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, 2003

OR

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

Commission file number 1-10389

WESTERN GAS RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware		84-1127613
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1099 18^th Street, Suite 1200, Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

(303) 452-5603
Registrant’s telephone number, including area code

No changes
(Former name, former address and former fiscal year, if changed since last report).

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

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

On August 1, 2003, there were 33,179,544 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, 2003 and December 31, 2002

		Consolidated Statement of Cash Flows - Six Months Ended June 30, 2003 and 2002

		Consolidated Statement of Operations - Three and Six Months Ended June 30, 2003 and 2002

		Consolidated Statement of Changes in Stockholders’ Equity - Six Months Ended June 30, 2003

		Condensed Notes to Consolidated Financial Statements

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

	Item 3.	Quantitative and Qualitative Disclosures about Market Risk

	Item 4.	Controls and Procedures

PART II - Other Information

	Item 1.	Legal Proceedings

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

	Item 6.	Exhibits and Reports on Form 8-K

Signatures

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Dollars in thousands, except share data)

	June 30, 2003			December 31, 2002
	(unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	40,231		$	7,312
Trade accounts receivable, net	283,772			253,587
Inventory	59,935			43,482
Assets held for sale	1,617			3,250
Assets from price risk management activities	17,209			34,873
Other	10,284			27,744
Total current assets	413,048			370,248

Property and equipment:
Gas gathering, processing, storage and transportation	993,663			942,147
Oil and gas properties and equipment (successful efforts method)	298,144			252,747
Construction in progress	90,224			104,033
	1,382,031			1,298,927
Less: Accumulated depreciation, depletion and amortization	(464,560		)	(432,281		)

Total property and equipment, net	917,471			866,646

Other assets:
Gas purchase contracts (net of accumulated amortization of $38,079 and $ 37,232, respectively)	30,076			30,924
Assets from price risk management activities	2,677			406
Other	34,906			33,920

Total other assets	67,659			65,250

TOTAL ASSETS	$	1,398,178		$	1,302,144

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	305,798		$	242,987
Accrued expenses	43,021			51,509
Liabilities from price risk management activities	29,530			34,811
Dividends payable	3,469			3,464
Total current liabilities	381,818			332,771

Long - term debt	333,333			359,933
Liabilities from price risk management activities	1,624			406
Other long-term liabilities	21,011			1,713
Deferred income taxes payable, net	143,095			124,253

Total liabilities	880,881			819,076

Stockholders’ equity:
Preferred Stock; 10,000,000 shares authorized: $2.625 cumulative convertible preferred stock, par value $.10; 2,760,000 issued ($138,000,000 aggregate liquidation preference)	276			276
Common stock, par value $.10; 100,000,000 shares authorized; 33,176,144 and 33,077,611 shares issued, respectively	3,339			3,329
Treasury stock, at cost; 25,016 common shares in treasury	(788		)	(788		)
Additional paid-in capital	383,334			381,066
Retained earnings	139,629			102,292
Accumulated other comprehensive income	(8,493		)	(2,812		)
Notes receivable from key employees secured by common stock	—			(295		)

Total stockholders’ equity	517,297			483,068

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,398,178		$	1,302,144

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

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Six Months Ended June 30,
	2003			2002
Reconciliation of net income to net cash provided by operating activities:
Net income	$	44,275		$	21,766
Add income items that do not affect cash:
Depreciation, depletion and amortization	35,828			35,189
Loss on the sale of property and equipment	86			82
Cumulative effect of change in accounting principle	6,724			—
Deferred income taxes	26,989			7,855
Non-cash change in fair value of derivatives	480			3,129
Other non-cash items, net	1,015			1,589

Adjustments to working capital to arrive at net cash provided by operating activities:
(Increase) in trade accounts receivable	(29,987		)	(6,812		)
(Increase) decrease in product inventory	(16,410		)	13,331
(Increase) decrease in other current assets	18,958			(473		)
(Increase) decrease in other assets and liabilities, net	(298		)	425
Increase (decrease) in accounts payable	62,811			(20,899		)
Increase (decrease) in accrued expenses	(8,821		)	12,733

Net cash provided by operating activities	141,650			67,915

Cash flows from investing activities:

Purchases of property and equipment	(79,551		)	(57,855		)
Proceeds from the dispositions of property and equipment	3,564			465
Contributions to equity investees	—			(6,583		)

Net cash used in investing activities	(75,987		)	(63,973		)

Cash flows from financing activities:

Net proceeds from exercise of common stock options	2,618			6,514
Debt issue costs paid	(1,829		)	(114		)
Borrowings on long-term debt	25,000			—
Payments on revolving credit facility	(625,500		)	(522,100		)
Borrowings under revolving credit facility	573,900			537,000
Dividends paid	(6,933		)	(7,546		)

Net cash provided by (used in) financing activities	(32,744		)	13,754

Net increase in cash and cash equivalents	32,919			17,696

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

Cash and cash equivalents at end of period	$	40,231		$	27,728

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,
	2003			2002			2003			2002
Revenues:
Sale of gas	$	554,090		$	510,198		$	1,333,829		$	1,055,787
Sale of natural gas liquids	80,510			79,866			172,559			144,674
Gathering, processing and transportation revenue	21,458			15,028			41,235			30,459
Non-cash change in fair value of derivatives	3,683			7,866			(480		)	(3,129		)
Other	750			1,170			1,454			2,253
Total revenues	660,491			614,128			1,548,597			1,230,044

Costs and expenses:
Product purchases	559,836			528,289			1,331,438			1,072,895
Plant and transportation operating expense	22,612			19,790			44,534			38,661
Oil and gas exploration and production expense	13,290			9,142			25,801			16,531
Depreciation, depletion and amortization	17,685			17,243			35,828			35,189
(Gain) loss on sale of assets	(195		)	73			86			82
Selling and administrative expense	9,923			11,887			20,515			20,578
Earnings from equity investments	(1,867		)	(802		)	(3,429		)	(1,652		)
Interest expense	6,429			6,770			13,243			13,430
Total costs and expenses	627,713			592,392			1,468,016			1,195,714

Income before income taxes	32,778			21,736			80,581			34,330
Provision for income taxes:
Current	2,072			3,951			2,593			4,709
Deferred	9,806			4,019			26,989			7,855
Total provision for income taxes	11,878			7,970			29,582			12,564

Income before cumulative effect of change in accounting principle	20,900			13,766			50,999			21,766

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

Net income	20,900			13,766			44,275			21,766

Preferred stock requirements	(1,811		)	(2,130		)	(3,623		)	(4,260		)

Income attributable to common stock	$	19,089		$	11,636		$	40,652		$	17,506

Net income per share of common stock before cumulative effect of a change in accounting principle	$	.58		$	.35		$	1.43		$	.53

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

Earnings per share of common stock	$	.58		$	.35		$	1.23		$	.53

Weighted average shares of common stock outstanding	33,147,943			32,994,543			33,117,812			32,877,312

Income attributable to common stock – assuming dilution	$	20,900		$	11,636		$	44,275		$	17,506

Earnings per share of common stock – assuming dilution	$	.56		$	.34		$	1.19		$	.52

Weighted average shares of common stock outstanding - assuming dilution	37,263,359			33,779,869			37,208,441			33,621,877

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

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(Dollars in thousands, except share amounts)

	$2.625 Cumulative Convertible Preferred Stock	Shares of Common Stock	Shares of Common Stock in Treasury	$2.625 Cumulative Convertible Preferred Stock		Common Stock		Treasury Stock			Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income Net of Tax			Notes Receivable from Key Employees			Total Stock- holders’ Equity

