$	2,739		$	7,004		$	124,759	$	44,951		$	281,912		$	(38,451	)	$	422,914
Investment in others	2,469			—			—		—			697,196			(662,882		)	36,783
Capital assets	623,982			321,009			1,253		38,225			56,240			(569		)	1,040,140
Total identifiable assets	$	629,190		$	328,013		$	126,012	$	83,176		$	1,035,348		$	(701,902	)	$	1,499,837

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Elim- inating Entries			Total
Quarter Ended June 30, 2003
Revenues from unaffiliated customers
Sale of gas	$	817		$	1,221		$	562,041		$	138		$	—		$	—		$	564,216
Sale of natural gas liquids	2			—			82,589			—									82,591
Equity hedges:
Gas	(593		)	(4,702		)	—			—			—			—			(5,295		)
Liquids	(1,808		)	—			—			—			—			—			(1,808		)
Gathering, processing and transportation revenue	19,911			––			—			1,691			(144		)	—			21,458
Total revenues from unaffiliated customers	18,329			(3,481		)	644,630			1,829			(144		)	—			661,162
Inter-segment revenues	262,092			53,784			6,658			3,356			(7		)	(325,883		)	—
Price risk management activities	306			210			(1,938		)	—			—			—			(1,421		)
Interest income	6			5			—			—			2,978			(2,989		)	—
Other, net	534			(2		)	281			42			(105		)	—			750
Total revenues	281,267			50,516			649,631			5,227			2,722			(328,872		)	660,491
Product purchases	235,290			643			640,743			400			—			(317,240		)	559,836
Plant operating and transportation expense	21,664			25			80			1,881			(351		)	(687		)	22,612
Oil and gas exploration and production expense	—			21,332			—			—			—			(8,042		)	13,290
Earnings from equity investments	(1,867		)	—			—			—			—			—			(1,867		)
Operating profit	26,180			28,516			8,808			2,946			3,073			(2,903		)	66,620

Depreciation, depletion and amortization	7,583			7,608			36			429			2,029			—			17,685
Selling and administrative expense	—			—			—			—			9,936			(13		)	9,923
(Gain) loss from sale of assets	246			—			—			(118		)	(323		)	—			(195		)
Interest expense	(1		)	—			1			(32		)	9,450			(2,989		)	6,429
Income before income taxes	$	18,352		$	20,908		$	8,771		$	2,667		$	(18,019	)	$	99		$	32,778

Identifiable assets
Other allocated assets	$	—		$	3,633		$	132,235		$	1,601		$	375,185		$	(57,519	)	$	455,135
Investment in others	3,028			—			—			—			475,630			(453,086		)	25,572
Capital assets	589,299			229,250			1,602			41,536			55,777			7			917,471
Total identifiable assets	$	592,327		$	232,883		$	133,837		$	43,137		$	906,592		$	(510,598	)	$	1,398,178

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Elim- inating Entries			Total
Six Months Ended June 30, 2004
Revenues from unaffiliated customers
Sale of gas	$	1,889		$	3,783		$	1,251,072		$	865		$	—		$	—		$	1,257,609
Sale of natural gas liquids	3			—			199,911			—			—						199,914
Equity hedges:
Gas	265			3,117			—			—			—			—			3,382
Liquids	(4,978		)	—			—			—			—			—			(4,978		)
Gathering, processing and transportation revenue	37,680			—			—			3,397			162			—			41,239
Total revenues from unaffiliated customers	34,859			6,900			1,450,983			4,262			162			—			1,497,166
Inter-segment revenues	509,403			116,356			27,601			7,145			21			(660,526		)	—
Price risk management activities	(26		)	—			(1,794		)	—			—			—			(1,820		)
Interest income	—			3			—			—			8,342			(8,345		)	—
Other, net	812			1			5			47			1,308			—			2,173
Total revenues	545,048			123,260			1,476,795			11,454			9,833			(668,871		)	1,497,519
Product purchases	428,120			932			1,470,694			2,955			—			(643,193		)	1,259,508
Plant operating and transportation expense	41,837			70			(172		)	3,572			451			(1,569		)	44,189
Oil and gas exploration and production expense	—			52,585			—			—			—			(15,663		)	36,922
Earnings from equity investments	(3,702		)	—			—			—			—			—			(3,702		)
Operating profit	78,792			69,673			6,273			4,927			9,382			(8,446		)	160,602

Depreciation, depletion and amortization	18,212			21,866			52			824			4,020			—			44,974
Selling and administrative expense	—			—			—			—			27,227			(26		)	27,201
(Gain) loss from sale of assets	244			(196		)	—			—			292			1,299			1,639
Loss from early extinguishment of debt	—			—			—			—			10,662			—			10,662
Interest expense	—			42			177			(133		)	19,412			(8,345		)	11,153
Income before income taxes	$	60,337		$	47,961		$	6,044		$	4,236		$	(52,231	)	$	(1,374	)	$	64,973

Identifiable assets
Other allocated assets	$	2,739		$	7,004		$	124,759		$	44,951		$	281,912		$	(38,451	)	$	422,914
Investment in others	2,469			—			—			—			697,196			(662,882		)	36,783
Capital assets	623,982			321,009			1,253			38,225			56,240			(569		)	1,040,140
Total identifiable assets	$	629,190		$	328,013		$	126,012		$	83,176		$	1,035,348		$	(701,902	)	$	1,499,837

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Elim- inating Entries			Total
Six Months Ended June 30, 2003
Revenues from unaffiliated customers
Sale of gas	$	1,871		$	2,141		$	1,360,799		$	434		$	—		$	—		$	1,365,245
Sale of natural gas liquids	6			—			179,526			—			—			—			179,532
Equity hedges:
Gas	(1,561		)	(11,493		)	—			—			—			—			(13,054		)
Liquids	(6,700		)	—			—			—			—			—			(6,700		)
Gathering, processing and transportation revenue	37,815			—			—			3,529			(109		)	—			41,235
Total revenues from unaffiliated customers	31,431			(9,352		)	1,540,325			3,963			(109		)	—			1,566,258
Inter-segment revenues	564,128			117,126			18,625			7,229			27			(707,135		)	—
Price risk management activities	(470		)	(1,835		)	(16,810		)	—			—			—			(19,115		)
Interest income	6			13			—			2			5,317			(5,338		)	—
Other, net	1,118			13			281			42			—			—			1,454
Total revenues	596,213			105,965			1,542,421			11,236			5,235			(712,473		)	1,548,597
Product purchases	499,577			1,031			1,518,670			601			250			(688,441		)	1,331,438
Plant operating and transportation expense	41,863			126			160			3,628			—			(1,493		)	44,534
Oil and gas exploration and production expense	—			42,893			—			—			—			(17,092		)	25,801
Earnings from equity investments	(3,429		)	—			—			—			—			—			(3,429		)
Operating profit	58,202			61,915			23,591			7,007			4,985			(5,447		)	150,253