Balance at December 31, 2002	2,760,000	33,077,611	25,016	$	276	$	3,329	$	(788	)	$	381,066	$	102,292		$	(2,812	)	$	(295	)	$	483,068
Comprehensive income:
Net income, six months ended June 30, 2003	—	—	—	—		—		—			—		44,275			—			—			44,275
Translation adjustments	—	—	—	—		—		—			—		—			687			—			687
Reclassification adjustment for settled contracts	—	—	—	—		—		—			—		—			2,142			—			2,142
Changes in fair value of outstanding hedging positions	—	—	—	—		—		—			—		—			(9,375		)	—			(9,375		)
Reduction due to estimated ineffectiveness	—	—	—	—		—		—			—		—			—			—			—
Fair value of new hedge positions	—	—	—	—		—		—			—		—			865			—			865
Change in accumulated derivative comprehensive income	—	—	—	—		—		—			—		—			(6,368		)	—			(6,368		)

Total comprehensive income, net of tax																						38,594
Stock options exercised	—	98,533	—	—		10		—			1,740		—			—			—			1,750
Effect of re-priced stock options	—	—	—	—		—		—			528		—			—			—			528
Loans forgiven	—	—	—	—		—		—			—		—			—			295			295
Dividends declared on common stock ($.10 per common share)	—	—	—	—		—		—			—		(3,315		)	—			—			(3,315		)
Dividends declared on $2.625 cumulative convertible preferred stock	—	—	—	—		—		—			—		(3,623		)	—			—			(3,623		)

Balance at June 30, 2003	2,760,000	33,176,144	25,016	$	276	$	3,339	$	(788	)	$	383,334	$	139,629		$	(8,493	)	$	—		$	517,297

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

WESTERN GAS RESOURCES, INC.

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

GENERAL

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

The interim consolidated financial statements presented herein should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2002. The interim consolidated financial statements as of June 30, 2003 and for the three and six month periods ended June 30, 2003 and 2002 included herein are unaudited but reflect, in the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to fairly present the results for such periods. The results of operations for the three and six months ended June 30, 2003 are not necessarily indicative of the results of operations expected for the year ended December 31, 2003.

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

EARNINGS PER SHARE OF COMMON STOCK

Earnings per share of common stock are computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding. In addition, earnings per share of common stock - assuming dilution is computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding as adjusted for potential common shares. Income attributable to common stock is income less preferred stock dividends. We declared preferred stock dividends of $1.8 million and $2.1 million for the three months ended June 30, 2003 and 2002, respectively, and $3.6 million and $4.3 million, respectively, for the six month period ended June 30, 2003 and 2002. Common stock options and our $2.625 Cumulative Convertible Preferred Stock are potential common shares. The following is a reconciliation of the weighted average shares of common stock outstanding to the weighted average common shares outstanding – assuming dilution.

	Quarter Ended June 30,		Six Months Ended June 30,
	2003	2002	2003	2002
Weighted average shares of common stock outstanding	33,147,943	32,994,543	33,117,812	32,877,312
Potential common shares from:
Common stock options	643,718	785,326	618,931	744,565
$2.625 Cumulative Convertible Preferred Stock	3,471,698	—	3,471,698	—
Weighted average shares of common stock outstanding - assuming dilution	37,263,359	33,779,869	37,208,441	33,621,877

The numerators and the denominators for these periods were adjusted to reflect these potential shares and any related preferred dividends in calculating fully diluted earnings per share.

ACCUMULATED OTHER COMPREHENSIVE INCOME

Included in Accumulated other comprehensive income at 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.

Included in Accumulated other comprehensive income at June 30, 2002 were unrealized gains of $5.2 million from the fair value of derivatives designated as cash flow hedges and $2.5 million of cumulative foreign currency translation adjustments.

CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE

In June 2001, the FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 was effective for fiscal years beginning after June 15, 2002. SFAS No. 143 establishes accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. We adopted SFAS No.

143 on January 1, 2003 and recorded a $11.5 million increase to Property and Equipment, a $4.4 million increase to Accumulated depreciation, depletion and amortization, a $17.8 million increase to Other long-term liabilities and a $6.7 million non-cash, after-tax loss from the Cumulative effect of a change in accounting principle.

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

Asset retirement obligation as of January 1, 2003	$	17,801
Liability accrued upon capital expenditures	1,258
Liability settled	(42		)
Accretion of discount expense	566
Asset retirement obligation as of June 30, 2003	$	19,583

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

In connection with the adoption of SFAS No. 143, we completed a review of our operating assets and reevaluated the operating life and salvage values of the associated equipment. As a result of this evaluation, we extended the useful life of many of our operating assets and adjusted the estimated salvage value of our operating equipment. These adjustments resulted in an approximate $3.3 million and $5.8 million, respectively, or $0.06 and $0.10 per share of common stock - assuming dilution, respectively, decrease in depreciation, depletion and amortization in the three and six months ended June 30, 2003, from the expense calculated using the previous useful lives. The adjustments to the salvage value and depreciable lives of our assets are treated as a revision of an estimate and are accounted for on a prospective basis.

OTHER INFORMATION

Acquisition of Gathering Systems. Effective February 1, 2003, we acquired 18 gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million. Several of the systems located in the Powder River Basin do not integrate directly into our existing systems, and accordingly we are negotiating for the sale of these systems. These systems are classified as Assets held for sale on the Consolidated Balance Sheet at June 30, 2003. During the three and six months ended June 30, 2003, the system, included in Assets held for sale, generated a net losses of approximately ($239,000) and ($92,000), respectively, and are immaterial for separate presentation as a discontinued operation.

Corporate Offices. We relocated our corporate offices in March 2003. In April 2003, we completed the sale of the building we previously occupied for net proceeds of $2.7 million, which resulted in a loss on the sale of ($383,000).

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The net loss recognized in earnings through Sale of residue gas and Sale of natural gas liquids during the first six months of 2003 from hedging activities was $19.5 million, and we did not recognize any losses from hedge ineffectiveness. Overall, our hedges are expected to continue to be “highly effective” under SFAS No. 133 in the future. An additional $2.8 million of losses were reclassified into earnings as a result of the discontinuance of cash flow hedges. These cash flow hedges were discontinued due to the reduction of forecasted production volumes.

The gains and losses currently reflected in Accumulated other comprehensive income will be reclassified to earnings based on the actual sales of the hedged gas or NGLs. Based on prices as of June 30, 2003, approximately $12.6 million of losses in Accumulated other comprehensive income will be reclassified to earnings in 2003 and approximately $746,000 of gains in Accumulated other comprehensive income will be reclassified to earnings in 2004.

SUPPLEMENTARY CASH FLOW INFORMATION

Interest paid was $13.7 million and $14.1 million for the six months ended June 30, 2003 and 2002, respectively. A total of $6.0 million was paid in income taxes in the six months ended June 30, 2003. No income taxes were paid during the six months ended June 30, 2002.

STOCK COMPENSATION

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

We are required to record compensation expense (if not previously accrued) equal to the number of unexercised re-priced options multiplied by the amount by which our stock price at the end of any quarter exceeds $21.00 per share. We had re-priced options covering 40,750 common shares outstanding at June 30, 2003 and 63,583 common shares outstanding at June 30, 2002. Based on our stock price at June 30, 2003 of $39.60 per share and our stock price at June 30, 2002 of $37.40 per share, compensation expense of $287,000 and $11,000, respectively, was recorded in the three months ended June 30, 2003 and 2002 and $340,000 and $323,000, respectively was recorded in the six months ended June 30, 2003 and 2002.

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

	Quarter Ended June 30,		Six Months Ended June 30,
	2003	2002	2003	2002
2002 Plan	15,000	—	45,000	—
2002 Directors’ Plan	18,000	18,000	18,000	18,000
Total options granted	33,000	18,000	63,000	18,000

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, 2003 and 2002, respectively.

	Quarter Ended June 30,				Six Months Ended June 30,
	2003		2002		2003		2002
2002 Plan	$	22.00	—		$	19.52	—
2002 Directors’ Plan	$	21.39	$	22.50	$	21.39	$	22.50

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

	2002 Plan			2002 Directors’ Plan
Risk-free interest rate	2.85		%	2.59		%
Expected life (in years)	5			5
Expected volatility	53		%	54		%
Expected dividends (quarterly)	$	0.05		$	0.05

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

	Quarter Ended June 30,
	2003		2003		2002		2002
	As Reported		Pro Forma		As Reported		Pro Forma
Net income	$	20,900	$	20,144	$	13,766	$	13,062
Net income attributable to common stock	19,089		18,333		11,636		10,932
Earnings per share of common stock	0.58		0.55		0.35		0.34
Earnings per share of common stock - assuming dilution	0.56		0.54		0.34		0.33
Stock-based employee compensation cost, net of related tax effects, included in net income	$	241	$	—	$	28	$	—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	997	$	—	$	732

	Six Months Ended June 30,
	2003		2003		2002		2002
	As Reported		Pro Forma		As Reported		Pro Forma
Net income	$	44,275	$	42,755	$	21,766	$	20,460
Net income attributable to common stock	40,652		39,132		17,506		16,200
Earnings per share of common stock	1.23		1.18		0.53		0.49
Earnings per share of common stock - assuming dilution	1.19		1.15		0.52		0.48
Stock-based employee compensation cost, net of related tax effects, included in net income	$	334	$	—	$	321	$	—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	1,854	$	—	$	1,627

SEGMENT REPORTING

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

Gas Gathering, Processing and Treating. In this segment, we connect producers’ wells (including those of our Exploration and Production segment) to our gathering systems for delivery to our processing or treating plants, process the natural gas to extract NGLs and treat the natural gas in order to meet pipeline specifications. In some areas, where no processing is required, we gather and compress producers’ gas and deliver it to pipelines for further delivery to market. Except for volumes taken in kind by our producers, the Marketing segment sells the residue gas and NGLs extracted at most of our facilities. In this segment, we recognize revenue for our services at the time the service is performed.

Substantially all gas flowing through our gathering, processing and treating facilities is supplied under three types of contracts providing for the purchase, treating or processing of natural gas for periods ranging from one month to twenty years or in some cases for the life of the oil and gas lease. Approximately 81% of our plant facilities’ gross margins, or revenues at the plants less product purchases, for the month of June 2003 resulted from percentage-of-proceeds agreements in which we

are typically responsible for the marketing of the gas and NGLs. We pay producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs.

Approximately 11% of our plant facilities’ gross margins for the month of June 2003 resulted from contracts that are primarily fee-based from which we receive a set fee for each Mcf of gas gathered and/or processed. This type of contract provides us with a steady revenue stream that is not dependent on commodity prices, except to the extent that low prices may cause a producer to delay drilling.

Approximately 8% of our plant facilities’ gross margins for the month of June 2003 resulted from contracts with ‘‘keepwhole’’ arrangements or wellhead purchase contracts. We retain the NGLs recovered by the processing facility and keep the producers whole by returning to the producers at the tailgate of the plant an amount of residue gas equal on a Btu basis to the natural gas received at the plant inlet. The ‘‘keepwhole’’ component of the contracts permits us to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, we are adversely affected when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream.

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

Marketing. Our Marketing segment buys and sells gas and NGLs in the United States and Canada from and to a variety of customers. The marketing of products purchased from third-parties typically results in low operating margins relative to the sales price. 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.

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. Revenues for sales of product are recognized at the time the gas or NGLs are delivered to the customer and are sensitive to changes in the market prices of the underlying commodities. We record revenue on our physical gas and NGL marketing activities on a gross basis versus sales net of purchases basis. We believe that this presentation is required because we obtain title to all the gas and NGLs that we buy including third-party purchases, bear the risk of loss and credit exposure on these transactions and it is our intention upon entering these contracts to take physical delivery of the product. We sell our products under agreements with varying terms and conditions in order to match seasonal and other changes in demand.

Transportation. The Transportation segment reflects the operations of Western’s MIGC and MGTC pipelines. The revenue generated in this segment is primarily from transportation of residue gas for our Marketing segment and other third-parties. In this segment, we realize revenue on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline. The Transportation segments’ firm capacity contracts range in duration from one month to six years.

Segment Information. The following table sets forth our segment information as of and for the three and six months ended June 30, 2003 and 2002 (dollars in thousands). Due to our integrated operations, the use of allocations in the determination of business segment information is necessary. Inter-segment revenues are valued at prices comparable to those of unaffiliated customers.

	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	$	862		$	2,397		$	555,988	$	138		$	—		$	—		$	559,385
Sale of natural gas liquids	2			—			82,589		—									82,591
Equity hedges:
Residue	(593		)	(4,702		)	—		—			—			—			(5,295		)
Liquids	(2,081		)	—			—		—			—			—			(2,081		)
Gathering, processing and transportation revenue	19,911			—			—		1,691			(144		)	—			21,458
Total revenues from unaffiliated customers	18,101			(2,305		)	638,577		1,829			(144		)	—			656,058
Inter-segment revenues	261,915			52,608			8,010		3,356			(7		)	(325,882		)	—
Non-cash change in fair value of derivatives	254			263			3,166		—			—			—			3,683
Interest income	—			5			—		(2		)	3,090			(2,989		)	104
Other, net	(434		)	960			281		—			(161		)	—			646
Total revenues	279,836			51,531			650,034		5,183			2,778			(328,871		)	660,491
Product purchases	232,599			646			640,742		—			76			(314,227		)	559,836
Plant operating and transportation expense	21,251			110			79		2,300			(441		)	(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	27,853			29,443			9,213		2,883			3,143			(5,915		)	66,620

Depreciation, depletion and amortization	6,693			8,498			36		430			2,028			—			17,685
Selling and administrative expense	4,296			2,937			1,856		834			—			—			9,923
(Gain) loss from sale of assets	246			—			—		(118		)	(323		)	—			(195		)
Interest expense	—			—			—		—			6,429			—			6,429
Segment profit	$	16,618		$	18,008		$	7,321	$	1,737		$	(4,991	)	$	(5,915	)	$	32,778

Identifiable assets
Other allocated assets	$	—		$	3,633		$	132,235	$	1,601		$	375,185		$	(57,519	)	$	455,135
Investment in others	3,028			—			—		3,789			54,783			(36,028		)	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	$	46,926		$	485,745		$	(93,540	)	$	1,398,178