Depreciation, depletion and amortization	15,117			16,029			71			862			3,749			—			35,828
Selling and administrative expense	—			—			—			—			20,541			(26		)	20,515
(Gain) loss from sale of assets	154			—			—			(118		)	50			—			86
Interest expense	—			—			41			(56		)	18,596			(5,338		)	13,243
Income before income taxes	$	42,931		$	45,886		$	23,479		$	6,319		$	(37,951	)	$	(83	)	$	80,581

Identifiable assets
Other allocated assets	$	—		$	3,633		$	132,235		$	1,601		$	375,185		$	(57,519	)	$	455,135
Investment in others	3,028			—			—			—			475,630			(453,086		)	25,572
Capital assets	589,299			229,250			1,602			41,536			55,777			7			917,471
Total identifiable assets	$	592,327		$	232,883		$	133,837		$	43,137		$	906,592		$	(510,598	)	$	1,398,178

LEGAL PROCEEDINGS

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 a defendant in litigation filed on June 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. On October 9, 2002, the court dismissed Mr. Grynberg’s valuation claims, and his appeal against this decision was also unsuccessful. We believe that Mr. Grynberg’s remaining 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 second quarter of 2003, the plaintiff amended and refiled for certification as a class. On May 12, 2003, Mr. Price filed a further claim, Will Price et al v. Western Gas Resources, Inc. et al., District Court, Stevens County, Kansas, Case No. 03C23, relating to certain matters previously removed from the foregoing action. We believe that Mr. Price’s claims are without merit and intend to vigorously contest the allegations in this case.

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 towards 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 such participant’s funds in the Retirement Plan to the 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 June 30, 2004 or at December 31, 2003.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS.

SFAS No. 141 and SFAS No. 142. SFAS No. 141, “Business Combinations” and SFAS No. 142, “Goodwill and Intangible Assets” were issued in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS No. 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. In April 2004, the Financial Accounting Standards Board issued an amendment to SFAS Nos. 141and 142 clarifying that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified as tangible assets on the Consolidated Balance Sheet. As we have historically presented these types of assets as part of the Oil and gas properties and equipment, this amendment has no impact on our financial statements.

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 six months ended June 30, 2004 and 2003. Certain prior year amounts have been reclassified to conform to the presentation used in 2004. 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 Greater Green River Basins in Wyoming and Colorado and our midstream operations in west Texas, Oklahoma and New Mexico. 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. 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 Greater Green River Basins of Wyoming and Colorado and will also include the San Juan Basin of New Mexico after the completion of a pending acquisition. These plays are low-risk, long-lived development projects. These provide us with the opportunity to steadily increase our production volume at low operating and finding and development costs. In the second quarter of 2004 our average production sold was 148 MMcfe per day, which is comparable to the average production volume sold in the second 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 tight-gas sands, coal bed methane and fractured shale plays to evaluate acquisitions of either additional leaseholds, proven and undeveloped reserves or companies with operations focused in the Rockies. Toward this goal, through June 30, 2004, we have acquired the drilling rights on approximately 397,000 net acres, in other Rocky Mountain basins and continue to expand our leasehold positions. Additionally, 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 is expected to occur on October 1, 2004 and is subject to due diligence.

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 second quarter of 2004 has remained relatively constant as compared to the second quarter of 2003 and averaged a total of 1.3 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 six months ended June 30, 2004 compared to the three and six months ended June 30, 2003

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

	Three Months Ended June 30,							Six Months Ended June 30,
	Three Months Ended June 30,					Percent Change		Six Months Ended June 30,							Percent Change
	2004			2003		Percent Change		2004			2003				Percent Change

Financial results:
Revenues	$	726,303		$	660,491	10		$	1,497,519		$	1,548,597			(3	)
Gross profit	50,836			48,935		4		104,966			114,425				(8	)
Net income	13,975			20,900		(33	)	43,063			44,275				(3	)
Earnings per share of common stock	0.19			0.29		(35	)	0.60			0.61				(2	)
Earnings per share of common stock - diluted	0.19			0.28		(32	)	0.58			0.59				(3	)
Net cash provided by operating activities	21,698			26,495		(12	)	115,403			141,650				(19	)
Net cash used in (provided by) investing activities	(42,118		)	18,952		(122	)	(78,758		)	(75,987			)	(4	)
Net cash used in (provided by) financing activities	$	34,935		$	19,500	79		$	(59,875	)	$		(32,744	)	82

Operating data:
Average gas sales (MMcf/D)	1,190			1,247		(5	)	1,279			1,419				(10	)
Average NGL sales (MGal/D)	1,643			1,625		1		1,627			1,639				(1	)
Average gas prices ($/Mcf)	$	5.49		$	4.91	12		$	5.40		$		5.26		3
Average NGL prices ($/Gal)	$	0.68		$	0.55	24		$	0.66		$		0.58		14

Net income decreased $6.9 million and $1.2 million for the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003. The decrease in net income in the second quarter ended June 30, 2004 compared to the second quarter of 2003 was primarily attributable to after-tax charges associated with a settlement with the CFTC of $7.0 million and the early extinguishment of long-term debt of $6.7 million. These charges more than offset the benefits of higher product prices. The decrease in net income in the six months ended June 30, 2004 compared to the same period in 2003 were primarily attributable to the settlement with the CFTC, the early extinguishment of long-term debt and a $6.7 million after-tax loss from the Cumulative effect of a change in accounting principle from the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations” on January 1, 2003 which were substantially offset by higher prices and a change in accounting principle resulted in a cumulative reduction of depreciation for periods prior to 2004 of $4.7 million, net of tax.

Revenues from the sale of gas increased $36.9 million to $595.8 million for the three months ended June 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 June 30, 2004. Average gas prices realized by us increased $0.58 per Mcf to $5.49 per Mcf for the quarter ended June 30, 2004 compared to the same period in 2003. Included in the realized gas price were approximately $1.7 million of gains recognized in the three months ended June 30, 2004 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately half of our equity gas for the remainder of 2004 and to a lesser extent in 2005. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average gas sales volumes decreased to 1,190 MMcf per day for the quarter ended June 30, 2004 compared to the same period in 2003. This decrease was due to a reduction in third party sales volume resulting from the increase in product prices and related credit exposure.