	Gathering and Processing			Exploration and Production			Marketing		Trans- portation		Corporate			Elim- inating Entries			Total
Quarter Ended June 30, 2002
Revenues from unaffiliated customers
Sale of gas	$	564		$	349		$	502,285	$	259	$	—		$	—		$	503,457
Sale of natural gas liquids	3			—			83,274		—		—			—			83,277
Equity hedges:
Residue	650			6,090			—		—		—			—			6,740
Liquids	(3,410		)	—			—		—		—			—			(3,410		)
Gathering, processing and transportation revenue	12,932			—			—		2,045		51			—			15,028
Total revenues from unaffiliated customers	10,739			6,439			585,559		2,311		51			—			605,099
Inter-segment revenues	162,582			25,782			5,866		3,728		13			(197,971		)	—
Non-cash change in fair value of derivatives	—			—			7,866		—		—			—			7,866
Interest income	—			14			10		—		2,068			(2,027		)	65
Other, net	1,344			36			—		2		(277		)	—			1,105
Total revenues	174,665			32,271			599,301		6,041		1,854			(199,998		)	614,128
Product purchases	132,850			756			585,788		—		(154		)	(190,951		)	528,289
Plant operating and transportation expense	17,168			34			79		2,834		(2		)	(323		)	19,790
Oil and gas exploration and production expense	—			15,534			—		—		—			(6,392		)	9,142
Earnings from equity investments	(802		)	—			—		—		—			—			(802		)
Operating profit	25,448			15,947			13,434		3,207		2,010			(2,332		)	57,709

Depreciation, depletion and amortization	10,363			4,784			40		425		1,631			—			17,243
Selling and administrative expense	5,254			3,333			2,425		975		—			—			11,887
(Gain)Loss from sale of assets	—			(59		)	—		—		132			—			73
Interest expense	—			—			—		—		6,770			—			6,770
Segment profit	$	9,831		$	7,989		$	10,969	$	1,807	$	(6,523	)	$	(2,332	)	$	21,736

Identifiable assets
Other allocated assets	$	1,293		$	12,491		$	111,601	$	844	$	376,995		$	(55,264	)	$	447,960
Investment in others	1,960			—			—		3,549		46,448			(37,266		)	14,691
Capital assets	542,030			203,039			1,749		42,752		42,752			—			839,493
Total identifiable assets	$	545,283		$	215,530		$	113,350	$	47,145	$	473,366		$	(92,530	)	$	1,302,144

	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	$	1,935		$	2,114		$	1,342,400	$	434		$	—		$	—		$	1,346,883
Sale of natural gas liquids	6			—			179,526		—									179,532
Equity hedges:
Residue	(1,561		)	(11,493		)	—		—			—			—			(13,054		)
Liquids	(6,973		)	—			—		—			—			—			(6,973		)
Gathering, processing and transportation revenue	37,815			—			—		3,529			(109		)	—			41,235
Total revenues from unaffiliated customers	31,222			(9,379		)	1,521,926		3,963			(109		)	—			1,547,623
Inter-segment revenues	563,684			117,152			19,041		7,231			27			(707,135		)	—
Non-cash change in fair value of derivatives	(470		)	(1,835		)	1,825		—			—			—			(480		)
Interest income	—			13			—		—			5,512			(5,338		)	187
Other, net	(3		)	989			281		—			—			—			1,267
Total revenues	594,433			106,940			1,543,073		11,194			5,430			(712,473		)	1,548,597
Product purchases	496,947			1,040			1,518,670		—			208			(685,427		)	1,331,438
Plant operating and transportation expense	41,225			288			159		4,265			90			(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	59,690			62,719			24,244		6,929			5,132			(8,461		)	150,253

Depreciation, depletion and amortization	14,588			16,558			71		863			3,748			—			35,828
Selling and administrative expense	9,031			6,178			3,910		1,395			—			—			20,515
(Gain) loss from sale of assets	154			—			—		(118		)	50			—			86
Interest expense	—			—			—		—			13,243			—			13,243
Segment profit	$	35,917		$	39,983		$	20,263	$	4,789		$	(11,909	)	$	(8,461	)	$	80,581

Identifiable assets
Other allocated assets	$	—		$	3,633		$	132,235	$	1,601		$	375,185		$	(57,519	)	$	455,135
Investment in others	3,028			—			—		3,789			54,783			(36,028		)	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	$	46,926		$	485,745		$	(93,540	)	$	1,398,178

	Gathering and Processing			Exploration and Production			Marketing			Trans- portation		Corporate			Elim- inating Entries			Total
Six Months Ended June 30, 2002
Revenues from unaffiliated customers
Sale of gas	$	879		$	601		$	1,036,668		$	780	$	—		$	—		$	1,038,928
Sale of natural gas liquids	6			—			148,720			—		—			—			148,726
Equity hedges:
Residue	2,348			14,511			—			—		—			—			16,859
Liquids	(4,052		)	—			—			—		—			—			(4,052		)
Gathering, processing and transportation revenue	26,105			—			—			4,304		50			—			30,459
Total revenues from unaffiliated customers	25,286			15,112			1,185,388			5,084		50			—			1,230,920
Inter-segment revenues	283,913			45,594			9,426			7,857		27			(346,817		)	—
Non-cash change in fair value of derivatives	—			—			(3,129		)	—		—			—			(3,129		)
Interest income	—			24			10			—		3,895			(3,827		)	102
Other, net	2,119			19			—			14		(1		)	—			2,151
Total revenues	311,318			60,749			1,191,695			12,955		3,971			(350,644		)	1,230,044
Product purchases	235,147			1,281			1,170,158			—		168			(333,859		)	1,072,895
Plant operating and transportation expense	33,593			90			132			5,449		(2		)	(601		)	38,661
Oil and gas exploration and production expense	—			28,580			—			—		—			(12,049		)	16,531
Earnings from equity investments	(1,652		)	—			—			—		—			—			(1,652		)
Operating profit	44,230			30,798			21,405			7,506		3,805			(4,135		)	103,609

Depreciation, depletion and amortization	20,959			10,105			80			860		3,185			—			35,189
Selling and administrative expense	9,095			5,597			4,198			1,687		—			—			20,578
(Gain) Loss from sale of assets	3			(59		)	—			6		132			—			82
Interest expense	—			—			—			—		13,430						13,430
Segment profit	$	14,172		$	15,156		$	17,127		$	4,953	$	(12,942	)	$	(4,135	)	$	34,330

Identifiable assets
Other allocated assets	$	1,293		$	12,491		$	111,601		$	844	$	376,995		$	(55,264	)	$	447,960
Investment in others	1,960			—			—			3,549		46,448			(37,266		)	14,691
Capital assets	542,030			203,039			1,749			42,752		42,752			—			839,493
Total identifiable assets	$	545,283		$	215,530		$	113,350		$	47,145	$	473,366		$	(92,530	)	$	1,302,144

LEGAL PROCEEDINGS

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

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

SFAS No. 141 and SFAS No. 142. In June 2001, the Financial Accounting Standards Board, or FASB issued SFAS No. 141, “Business Combinations”, and SFAS No. 142 “Goodwill and Intangible Assets.” SFAS No. 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, 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. The FASB, the Securities and Exchange Commission and others continue to discuss the appropriate application of SFAS No. 141 and No. 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves. Depending on the outcome of such discussions, these 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 may be classified separately from oil and gas properties as intangible assets on our balance sheet. In addition, the disclosures required by SFAS No. 141 and No. 142 relative to intangibles would be included in the notes to financial statements. Historically, we, like many other oil and gas companies, have included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract these reserves as part of the oil and gas properties, even after SFAS No. 141 and No. 142 became effective.

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

At June 30, 2003, we have undeveloped leaseholds of $47.6 million that would be classified on our balance sheet as “intangible undeveloped leaseholds” and developed leaseholds of approximately $18.3 million that would be classified as “intangible developed leaseholds” if we applied the interpretation currently being discussed.