Revenues from the sale of gas decreased $91.2 million to $1,261.0 million for the six months ended June 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 six months ended June 30, 2004. Average gas prices realized by us increased $0.14 per Mcf to $5.40 per Mcf for the six months ended June 30, 2004 compared to the same period in 2003. Included in the realized gas price were approximately $3.4 million of gains recognized in the six months ended June 30, 2004 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately half of our equity gas for the remainder of 2004 and to a lesser extent in 2005. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average gas sales volumes decreased to 1,279 MMcf per day for the six months ended June 30, 2004 compared to the same period in 2003. This decrease was due to a reduction in third party sales volume resulting from the increase in product prices and related credit exposure.

Revenues from the sale of NGLs increased $21.2 million to $102.0 million for the three months ended June 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 $0.13 per gallon to $0.68 per gallon for the three months ended June 30, 2004 compared to the same period in 2003. Included in the realized NGL price were approximately $2.6 million of losses recognized in the three months ended June 30, 2004 related to futures positions on equity NGL volumes. We have entered into additional futures positions for the majority of our equity NGL production for the remainder of 2004. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average NGL sales volumes increased 17 MGal per day to 1,643 MGal per day for the three months ended June 30, 2004 compared to the same period in 2003.

Revenues from the sale of NGLs increased approximately $22.1 million to $194.9 million for the six months ended June 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 $0.08 per gallon to $0.66 per gallon for the six months ended June 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 six months ended June 30, 2004 related to futures positions on equity NGL volumes. We have entered into additional futures positions for the majority of our equity NGL production for the remainder of 2004. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Average NGL sales volumes decreased 13 MGal per day to 1,627 MGal per day for the six months ended June 30, 2004 compared to the same period in 2003.

Product purchases increased by $42.3 million and decreased by $71.9 million for the quarter and six months ended June 30, 2004 compared to the same periods in 2003. The increase in product purchases in the second 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 six months ended June 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 86% in both the quarter and six months ended June 30, 2004 from 88% in both of the 2003 comparable periods. The reduction in this percentage is primarily the result of increases in product prices and a decrease in the sale of third party product.

Oil and gas exploration and production expenses increased by $6.5 million and $11.1 million, respectively, for the three and six months ended June 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 $0.66 per Mcf and $0.65 per Mcf for the quarter and six months ended June 30, 2004 and LOE in the Powder River Basin coal bed development averaged $0.78 per Mcf in both the quarter and six months ended June 30, 2004. In the Powder River Basin, these represent increases of $0.26 and $0.33 per Mcf from the same periods in 2003. The increases in LOE are substantially due to higher water handling charges, contract labor, and fuel and operating costs of wellhead blowers.

Depreciation, depletion and amortization increased by $4.7 million and $9.1 million, respectively, for the three and six months ended June 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 $653,000 and $1.6 million in the second quarter and six months ended June 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 of $4.7 million, net of tax, 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 $7.3 million and $6.7 million for the three and six months ended June 30, 2004 as compared to the same period in 2003. The increase in selling and administrative expenses was the result of a July 2004 settlement with the CTFC related to reporting of price information to industry publications. The civil penalty of $7.0 million paid in connection with this matter was accrued in the second quarter of 2004.

The Total provision for income taxes, as a percentage of Income before income taxes was approximately 47.4% during the quarter ended June 30, 2004 as compared to 36.2% in same period of 2003. This increase is due to the civil penalty paid to the CFTC, which was non-deductible for tax purposes. We expect that the provision for income taxes as a percentage of Income before income taxes will average approximately 37.0% for the remainder of 2004.

Cash Flow Information

Cash flows from operating activities decreased by $26.2 million in the first six months of 2004 compared to the first six months of 2003. This decrease was primarily due to the timing of cash receipts and payables.

Cash flows used in investing activities increased by $2.8 million in the first six months of 2004 compared to the first six months of 2003.

Cash flows used in financing activities increased by $27.1 million in the first six months of 2004 compared to the first six months of 2003. This increase was due to a reduction in our long-term debt.

Segment Information

Gas Gathering, Processing and Treating. The Gas Gathering, Processing and Treating segment realized segment-operating profit of $78.8 million for the six months ended June 30, 2004 as compared to $58.2 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 $69.7 million for the six months ended June 30, 2004 compared to $61.9 million in the same period of 2003. The increase is due 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 second quarter and six months ended June 30, 2004 and 2003.

	Three months ended June 30,				Six months ended June 30,
	2004		2003		2004		2003
Average sales price: (1)
Oil ($/Bbl)	$	33.89	$	30.91	$	33.68	$	29.86
Gas ($/Mcf) (2)	4.61		4.05		4.51		4.46

Production and other costs:
Lease operating expense ($/Mcfe)	0.66		0.45		0.65		0.41
Production tax expense ($/Mcfe)	0.48		0.42		0.50		0.48
Gathering and transportation expense ($/Mcfe)	0.73		0.65		0.72		0.68
Other expenses ($/Mcfe)	0.02		0.05		0.01		0.03
Total costs ($/Mcfe)	$	1.89	$	1.57	$	1.88	$	1.60

(1)	The average sales prices exclude the effects of hedging. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of our oil and gas hedging positions.

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

Marketing. The Marketing segment realized segment-operating profit of $6.3 million for the six months ended June 30, 2004 compared to $23.6 million in the same period of 2003. The decrease in the marketing profit is primarily due to transactions associated with our firm transportation capacity from the Rocky Mountain region to the Mid-Continent. Our firm transportation allows us to purchase gas in the Rocky Mountain region for resale in the higher priced Mid-Continent markets. In the second quarter of 2003, additional transportation capacity out of the Rocky Mountain region became operational, which reduced the price difference between the two regions. We expect that the reduced margins will continue in future periods.

Transportation. The Transportation segment realized segment-operating profit of $4.9 million for the six months ended June 30, 2004 compared to $7.0 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 the revolving credit facility, together with net cash provided by operating activities, will provide us with sufficient funds to connect new reserves, maintain our existing facilities and complete our current capital expenditure program. Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital. Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third-parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or 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 along with an additional $100.0 million borrowing under the master shelf agreement, to redeem our outstanding $155.0 million, 10% senior subordinated notes, to pay a $7.8 million prepayment penalty on this redemption, and to meet scheduled principal repayments during the first seven months of 2004 of $10.0 million under the master shelf agreement. We believe that cash provided by operating activities and amounts available under the revolving credit facility will be sufficient to meet scheduled principal repayments during the remainder of 2004 of $25.0 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 all financial information to reflect this split for all periods presented.

Sources and Uses of Funds. Our sources and uses of funds for the six months ended June 30, 2004 are summarized as follows (dollars in thousands):

Sources of funds:
Borrowings under the revolving credit facility	$	810,630
Borrowings on long-term debt	100,000
Proceeds from the dispositions of property and equipment	697
Net cash provided by operating activities	115,403
Distributions from equity investees	1,196
Proceeds from exercise of common stock options	3,492
Total sources of funds	$	1,031,418
Uses of funds:
Payments related to long-term debt (including debt issue costs)	$	966,457
Capital expenditures	80,651
Redemption of $2.625 cumulative convertible preferred stock	1,930
Preferred dividends paid	1,926
Common dividends paid	3,684
Total uses of funds	$	1,054,648

Capital Investment Program. We currently anticipate capital expenditures in 2004 of approximately $339.7 million. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2004 will not change. 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 six months ended June 30, 2004 are presented in the following table (dollars in thousands).

Type of Capital Expenditure	2004 Capital Budget			Amount Spent During the Six Months Ended June 30, 2004
Gathering, processing, treating and pipeline assets	$	104.6	*	$	30.1	*
Exploration and production and lease acquisition activities	142.1			45.1
Acquisition of San Juan Basin oil and gas properties	82.2			—
Information technology and other items	3.0			1.5
Capitalized interest and overhead	7.8			2.8
Total Capital Expenditures	$	339.7		$	79.5

* Includes $14.6 million in 2004 and $4.3 million in the first six months of 2004 for maintaining existing facilities.

Contractual Commitments and Obligations

Contractual Cash Obligations. A summary of our contractual cash obligations as of June 30, 2004, excluding the pending acquisition of San Juan oil and gas properties, 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	$	5,151	$	408	$	1,795	$	2,081	$	867
Operating Leases	78,192		7,379		30,075		25,349		15,389
Firm Transportation Capacity and Gathering Agreements	264,356		17,492		73,612		67,185		106,067
Firm Storage Capacity Agreements	33,765		4,751		12,102		5,899		11,013
Long-term Debt	285,000		35,000		20,000		35,000		195,000
Total Contractual Cash Obligations	$	666,464	$	65,030	$	137,584	$	135,514	$	328,336

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 any expansions of the gathering header and treating system have been project financed by Fort Union. This debt is amortizing on an annual basis and is scheduled to be fully paid in 2009. All participants in Fort Union have guaranteed Fort Union’s payment of the project financing on a proportional basis, resulting in our guarantee of $5.2 million of the debt of Fort Union at June 30, 2004. Our requirement to fund under this guarantee would be reduced by the value of assets held by Fort Union. This guarantee is not reflected on our Consolidated Balance Sheet.

Operating Leases. In the ordinary course of our business operations, we enter into operating leases for office space, office equipment, communication equipment and transportation equipment. In addition, we have entered into operating leases for compression equipment. Payments made on these leases are a component of operating expenses and are reflected on the Consolidated Statement of Operations and, as operating leases, are not reflected on our Consolidated Balance Sheet. These leases have terms ranging from one month to ten years with return or fair market purchase options available at various times during the lease. If we were to exercise the purchase options on all the leased equipment, these purchase options would require the capital expenditure of approximately $39.9 million between 2007 and 2012.

Firm Transportation Capacity and Gathering Agreements. Access to firm transportation is also a significant element of our business strategy. Firm transportation ensures that our equity production has access to downstream markets and allows us to capture incremental profit in our marketing segment when pricing differentials between physical locations occur. As of June 30, 2004, we had contracts for approximately 625 MMcf per day of firm transportation. This amount represents our total contracted amount on many individual pipelines. In many cases it is necessary to utilize sequential pipelines to deliver gas into a specific sales market. In total, we have the capacity to transport 172 MMcf per day of gas from the Rocky Mountain area to the Mid-Continent. This utilizes a total of approximately 376 MMcf per day of firm capacity on three separate pipelines. The total rate under these long-term contracts to transport this gas to the Mid-Continent from the southern Powder River Basin approximates $0.35 per Mcf. Our remaining firm capacity consists of 110 MMcf per day to markets within the Rocky Mountains and 140 MMcf per day contracted in various other markets throughout the country. In addition, we hold 83 MMcf per day of firm gathering capacity on the Fort Union gathering line. These agreements are not reflected on our Consolidated Balance Sheet.

The fixed fees associated with our existing contracts for firm transportation capacity during the remainder of 2004 will average approximately $0.15 per Mcf per day. The associated contract periods range from four months 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. As of June 30, 2004, we had contracts in place for approximately 18.6 Bcf of storage capacity at various third-party facilities. Of the total storage capacity under contract, approximately 8.0 Bcf is under contract to our Canadian subsidiary, WGR Canada, Inc., and Western guarantees the subsidiary’s performance under these contracts. This subsidiary is wholly owned by us and consolidated in our financial statements.

The fees associated with these contracts in the remainder of 2004 will average $0.52 per Mcf of annual capacity. The associated contract periods at June 30, 2004 have an average term of 37 months. At June 30, 2004, we held gas in our contracted storage facilities and in pipeline imbalances of approximately 14.5 Bcf at an average cost of $5.33 per Mcf compared to 12.9 Bcf at an average cost of $4.47 per Mcf at June 30, 2003. These positions are for storage withdrawals within the next nine 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 the future value of the product. These agreements for storage capacity are not reflected on our Consolidated Balance Sheet.

From time to time, we lease NGL storage space at major trading locations to facilitate the distribution of products. At June 30, 2004, we held NGLs in storage at various third-party facilities of 2,755 MGal, consisting primarily of propane and ethane, at an average cost of $0.28 per gallon compared to 2,662 MGal at an average cost of $0.25 per gallon at June 30, 2003. These agreements for storage capacity are not reflected on our Consolidated Balance Sheet.

Long-term Debt

Revolving Credit Facility. In June 2004, we amended and restated our revolving credit facility. The amended and restated facility is a five-year, $400 million revolving credit facility maturing in June 2009. At June 30, 2004, $95.0 million was outstanding under this facility. Loans made under this facility are secured by a pledge of the capital stock of our significant subsidiaries. These subsidiaries also guarantee the borrowings under the facility.

The 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 June 30, 2004, the interest rate payable on borrowings under this facility was approximately 2.6%. 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. In June 2004, we amended and restated the master shelf agreement with The Prudential Insurance Company of America. Also on June 30, 2004, we borrowed an additional $100.0 million under the master shelf agreement that matures in a single payment on June 30, 2011. The proceeds from this borrowing were used to fund a portion of the redemption of our senior subordinated notes. Amounts outstanding under the master shelf agreement with The Prudential Insurance Company of America at July 31, 2004 are as indicated in the following table (dollars in thousands):

Issue Date	Amount		Interest Rate		Final Maturity	Principal Payment Schedule
October 27, 1994	$	25,000	9.24	%	October 27, 2004	single payment at maturity
July 28, 1995	40,000		7.61	%	July 28, 2007	$10,000 on each of July 28, 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
	$	180,000

Our borrowings under the master shelf agreement are secured by a pledge of the capital stock of our significant subsidiaries, some of which have also provided a guaranty of payments we owe 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, as amended, 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. In the remainder of 2004, we will make scheduled principal payments totaling $25.0 million on this facility. We intend to fund these repayments with funds available under the revolving credit facility.