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

FIN 46. In January 2003, the FASB issued Interpretation No. 46, or “FIN 46”, “Consolidation of Variable Interest Entities.” FIN 46 provides guidance on how to identify a variable interest entity, or VIE, and determine when the assets, liabilities, and results of operations of a VIE need to be included in a company’s consolidated financial statements. FIN 46 also requires additional disclosures by primary beneficiaries and other significant variable interest holders in a VIE. The provisions of FIN 46 are effective immediately for all VIEs created after January 31, 2003. For VIEs created before February 1, 2003, the provisions of FIN 46 must be adopted at the beginning of the first interim or annual reporting period beginning after June 15, 2003. We do not have an interest in any entities that would be considered VIEs, and therefore the adoption of this pronouncement did not have an impact on our earnings or financial position.

SFAS No. 149. In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003. This statement amends and clarifies financial accounting reporting for derivative instruments and for hedging activities under SFAS Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities.” We will adopt SFAS No. 149 as required by the pronouncement. We do not expect the adoption of this pronouncement to have an impact on our earings or financial position.

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

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

The following discussion and analysis relates to factors which have affected our consolidated financial condition and results of operations for the three and six months ended June 30, 2003 and 2002. Prior year amounts have been reclassified as appropriate to conform to the presentation used in 2003. You should also refer to our interim consolidated financial statements and notes included in “Part 1 –Financial Information –Item 1. Financial Statements” of this report. This section, as well as other sections in this Quarterly Report on Form 10-Q, contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by the use of forward-looking terminology, such as “may,” “intend,” “will,” “expect,” “anticipate,” “estimate,” or “continue” or the negative thereof or other variations thereon or comparable terminology. In addition to the important factors referred to herein, numerous factors affecting the gas processing or the oil and gas industry generally and in the specific markets for gas and NGLs in which we operate could cause actual results to differ materially from those in such forward-looking statements.

Results of Operations

Three and six months ended June 30, 2003 compared to the three and six months ended June 30, 2002

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

	Three Months Ended June 30,				Percent Change		Six Months Ended June 30,				Percent Change
	2003		2002		Percent Change		2003		2002		Percent Change

Financial results:
Revenues	$	660,491	$	614,128	8		$	1,548,597	$	1,230,044	26
Gross profit	49,130		40,393		22		114,339		68,338		67
Net income	20,900		13,766		52		44,275		21,766		103
Earnings per share of common stock	.58		.35		66		1.23		.53		132
Earnings per share of common stock - diluted	.56		.34		65		1.19		.52		129
Net cash provided by operating activities	$	26,495	$	45,390	(42	)	$	141,650	$	67,915	109

Operating data:
Average gas sales (MMcf/D)	1,247		1,856		(33	)	1,419		2,148		(34	)
Average NGL sales (MGal/D)	1,626		2,118		(23	)	1,640		2,031		(19	)
Average gas prices ($/Mcf)	$	4.86	$	3.02	61		$	5.18	$	2.71	91
Average NGL prices ($/Gal)	$	.54	$	.41	32		$	.58	$	.39	49

Net income increased $7.1million and $22.5 million for the three and six months ended June 30, 2003 compared to the same periods in 2002. The increases in net income were primarily attributable to a significant increase in gas and NGL prices in 2003 compared to the same periods last year. This increase in prices was supplemented by increased equity production from the Powder River Basin coal bed methane development and the Green River Basin. Partially offsetting the increases to net income in the six months ended June 30, 2003 was a pre-tax loss of $2.8 million from the discontinuance of hedge treatment on some financial instruments and a $6.7 million after-tax loss from the Cumulative effect of a change in accounting principle from the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations” on January 1, 2003.

Revenues from the sale of gas increased $43.9 million to $554.1 million for the three months ended June 30, 2003 compared to the same period in 2002. This increase was primarily due to an increase in product prices, which more than offset a decrease in sales volume in the three months ended June 30, 2003. Average gas prices realized by us increased $1.84 per Mcf to $4.86 per Mcf for the quarter ended June 30, 2003 compared to the same period in 2002. Included in the realized gas price were approximately $5.3 million of losses recognized in the three months ended June 30, 2003 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately half of our equity gas for the remainder of 2003 and to a lesser extent in 2004. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk”. Average gas sales volumes decreased to 1,247 MMcf per day for the quarter ended June 30, 2003 compared to the same period in 2002. This decrease was due to a temporary reduction in third party sales volume resulting from the increase in product prices and related credit exposure.

Revenues from the sale of gas increased $278.0 million to $1,333.8 million for the six months ended June 30, 2003 compared to the same period in 2002. This increase was primarily due to an increase in product prices, which more than offset a decrease in sales volume in the six months ended June 30, 2003. Average gas prices realized by us increased $2.47 per Mcf to $5.18 per Mcf for the six months ended June 30, 2003 compared to the same period in 2002. Included in the realized gas price were approximately $13.1 million of losses recognized in the six months ended June 30, 2003 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately half of our equity gas for the remainder of 2003 and to a lesser extent in 2004. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk”. Average gas sales volumes decreased to 1,419 MMcf per day for the six months ended June 30, 2003 compared to the same period in 2002. This decrease was due to a temporary reduction in third party sales volume resulting from the increase in product prices and related credit exposure.

Revenues from the sale of NGLs remain relatively constant at $80.5 million for the three months ended June 30, 2003 compared to the same period in 2002. This is primarily due to a significant increase in product prices that was substantially offset by a reduction in sales volumes as a result of the sale of our Toca facility in September 2002. Average NGL prices realized by us increased $0.13 per gallon to $0.54 per gallon for the three months ended June 30, 2003 compared to the same period in 2002. Included in the realized NGL price were approximately $2.1 million of losses recognized in the three months ended June 30, 2003 related to futures positions on equity NGL volumes. We have entered into additional futures positions for the majority of our equity NGL production for the remainder of 2003 and to a lesser extent in 2004. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk”. Average NGL sales volumes decreased 492 MGal per day to 1,626 MGal per day for the three months ended June 30, 2003 compared to the same period in 2002.

Revenues from the sale of NGLs increased approximately $27.9 million to $172.6 million for the six months ended June 30, 2003 compared to the same period in 2002. This increase is primarily due to a significant increase in product prices, which was partially offset by a reduction in sales volumes as a result of the sale of our Toca facility in September 2002. Average NGL prices realized by us increased $0.19 per gallon to $0.58 per gallon for the six months ended June 30, 2003 compared to the same period in 2002. Included in the realized NGL price were approximately $7.0 million of losses recognized in the six months ended June 30, 2003 related to futures positions on equity NGL volumes. We have entered into additional futures positions for the majority of our equity NGL production for the remainder of 2003 and to a lesser extent in 2004. See further discussion in “Item 3. Quantitative and Qualitative Disclosures About Market Risk”. Average NGL sales volumes decreased 391 MGal per day to 1,640 MGal per day for the six months ended June 30, 2003 compared to the same period in 2002.

Product purchases increased by $31.5 million and $258.5 million for the quarter and six months ended June 30, 2003 compared to the same periods in 2002 as a result of the significant increase in commodity prices. Overall, combined product purchases as a percentage of sales of all products decreased to 88% in both the quarter and six months ended June 30, 2003 from 89% in both of the 2002 periods. The reduction in this percentage is primarily the result of increases in product prices and an increase in sales of our equity production.