Senior Subordinated Notes. In 1999, we sold $155.0 million of senior subordinated notes in a private placement with a final maturity of 2009 due in a single payment which were subsequently exchanged for registered publicly tradable notes under the same terms and conditions. The subordinated notes bore interest at 10% per annum. We incurred approximately $5.0 million in offering commissions and expenses, which were capitalized and were being amortized over the term of the notes. We redeemed the senior subordinated notes on June 24, 2004 using amounts available under the revolving credit facility and an additional borrowing under the master shelf agreement. In connection with this redemption, we paid a prepayment penalty of $7.75 million and expensed approximately $2.9 million of unamortized offering commissions and expenses.

Covenant Compliance. We were in compliance with all covenants in our debt agreements at June 30, 2004.

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 continued development of our leasehold positions in the Powder River CBM development and the Greater 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 June 30, 2004	Net Acres Under Lease At June 30, 2004	Average Net Production Sold for the Quarter Ended June 30, 2004	Gross Productive Gas Wells at June 30, 2004	Net Productive Gas Wells at June 30, 2004
Powder River Basin CBM	1,052,000	534,000	118 Mmcfe/day	3,665	1,736
Pinedale/Jonah Basin	169,000	27,000	22 Mmcfe/day	168	18
Sand Wash Basin	174,000	144,000	7 Mmcfe/day	17	17
Northeast Colorado	394,000	340,000	—	—	—
Other	77,000	57,000	1 Mmcfe/day	10	2

Powder River Basin Coal Bed Methane. We continue to develop our Powder River Basin CBM reserves and expand the associated gathering system in northeast Wyoming. The Powder River Basin CBM area is currently one of the largest on-shore plays for the development of natural gas in the United States. Within this area, together with our co-developer, we continue to be the largest producer of natural gas. Additionally, Western is the largest gatherer of natural gas and, through our MIGC pipeline, we transport a significant volume of gas out of this basin.

The drilling operations in the Powder River Basin have been primarily 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 second quarter ended June 30, 2004. Overall, we believe the Wyodak coals have reached their peak production and will gradually decline over the next several years.

The majority of future development will be concentrated on developing the Big George and related coal seams. Our net production from the Big George coal continues to increase and in July 2004 was over 23 MMcfd from the All Night Creek Unit, Pleasantville, SG Palo, Bullwhacker and Kingsbury Unit development areas. As of July 2004, we had 474 Big George wells that are dewatering and producing gas. An additional 221Big George wells are dewatering and 245 Big George wells have been drilled and are in various stages of completion and hook-up in preparation for production.

In order to develop the majority of our undeveloped acreage in this basin, we are required to obtain federal drilling permits from the BLM. The BLM has been reviewing its permitting process in an effort to issue to industry a total of approximately 3,000 permits per year under the EIS. As of July 31, 2004, we have received 244 permits to drill on federal acreage and require an additional 181 permits to complete our 2004-drilling plan. We are unable to

predict the rate at which permits will be granted in the future or if we can receive the permits necessary to accomplish our drilling targets.

Additionally, the Wyoming Department of Environmental Quality, or DEQ, has revised some standards for surface water discharge that have allowed the issuance of most of the permits that apply to the Cheyenne and Belle Fourche drainage areas. The majority of our existing production is from wells draining into these areas. Most of our undeveloped prospects from the Big George formation are located in the Powder River drainage area. The Wyoming DEQ will and has required additional water management techniques, such as containment or treating, in these areas. We are treating the water produced in some areas of the basin. These treating operations have added 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.

Our 2004 capital budget for the Powder River Basin coal bed project is estimated at $81.1 million, of which $27.2 million was spent through June 30, 2004. We currently plan to participate in the drilling of a total of 800 gross wells in 2004. Of this total, we plan to drill 500 gross wells in the Big George coals and 300 gross wells in the Wyodak coals. Through July 31, 2004, we drilled a total of 213 gross wells in the Big George coals and 96 wells in the Wyodak coals. Due to regulatory uncertainties, which are beyond our control, we can make no assurance that we will incur this level of capital expenditure during 2004.

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. Our capital budget for 2004 in the Jonah Field and Pinedale Anticline areas provides for expenditures of approximately $37.9 million for drilling costs and production equipment, of which $7.2 million was spent in the first six months of 2004. During 2004, we currently expect to participate in the drilling of 68 gross wells, or approximately seven net wells, on the Pinedale Anticline, of which 22 gross wells, or two net wells, were drilled in the first half of this year. Drilling to date on the Pinedale Anticline has been allowed on one well per 40-acre tract. In July 2004, one operator on the Pinedale anticline received permission from the State of Wyoming to drill two wells per 40-acre tract. If this spacing were approved along the expanse of the Pinedale Anticline and proves successful, we would significantly increase our number of drilling locations and our reserve potential. Due to drilling and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure during 2004.

Sand Wash Basin. We continue to explore and develop our acreage position in the Sand Wash Basin in northwest Colorado, located in the Greater Green River Basin. Our 2004 capital budget in this area provides for expenditures of approximately $12.6 million for the drilling of eight gross and net development wells and one exploratory well. In the first six months of 2004, we spent $7.0 million primarily for the drilling of four gross and net development wells in this area, and one exploratory well, which was plugged and abandoned.

Acquisition of San Juan Basin Properties. On July 21, 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 is expected to occur on October 1, 2004 and is subject to due diligence. We expect to fund this acquisition with amounts available under our revolving credit facility. In conjunction with signing the agreement, we paid a deposit of $4.1 million to be applied against the purchase price at closing. The purchase includes 32,000 gross acres, or 24,000 net acres, with approximately 100 wells producing 13 MMcf per day gross, or 9 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.

Exploration. We are also actively seeking to add additional exploration core projects that are focused on Rocky Mountain natural gas. We will utilize our expertise in exploration and low-risk development of tight-gas sands, coal bed methane and fractured shale plays to evaluate acquisitions of either additional leaseholds, proven and undeveloped reserves or companies with operations focused in the Rockies.

Toward this goal, as of June 30, 2004, we have acquired the drilling rights in the northeastern area of the Denver-Julesburg Basin in northeast Colorado and southwest Nebraska. In the fourth quarter of 2003, we drilled two test wells in this area to further evaluate its potential. These wells are completed and have been flow tested. Overall the gas flow rates from these test wells were encouraging and we will continue to evaluate the economics of these properties. We plan to drill at least 9 test wells in this area in 2004, of which four have been drilled through July 31, 2004. These wells are not yet

completed. We are targeting the Niobrara formation at a depth of approximately 2,500 feet. The drilling and completion costs per gross well are expected to approximate $200,000.