Marketing margins on residue gas averaged $0.06 and $0.08 per Mcf in the second quarter and the six months ended June 30, 2003, respectively. This represents a decrease of approximately $0.02 per Mcf as compared to the margin realized during the second quarter and an increase of approximately $0.03 per Mcf as compared to the margin realized during the six months ended June 30, 2002. The changes in the marketing margins are primarily due to transactions associated with our firm transportation capacity from the Rocky Mountain region to the mid-continent. Our firm transportation allows us to purchase gas in the Rocky Mountain region for resale in the higher priced mid-continent markets. In the second quarter of 2003, additional transportation capacity out of the Rocky Mountain region became operational, which reduced the price difference between the two regions. We expect that the reduced margins experienced in the second quarter of 2003 will continue in future periods. There is no assurance, however, that these margins will continue in the future, that we will be in a similar position to capture them or that we will continue to originate the same amount of transactions in future quarters.

Plant and transportation operating expense increased by $2.8 million and $5.9 million, respectively, for the three and six months ended June 30, 2003 compared to the same periods in 2002. These increases were primarily due to increased throughput at our facilities, additional leased compression in the Powder River Basin coal bed development and higher utility and fuel charges at our plant facilities. Also contributing to these increases are fees paid to other companies, primarily Rendezvous Gas Services, L.L.C., or Rendezvous, for gas gathering services. Rendezvous is a 50%-owned entity that delivers gas to our Granger Complex. Rendezvous is accounted for under the equity method and our share of its gathering revenues is reflected in Earnings from equity investments.

Oil and gas exploration and production expenses increased by $4.1 million and $9.3 million, respectively, for the three and six months ended June 30, 2003 compared to the same periods in 2002. In our operating areas, the significant increase in residue gas prices in 2003 resulted in substantially higher severance tax expenses. This increase was partially offset by decreased lease operating expenses, or LOE, in the Powder River Basin coal bed development. Overall, LOE averaged $0.41 per Mcf for the six months ended June 30, 2003. This represents a decrease of $0.04 per Mcf from the same period in 2002. The decrease in LOE is substantially due to increased production volumes in 2003.

Depreciation, depletion and amortization increased by $442,000 and $639,000, respectively, for the three and six months ended June 30, 2003 as compared to the same periods in 2002. These increases were the result of additional capital expenditures and depletion on our oil and gas assets, which was substantially offset by revisions to the operating lives and salvage values of our operating assets. These revisions were the result of analysis performed in connection with the adoption of SFAS No. 143.

Selling and administrative expenses decreased by $2.0 million for the three months ended June 30, 2003 as compared to the same period in 2002, due to a reduction in accruals for doubtful accounts. In the second quarter of 2002, we accrued a total of $1.6 million for doubtful accounts, primarily due to the bankruptcy filing of a large mid-western co-op in that quarter. Selling and administrative expenses remained relatively constant for the six months ended June 30, 2003 as compared to the same period in 2002 as higher health insurance costs and higher compensation expenses were substantially offset by a reduction in the accruals for doubtful accounts.

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

Cash Flow Information

Cash flows from operating activities increased by $73.7 million in the first six months of 2003 compared to the same period in 2002. This increase was primarily due to an increase in net income in the first six months of 2003 compared to the prior year and the timing of cash receipts and payables.

Cash flows used in investing activities increased by $12.0 million in the first six months of 2003 compared to the same period in 2002. This increase was primarily due to a higher level of capital expenditures.

Cash flows used in financing activities increased by $46.5 million in the first six months of 2003 compared to the same period in 2002. This increase was due to increased cash flows from operating activities, which was used to reduce our long-term debt.

Other Information

Acquisition of Gathering Systems. Effective February 1, 2003, we acquired 18 gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million. Several of the systems located in the Powder River Basin do not integrate directly into our existing systems, and accordingly we are negotiating for the sale of these systems. These systems are classified as Assets held for sale on the Consolidated Balance Sheet at June 30, 2003. During the three and six months ended June 30, 2003, the systems included in Assets held for sale generated net losses of approximately ($239,000) and ($92,000), respectively, and are immaterial for separate presentation as a discontinued operation.

Critical Accounting Policies

Accounting rules generally involve an interpretation and implementation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. Our critical accounting policies and estimates are discussed below.

Use of Estimates. The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported for assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the amounts reported for revenues and expenses during the reporting period. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. However, actual results may differ significantly from the estimates used. Any effects on our business, financial position or results of operations resulting from revisions to these estimates will be recorded in the period in which the facts that necessitate a revision become known.

Property and Equipment. Our property and equipment is recorded at the lower of cost, including capitalized interest, or estimated realizable value. Interest incurred during the construction period of new projects is capitalized and amortized over the life of the associated assets.

Depreciation on these assets is provided using the straight-line method based on the estimated useful life of each facility, which ranges from three to 35 years. Useful lives are determined based on the shorter of our estimate of the life of the equipment or our estimate of the reserves serviced by the equipment. Among other factors, the estimates consider our experience with similar assets and technical analysis of the reserves. The cost of acquired gas purchase contracts is amortized using the straight-line method or units of production. If the actual lives of the equipment or the reserves serviced by the equipment were less than we originally estimated, we may be required to record a loss upon retirement of a specific asset.

In connection with the adoption of SFAS No. 143, we completed a review of our operating assets and reevaluated the operating life and salvage values of the associated equipment. As a result of this evaluation, we extended the useful life of many of our operating assets and adjusted the estimated salvage value of our operating equipment. These adjustments resulted in an approximate $5.8 million, or $0.10 per share of common stock – assuming dilution, decrease in depreciation, depletion and amortization in the six months ended June 30, 2003 from the expense calculated using the previous useful lives. The adjustments to the salvage value and depreciable lives of our assets are treated as a revision of an estimate and are accounted for on a prospective basis.

Oil and Gas Properties and Equipment. We follow the successful efforts method of accounting for oil and gas exploration and production activities. Acquisition costs, development costs and successful exploration costs are capitalized when incurred. Exploratory dry hole costs, lease rentals and geological and geophysical costs are charged to expense as incurred. Upon surrender of undeveloped properties, the original cost is charged against income. Producing properties and related equipment are depleted and depreciated by the units-of-production method based on estimated proved reserves. The unit of production method is sensitive to the determination of proved reserves. We utilize technical analysis and outside expertise annually to determine the reserves associated with our oil and gas properties. To the extent the reserves are modified based on this review, the depletion determined under the units of production method will be increased or decreased on a prospective basis.

Impairment of Long-Lived Assets. If changes in the expected performance of an asset occur, or if overall economic conditions warrant, we will review our assets to determine their economic viability. This review is completed at the plant facility, the related group of plant facilities or the oil and gas producing property level. In order to determine whether an impairment exists, we compare the net book value of the asset to the estimated fair market value or the undiscounted expected future net cash flows, determined by applying future prices estimated by management over the shorter of the lives of the facilities or the reserves supporting the facilities. If an impairment exists, write-downs of assets are based upon expected future net cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset. This analysis is sensitive to, among other things; management’s expectation of commodity prices, operating costs, drilling plans and production rates.

Identification of Derivatives and Mark to Market Valuations. The determination of which contractual instruments meet the definition of a derivative under accounting rules is subject to differing interpretations as is the valuation of those derivatives. Management uses its judgment to analyze all contracts to determine whether or not they qualify as derivatives and to determine their value. Specific areas in which management’s judgment is required includes identifying contracts

meeting the criteria for exclusions from derivatives treatment, market liquidity, and market valuation. This analysis is sensitive to commodity prices, outside market factors and management’s intent upon entering into these contracts.