In the fourth quarter of 2003, we also participated in two gross exploratory wells, or one net well, in the eastern Green River Basin. One of these wells is on production, and the other well is waiting on completion. If these wells are successful, additional offset locations may be proposed.

Our capital expenditure budget for 2004 in the exploration area totals $10.5 million, primarily for our participation in drilling activities, seismic surveys and leasehold acquisition. In the first six months of 2004, we spent a total of $2.8 million.

Midstream Operations

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

Gas Gathering, Processing and Treating

At June 30, 2004, we operated 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, our core assets include our plant operations located in west Texas, Oklahoma and New Mexico. We believe that our core assets have stable production rates, provide a significant operating cash flow and continue to provide us with strategic growth opportunities.

Powder River Basin. Our operations in the Powder River Basin are fully integrated with our exploration and production operations as we provide gathering services for our own production. Additionally we provide the same types of services for third-parties. Our assets in the Powder River Basin in northeast Wyoming are primarily comprised of our coal bed methane gathering system, several gas processing facilities and our 13% equity interest in Fort Union.

Our capital budget in the Powder River Basin for midstream activities provides for expenditures of approximately $31.3 million during 2004, of which $6.4 million was spent in the six months ended June 30, 2004. Due to drilling, regulatory, commodity pricing and other uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure during 2004 or that we will not be required to make additional capital commitments to continue expansion in this basin.

Green River Basin. Our gathering and processing operations in the Green River Basin of southwest Wyoming are also fully integrated with our exploration and production operations in this area. Our midstream assets in this basin are comprised of the Granger and Lincoln Road processing facilities, or collectively the Granger complex, our 50% equity interest in Rendezvous Gas Services, L.L.C., or Rendezvous, our Red Desert processing plant and our Table Rock, Wamsutter and Desert Springs gathering systems.

Our 2004 capital budget for midstream activities in this basin provides for expenditures of approximately $42.3 million, of which $11.4 million was spent in the first six months of 2004. This capital budget includes approximately $41.0 million for gathering lines and installation of compression to expand the capacity of our Granger Complex, our Wamsutter gathering system and our Red Desert processing plant, and $1.3 million for additional contributions to Rendezvous for the expansion of its systems. In the second half of 2004, we also expect to construct a 200 MMcf per day processing facility adjacent to the Granger Complex to process gas flowing on a third-party pipeline. Due to drilling, commodity pricing and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure during 2004.

West Texas. Our primary assets in west Texas are the Midkiff/Benedum gathering and processing complex and the Gomez and Mitchell Puckett treating facilities. Our capital budget in this area provides for expenditures of approximately $9.5 million during 2004, of which $3.3 million was spent in the first six months of 2004. This budget includes approximately $6.4 million for additions to the gathering systems and processing facilities and approximately $3.1 million for replacing and upgrading field and plant equipment.

Oklahoma. Our primary assets in Oklahoma are the Chaney Dell gathering and processing facility and the Westana gathering system. Our capital budget in this area provides for expenditures of approximately $14.5 million during 2004, of which $6.6 million was spent in the first six months of 2004. This budget includes approximately $11.1 million for additions to the gathering systems and plant facilities and approximately $3.4 million for replacing and upgrading field and plant equipment.

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

				Average for the Six Months Ended June 30, 2004
		Gas Gathering System Miles	Gas Throughput Capacity (MMcf/D) (2)	Average for the Six Months Ended June 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	98	89	—
Midkiff/Benedum	1949	2,286	165	141	93	850
Mitchell Puckett Treating (5)	1972	126	120	50	32	1
Wyoming
Coal Bed Methane Gathering	1990	1,368	525	395	93	—
Desert Springs Gathering	1979	65	10	6	6	23
Fort Union Gas Gathering	1999	167	635	461	461	—
Granger (6)(7)(8)	1987	559	235	202	150	320
Hilight Complex (6)	1969	657	124	18	14	60
Kitty/Amos Draw (6)	1969	321	17	6	4	25
Lincoln Road	1988	149	50	—	—	—
Newcastle (6)	1981	146	5	3	2	21
Red Desert (6)	1979	119	42	40	27	49
Rendezvous	2001	238	275	246	246	—
Reno Junction (7)	1991	—	—	—	—	130
Table Rock Gathering	1979	69	20	14	14	—
Wamsutter Gathering	1979	239	50	46	41	20
Wind River Gathering	1979	111	80	52	51	—
Oklahoma
Chaney Dell/Westana	1966	3,242	175	183	159	306
New Mexico
San Juan River (5)	1955	140	60	27	22	42
Utah
Four Corners Gathering	1988	104	15	2	1	12
Total		10,495	2,883	1,990	1,505	1,859

(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 June 30, 2004 and represents capacity in accordance with design specifications unless other constraints exist, including permitting or field compression limits.

(3) Aggregate wellhead natural gas volumes collected by a gathering system.

(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) Lincoln Road is operated on an intermittent basis to process excess gas from the Granger system. As of January 1, 2004, the volume information for this facility is reported with the volume information reported for Granger.

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 firm capacity on MIGC range in duration from one month to five years and the fees charged averaged $0.33 per Mcf in the first six 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 FERC has implemented changes over the past several years to restrict transactions between regulated pipelines and affiliated companies. In November 2003, the FERC issued a notice of rulemaking limiting the use of affiliates’ employees in the operation of regulated entities. In July 2004, we received a partial waiver from the FERC allowing us to share some employees in the operation of these entities.

The following table provides information concerning our principal transportation assets at June 30, 2004.

			Average for the Six Months June 30, 2004
Transportation Facilities (1)	Year Placed In Service	Transportation Miles	Pipeline Capacity (MMcf/D) (2)	Gas Throughput (MMcf/D) (3)
MIGC (4)	1970	263	130	149
MGTC (5)	1963	251	18	7
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. Historically, the gas produced in the Rocky Mountain region has traded at a substantial discount to the Mid-Continent and west coast areas as a result of limited pipeline capacity from the region. During the second quarter of 2003, additional pipeline capacity out of the Rocky Mountain region went into service. This pipeline expansion contributed to a reduction in the price difference between the Rocky Mountain region and Mid-Continent market center. We expect this additional pipeline capacity to continue to have an ongoing impact on the price differences between the Rocky Mountain and Mid-Continent regions.

For the six months ended June 30, 2004, our total gas sales volumes averaged 1.3 Bcf per day, of which 494 MMcf per day was produced at our plants or from our producing properties. This volume of sales is an approximate 14% decrease as compared to the same period in 2003. In general, we reduced our sales volume due to price volatility and credit concerns with many counterparties in the energy industry. The marketing of products purchased from third-parties typically results in low profit margins relative to the sales price. We sell gas under agreements with varying terms and conditions in order to match seasonal and other changes in demand.

Revenues for sales of product are recognized at the time the gas is delivered to the customer and are sensitive to changes in the market prices of the underlying commodities. Gains and losses on any accompanying financial transactions are recorded net. Additionally, for our marketing activities, we utilize mark-to-market accounting. Under mark-to-market accounting, the expected margin to be realized over the term of the transaction is recorded in

the month of origination. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods.

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. For the six months ended June 30, 2004, NGL sales averaged 1,627 MGal per day, of which 1,388 MGal per day was produced at our plants.

Consumers of NGLs are primarily the petrochemical industry, the petroleum refining industry and the retail and industrial fuel markets. As an example, the petrochemical industry uses ethane, propane, normal butane and natural gasoline as feedstocks in the production of ethylene, which is used in the production of various plastics products. Further, consumers use propane for home heating, transportation and agricultural applications. Price, seasonality and the economy primarily affect the demand for NGLs.

We sell NGLs under agreements with varying terms and conditions in order to match seasonal and other changes in demand. The marketing of products purchased from third-parties typically results in low profit margins relative to the sales price. As in the case of natural gas, we continually monitor and review the credit exposure to our NGL marketing counterparties.

Revenues for sales of NGLs are recognized at the time the NGLs are delivered to the customer and are sensitive to changes in the market prices of the underlying commodities. Gains and losses on any accompanying financial transactions are recorded net. Additionally, for our marketing activities we utilize mark-to-market accounting. As discussed above, 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.

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 June 30, 2004, we had $1.9 million of margin deposits outstanding.

We continually monitor and review the credit exposure to our marketing counterparties. In order to minimize our credit exposures, we have utilized existing netting agreements to reduce our net credit exposure, established new netting agreements with additional customers, terminated several long-term marketing obligations, negotiated accelerated payment terms with several customers, and reduced the amount of credit which we make available to various customers. Although netting agreements similar to those that we utilize have been upheld by bankruptcy courts in the past, if any of these customers with whom we have netting agreements were to file for bankruptcy, we can provide no assurance that our agreements will not be challenged or as to the outcome of any challenge.

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

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

Hedge Positions. As of June 30, 2004, we have hedged approximately 49% of our projected 2004 equity natural gas volumes and approximately 48% of our projected 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 $213,000 was included in Accumulated other comprehensive income at June 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 six months ended June 30, 2004, we recognized a loss of $26,000 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 June 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 $284,000 as of June 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	40,000 MMBtu per day with a minimum price of $4.50 and a maximum price ranging of $8.74 per MMbtu.	Mid-Continent – 40,000 MMBtu per day with an average basis price of ($0.43) 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	25,000 Barrels per month with a minimum price of $30.00 per barrel and a maximum price of $42.75 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	50,000 Barrels per month with a minimum price of $0.535 per gallon and a maximum price of $0.8175 per gallon.	Not Applicable

Ethane	2004	50,000 Barrels per month. Floor at $0.305 per gallon.	Not Applicable

Account balances related to equity and transportation hedging transactions (designated as hedges under SFAS 133) at June 30, 2004 were $2.1 million in Current assets from price risk management activities, $200,000 in Long-term assets from price risk management activities, $7.8 million in Current Liabilities from price risk management activities, ($2.0) million in Deferred income taxes payable, net, and a $3.5 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Stockholders’ Equity. Based on prices as of June 30, 2004, approximately $3.3 million of losses in Accumulated other comprehensive income will be reclassified to earnings in the remainder of 2004.

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

Fair value of contracts outstanding at December 31, 2003	$	6,707
Increase in value due to change in price	(3,891		)
Decrease in value due to new contracts entered into during the period	3,786
Gains realized during the period from existing and new contracts	(7,310		)
Changes in fair value attributable to changes in valuation techniques	—
Fair value of contracts outstanding at June 30, 2004	$	(708	)

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

	Fair Value of Contracts at June 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	$	(914	)	$	(1,659	)	$	745	—	—
Other actively quoted prices (1)	5,671			3,809			1,862		—	—
Other valuation methods (2)	(5,465		)	(5,965		)	500		—	—
Total fair value	$	(708	)	$	(3,815	)	$	3,107	—	—

(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 June 30, 2004, the net notional value of such contracts was approximately $37.5 million in Canadian dollars. As of June 30, 2004, the fair market value of these contracts is $27.5 million in U.S. dollars.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures.

Under the direction of the Chief Executive Officer and President and the Executive Vice President and Chief Financial Officer, we carried out an evaluation of 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, and believe, based upon this evaluation, that our disclosure controls and procedures are effective as of June 30, 2004.

Internal Control over Financial Reporting.

There has been no change in our internal control over financial reporting that occurred during the quarter ended June 30, 2004, that has materially affected, or is 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 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES

Period	Total Number of Shares (or Units) Purchased (a)	Average Price Paid per Share or Unit (b)		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
April 1 to 30	7,939	$	50.467	7,939	—
May 1 to 31	—	—		—	—
June 1 to 30	—	—		—	—

(a) Represents shares of our $2.625 Cumulative Convertible Preferred Stock redeemed on April 20, 2004. Holders of 792,061 shares of the preferred stock converted such shares into shares of Common Stock in lieu of being redeemed.

(b) Includes the redemption price per share of $50.00 plus accrued and unpaid dividends.

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

The following matters were voted on at our Annual Meeting of Stockholders held on May 7, 2004:

James A. Senty, Dean Phillips, Bill M. Sanderson and Walter L. Stonehocker were elected as Class Three Directors to serve until their terms expire in 2007 and until their successors have been elected. Our other directors whose terms did not expire on the date of the Annual Meeting, Joseph E. Reid, Richard B. Robinson, Ward Sauvage, Brion Wise and Peter Dea, continued in office. The results of the election were as follows.

	Votes For	Votes Withheld	Abstentions	Broker Non-votes
James A. Senty	58,298,318	5,959,128	—	—
Dean Phillips	59,872,368	5,385,078	—	—
Bill M. Sanderson	44,306,400	19,951,046	—	—
Walter L. Stonehocker	43,682,788	20,547,658	—	—

PricewaterhouseCoopers LLP appointment to serve as our independent auditors for the fiscal year ending December 31, 2003 was ratified as follows.