Significant Risks. We are subject to a number of risks inherent in the industry in which we operate, including price volatility, counter party credit risk, the success of our drilling programs and other gas supply. Our financial condition and results of operations will depend significantly upon the prices we receive for gas and NGLs. These prices are subject to fluctuations in response to changes in supply and demand and a variety of additional factors that are beyond our control. In addition, we must continually connect new wells to our gathering systems in order to maintain or increase throughput levels to offset natural declines in dedicated volumes. The number of new wells drilled will depend upon, among other factors, prices for gas and oil, the drilling budgets of third-party producers, the energy policy of the federal government and the availability of foreign oil and gas, none of which are within our control.

Recently Issued Accounting Pronouncements. We continually monitor and revise our accounting policies as new rules are issued. At this time, there are several new accounting pronouncements that have recently been issued, but not yet adopted, which will have an impact on our accounting when these rules become effective later in 2003. For a more detailed description of these pronouncements see “Part 1 – Financial Information – Item 1. Financial Statements.”

Liquidity and Capital Resources

Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of debt and equity securities. In the past, these sources have been sufficient to meet our needs and finance the growth of our business. We can give no assurance that the historical sources of liquidity and capital resources will be available for future development and acquisition projects, and we may be required to seek additional or alternative financing sources. Product prices, sales of inventory, the volumes of natural gas processed by our facilities, the volume of natural gas produced from our producing properties, the margin on third-party product purchased for resale, as well as the timely collection of our receivables will all affect future net cash provided by operating activities. Additionally, our future growth will be dependent upon obtaining additions to dedicated plant reserves, acquisitions, new project development, marketing results, efficient operation of our facilities and our ability to obtain financing at favorable terms.

During the past several years, although some of our plants have experienced declines in dedicated reserves, overall we have been successful in connecting additional reserves to more than offset the natural declines. The overall level of drilling will depend upon, among other factors, the prices for oil and gas, the drilling budgets of third-party producers, availability of transportation capacity to market centers, the energy and environmental policy and regulation by governmental agencies, and the availability of foreign oil and gas, none of which is within our control. There is no assurance that we will continue to be successful in replacing the dedicated reserves processed at our facilities. Any prolonged reduction in prices for natural gas and NGLs may depress the levels of exploration, development and production by third-parties and us. Lower levels of these activities could result in a corresponding decline in the demand for our gathering, processing and treating services. A reduction in any of these activities could have a material adverse effect on our financial condition, results of operations and cash flows.

We believe that the amounts available to be borrowed under the revolving credit facility, together with net cash provided by operating activities, will provide us with sufficient funds to connect new reserves, maintain our existing facilities and complete our current capital expenditure program. Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital. Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third-parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or a combination of alternatives. While we believe that we would be able to secure additional financing, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing. In July 2003, we utilized a portion of the revolving credit facility to fund a $10.0 million scheduled payment on the Master Shelf Agreement. We believe that cash provided by operating activities and amounts available under the revolving credit facility will be sufficient to meet remaining scheduled principal repayments during 2003 of $33.3 million under the Master Shelf Agreement and our preferred stock dividend requirements during the remainder of 2003 of approximately $3.6 million.

We have effective shelf registration statements filed with the SEC for an aggregate of $200 million of debt securities and preferred stock, along with the shares of common stock, if any, into which those securities are convertible, and $62 million of debt securities, preferred stock or common stock. These shelf registrations allow us to access the debt and equity markets without the requirement of further SEC review.

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

Sources of funds:
	Borrowings under the revolving credit facility	$	573,900
	Borrowings under the Master Shelf Agreement	25,000
	Proceeds from the dispositions of property and equipment	3,564
	Net cash provided by operating activities	141,650
	Proceeds from exercise of common stock options	2,618
	Total sources of funds	$	746,732
Uses of funds:
	Payments related to long-term debt (including debt issue costs)	$	627,329
	Capital expenditures	79,551
	Preferred dividends paid	3,623
	Common dividends paid	3,310
	Total uses of funds	$	713,813

Capital Investment Program. Our capital expenditures during the six months ended June 30, 2003 totaled approximately $79.6 million. Overall, capital expenditures during this period consisted of the following: (i) approximately $14.4 million related to gathering, processing, treating and pipeline assets, including $3.3 million for maintaining existing facilities; (ii) approximately $22.3 million related to exploration and production and lease acquisition activities; (iii) $37.1 million for the acquisition of 18 gathering systems, which closed in January 2003; (iv) approximately $3.1 million for information technology and other items; and (v) approximately $2.7 million for capitalized overhead and interest.

We currently anticipate capital expenditures in 2003 of approximately $210.1 million, an increase of $27.8 million from our previous 2003 capital budget. The revised 2003 capital budget consists of the following: (i) approximately $83.9 million related to gathering, processing, treating and pipeline assets, including $13.3 million for maintaining existing facilities; (ii) approximately $77.0 million related to exploration and production and lease acquisition activities; (iii) $37.1 million for the acquisition of 18 gathering systems, which closed in January 2003; (iv) approximately $4.3 million for information technology and other items; and (v) $7.8 million for capitalized interest and overhead. Overall, capital expenditures in the Powder River Basin coal bed methane development and in southwest Wyoming operations represent 28% and 51%, respectively, of the total 2003 budget. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital budget for 2003 will not change. This budget may be further increased to provide for acquisitions if approved by our board of directors.

Contractual Commitments and Obligations

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

			Payments by Period
Type of Obligation	Total Obligation		Due in 2003		Due in 2004 – 2005		Due in 2006 – 2007		Due Thereafter
Guarantee of Fort Union Project Financing	$	5,928	$	382	$	1,669	$	1,931	$	1,946
Operating Leases	77,057		8,546		23,472		22,453		22,586
Firm Transportation Capacity and Gathering Agreements	229,199		16,263		55,587		54,493		102,856
Firm Storage Capacity Agreements	14,967		3,055		6,610		3,379		1,923
Long-term Debt	333,333		43,333		45,000		65,000		180,000
Total Contractual Cash Obligations	$	660,484	$	71,579	$	132,338	$	147,256	$	309,311

Guarantee of Fort Union Project Financing. We own a 13% equity interest in the Fort Union Gas Gathering, L.L.C., or Fort Union, and are the construction manager and field operator. Fort Union gathers and treats natural gas in the Powder River Basin in northeast Wyoming. Initial construction and any expansions of the gathering header and treating system have been project financed by Fort Union. This debt is amortizing on an annual basis and is scheduled to be fully paid in 2009. All participants in Fort Union have guaranteed Fort Union’s payment of the project financing on a proportional

basis, resulting in our guarantee of $5.9 million of the debt of Fort Union at June 30, 2003. Our requirement to fund under this guarantee would be reduced by the value of assets held by Fort Union. This guarantee is not reflected on our Consolidated Balance Sheet.

Operating Leases. In the ordinary course of our business operations, we enter into operating leases for office space, office equipment, communication equipment and transportation equipment. In addition, we have entered into operating leases for compression equipment. Payments made on these leases are a component of operating expenses and are reflected on the Consolidated Statement of Operations and, as operating leases, are not reflected on our Consolidated Balance Sheet. These leases have terms ranging from one month to ten years with return or fair market purchase options available at various times during the lease. If we were to exercise the early buyout options on all the leased equipment, these purchase options would require the capital expenditure of approximately $33.9 million between 2007 and 2012.