		Votes For		Votes Against		Abstentions		Broker Non-votes
PricewaterhouseCoopers LLP		60,065,538		133,848		58,060		—

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 April 7, 2003 (previously filed as Exhibit 3.5 to our Quarterly Report on Form 10-Q filed on May 14, 2003 and incorporated herein by reference).

10.1		Amended and Restated Credit Agreement, dated as of June 29, 2004, among Western Gas Resources, Inc., as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, BNP Paribas, JPMorgan Chase Bank, The Royal Bank of Scotland plc and Wachovia Bank, National Association, as Co-Syndication Agents, Union Bank of California, N.A., U.S. Bank National Association and Wells Fargo Bank, N.A., as Co-Documentation Agents, and the Other Lenders a Party Thereto (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on July 1, 2004 and incorporated herein by reference).

10.2		Continuing Guaranty, dated as of June 29, 2004, by MIGC, Inc., Western Gas Resources – Texas, Inc., MGTC, Inc., Mountain Gas Resources, Inc. Lance Oil & Gas Company, Inc. and Western Gas Wyoming, L.L.C. in favor of Bank of America, N.A., as Administrative Agent (previously filed as Exhibit 10.2 to our Current Report on Form 8-K filed on July 1, 2004 and incorporated herein by reference).

10.3		Amended and Restated Pledge Agreement, dated as of June 29, 2004, by Western Gas Resources, Inc., in favor of Bank of America, N.A., as Administrative Agent (previously filed as Exhibit 10.3 to our Current Report on Form 8-K filed on July 1, 2004 and incorporated herein by reference).

10.4		Amended and Restated Subsidiary Pledge Agreement, dated as of June 29, 2004, by MIGC, Inc., in favor of Bank of America, N.A., as Administrative Agent (previously filed as Exhibit 10.4 to our Current Report on Form 8-K filed on July 1, 2004 and incorporated herein by reference).

10.5		Amended and Restated Intercreditor Agreement, dated as of June 29, 2004, by and among the Banks, Bank of America, N.A., as Administrative Agent for the Banks and The Prudential Insurance Company of America, Pruco Life Insurance Company, ING Life Insurance & Annuity Company, Prudential Investment Management, Inc., Pruco Life Insurance Company of New Jersey, Gibralter Life Insurance Co., Ltd., RGA Reinsurance Company, American Bankers Life Assurance Company of Florida, Inc., Fortis Benefits Insurance Company and Connecticut General Life Insurance Company, consented to agreed by Western Gas Resources, Inc. and its subsidiaries listed therein (previously filed as Exhibit 10.5 to our Current Report on Form 8-K filed on July 1, 2004 and incorporated herein by reference).

10.6		Letter Amendment No. 2 to Third Amended and Restated Master Shelf Agreement, dated as of June 29, 2004, by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management, Inc., ING Life Insurance & Annuity Company and each Purchaser listed on the Purchaser Schedule attached

		Thereto (previously filed as Exhibit 10.6 to our Current Report on Form 8-K filed on July 1, 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 June 30, 2004, we filed or furnished the following Form 8-K reports:

• Current Report on Form 8-K filed on April 22, 2004, announcing the completion of the redemption of all remaining outstanding shares of $2.625 Cumulative Convertible Preferred Stock.

• Current Report on Form 8-K furnished May 6, 2004, announcing our financial results for the quarter ended March 31, 2004.

• Current Report on Form 8-K filed on May 11, 2004, filing amended Bylaws.

• Current Report on Form 8-K filed on May 24, 2004, announcing two-for-one split of the common stock.

• Current Report on Form 8-K filed on May 25, 2004, announcing the redemption on June 24, 2004 of all outstanding 10% Senior Subordinated Notes due 2009.

• Current Report on Form 8-K filed June 25, 2004 announcing the completion of the redemption of all outstanding 10% Senior Subordinated Notes due 2009.

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: August 9, 2004	By:	/s/ PETER A. DEA
		Peter A. Dea
		Chief Executive Officer and President


Date: August 9, 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).

3.3		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).

3.5		Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on April 7, 2003 (previously filed as Exhibit 3.5 to our Quarterly Report on Form 10-Q filed on May 14, 2003 and incorporated herein by reference).

10.7		Amended and Restated Credit Agreement, dated as of June 29, 2004, among Western Gas Resources, Inc., as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, BNP Paribas, JPMorgan Chase Bank, The Royal Bank of Scotland plc and Wachovia Bank, National Association, as Co-Syndication Agents, Union Bank of California, N.A., U.S. Bank National Association and Wells Fargo Bank, N.A., as Co-Documentation Agents, and the Other Lenders a Party Thereto (previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on July 1, 2004 and incorporated herein by reference).

10.8		Continuing Guaranty, dated as of June 29, 2004, by MIGC, Inc., Western Gas Resources – Texas, Inc., MGTC, Inc., Mountain Gas Resources, Inc. Lance Oil & Gas Company, Inc. and Western Gas Wyoming, L.L.C. in favor of Bank of America, N.A., as Administrative Agent (previously filed as Exhibit 10.2 to our Current Report on Form 8-K filed on July 1, 2004 and incorporated herein by reference).

10.9		Amended and Restated Pledge Agreement, dated as of June 29, 2004, by Western Gas Resources, Inc., in favor of Bank of America, N.A., as Administrative Agent (previously filed as Exhibit 10.3 to our Current Report on Form 8-K filed on July 1, 2004 and incorporated herein by reference).

10.10		Amended and Restated Subsidiary Pledge Agreement, dated as of June 29, 2004, by MIGC, Inc., in favor of Bank of America, N.A., as Administrative Agent (previously filed as Exhibit 10.4 to our Current Report on Form 8-K filed on July 1, 2004 and incorporated herein by reference).

10.11		Amended and Restated Intercreditor Agreement, dated as of June 29, 2004, by and among the Banks, Bank of America, N.A., as Administrative Agent for the Banks and The Prudential Insurance Company of America, Pruco Life Insurance Company, ING Life Insurance & Annuity Company, Prudential Investment Management, Inc., Pruco Life Insurance Company of New Jersey, Gibralter Life Insurance Co., Ltd., RGA Reinsurance Company, American Bankers Life Assurance Company of Florida, Inc., Fortis Benefits Insurance Company and Connecticut General Life Insurance Company, consented to agreed by Western Gas Resources, Inc. and its subsidiaries listed therein (previously filed as Exhibit 10.5 to our Current Report on Form 8-K filed on July 1, 2004 and incorporated herein by reference).

10.12		Letter Amendment No. 2 to Third Amended and Restated Master Shelf Agreement, dated as of June 29, 2004, by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management, Inc., ING Life Insurance & Annuity Company and each Purchaser listed on the Purchaser Schedule attached Thereto (previously filed as Exhibit 10.6 to our Current Report on Form 8-K filed on July 1, 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