Firm Transportation Capacity and Gathering Agreements. Access to firm transportation is also a significant element of our business strategy. Firm transportation ensures that our equity production has access to downstream markets and allows us to capture incremental profit when pricing differentials between physical locations occur. As of June 30, 2003, we had contracts for approximately 616 MMcf per day of firm transportation. This amount represents our total contracted amount on many individual pipelines. In many cases it is necessary to utilize sequential pipelines to deliver gas into a specific sales market. In total, we have the capacity to transport 171 MMcf per day of gas from the Rocky Mountain area to the Mid-Continent. This utilizes a total of approximately 376 MMcf per day of firm capacity on three separate pipelines. The total rate under these long-term contracts to transport this gas to the Mid-Continent approximates $0.35 per Mcf. Our remaining firm capacity consists of 103 MMcf per day to markets within the Rocky Mountains and 137 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.

A portion of this firm transportation capacity was contracted for use in our Marketing operations. For example, our Marketing segment purchases gas in the Rocky Mountain region, transports this gas utilizing its 56 MMcf per day of our firm transportation capacity to the Mid-Continent, and resells the gas to various markets. During the six months ended June 30, 2003, these types of transactions have been profitable as the price difference, or basis, between the Rocky Mountain and Mid-Continent regions has exceeded the cost of transportation. We expect that the fixed fees associated with our contracts for firm transportation capacity during the remainder of 2003 will average approximately $0.13 per Mcf per day. The associated contract periods range from one month to fourteen years. Under firm transportation contracts, we are required to pay the fees associated with these contracts whether or not the transportation is used.

Firm Storage Capacity Agreements. We customarily store gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and to capture seasonal price differentials. As of June 30, 2003, we had contracts in place for approximately 13.3 Bcf of storage capacity at various third-party facilities. Of the total storage capacity under contract, approximately 5.2 Bcf is under contract to our Canadian subsidiary, WGR – Canada, Inc. and Western guarantees the subsidiary’s performance under these contracts. This subsidiary is wholly owned by us and fully consolidated in our financial statements.

The fees associated with these contracts during the remainder of 2003 will average $0.39 per Mcf of annual capacity. The associated contract periods at June 30, 2003 have an average term of twenty-four months. At June 30, 2003, we held gas in our contracted storage facilities and in imbalances of approximately 12.9 Bcf at an average cost of $4.47 per Mcf compared to 16.3 Bcf at an average cost of $2.50 per Mcf at June 30, 2002. These positions are for storage withdrawals within the next twelve months. At the time that we place product into storage, we contract for the sale of that product, physically or financially, and do not speculate on the future value of the product.

From time to time, we lease NGL storage space at major trading locations to facilitate the distribution of products. At June 30, 2003, we held NGLs in storage at various third-party facilities of 2,662 MGal, consisting primarily of propane and normal butane, at an average cost of $0.25 per gallon compared to 3,933 MGal at an average cost of $0.30 per gallon at June 30, 2002.

Long-term Debt

Revolving Credit Facility. At June 30, 2003, $45.0 million was outstanding under our existing four-year, $300 million revolving credit facility. Loans made under this facility are secured by a pledge of the capital stock of our significant subsidiaries. These subsidiaries also guarantee the borrowings under the facility. The facility contains a provision that requires us to secure loans under the facility with 75% of our oil and gas reserves. This provision would only be triggered in the event of a reduction to a debt rating on the revolving credit facility of Ba3 or lower by Moody’s Investors Service, Inc., or Moody’s, or the reduction to a debt rating on the revolving credit facility of BB- or lower by Standard & Poor’s Rating Services, a division of The McGraw-Hill Companies, Inc., or S&P. In August 2003, Moody’s issued a rating of Ba1 and S&P issued a rating of BB+ on the revolving credit 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 facility fee ranging between 0.30% and 0.50%, depending on our debt to capitalization ratio. This fee is paid on the total commitment. At June 30, 2003, the interest rate payable on borrowings under the new facility was approximately 3.04%.

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

The credit facility ranks equally with borrowings under our Master Shelf Agreement with The Prudential Insurance Company.

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

Issue Date	Amount		Interest Rate		Final Maturity	Principal Payments Due
October 27, 1992	$	8,333	7.99	%	October 27, 2003	single payment at maturity
December 27, 1993	25,000		7.23	%	December 27, 2003	single payment at maturity
October 27, 1994	25,000		9.24	%	October 27, 2004	single payment at maturity
July 28, 1995	50,000		7.61	%	July 28, 2007	$10,000 on each of July 28, 2003 through 2007
January 17, 2003	25,000		6.36	%	January 17, 2008	single payment at maturity
	$	133,333

Our borrowings under the Master Shelf Agreement are secured by a pledge of the capital stock of our significant subsidiaries, some of which have also provided a guaranty of payments owed by us under the facility. The Master Shelf requires us to secure loans under the facility with 75% of our oil and gas reserves. This provision would only be triggered in the event of a reduction to the debt rating on the revolving credit facility of Ba3 or lower by Moody’s or the reduction to the debt rating on the revolving credit facility of BB- or lower by S&P. In August 2003, Moody’s issued a rating of Ba1 and S&P issued a rating of BB+ on the revolving credit facility.

Under our Master Shelf Agreement, we are subject to a number of covenants, including: maintaining a minimum tangible net worth equal to the sum of $300 million plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of the net proceeds of any equity offerings after January 1, 1999; maintaining a total debt to capitalization ratio of not more than 55% and a senior debt to capitalization ratio of not more than 40%; maintaining a quarterly test of EBITDA to interest for the last four quarters in excess of 3.25 to 1.0, increasing to 4.25 to 1.0 by March 31, 2005; and maintaining a ratio of senior debt to EBITDA of no greater than 4.0 to 1.0.

In July 2003, we utilized funds available under the revolving credit facility to fund a $10.0 million scheduled payment under the Master Shelf Agreement. In the remainder of 2003, we will make required principal repayments under the Master Shelf Agreement totaling $33.3 million. We intend to fund these repayments with funds available under the revolving credit facility.

Senior Subordinated Notes. In 1999, we sold $155.0 million of Senior Subordinated Notes in a private placement with a final maturity of 2009 due in a single payment which were subsequently exchanged for registered publicly tradable notes under the same terms and conditions. The Subordinated Notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%. These notes contain covenants, which include limitations on debt incurrence, restricted payments, liens and sales of assets. The Subordinated Notes are unsecured and are guaranteed on a subordinated basis by our material subsidiaries. We incurred approximately $5.0 million in offering commissions and expenses, which were capitalized and are being amortized over the term of the notes.

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

Upstream Operations

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 three to five year period. In order to achieve this goal, we will focus on continued development of our leasehold positions in the Powder River Basin coal bed methane project and the Greater Green River Basin projects. Each of our existing upstream projects are fully integrated with our midstream operations. In other words, we provide the gathering, compression, processing, marketing or transportation services for both our own production and for third-party operators. Additionally, we are actively pursuing new exploration development and producing property acquisition opportunities.

Powder River Basin Coal Bed Methane. We continue to develop our Powder River Basin coal bed methane reserves and expand the associated gathering system in northeast Wyoming. The Powder River Basin coal bed methane area is currently one of the largest on-shore plays for the development of natural gas in the United States. Within this area, together with our co-developer, in the first six months of 2003, we were the largest producer of natural gas. In addition, Western is the largest gatherer of natural gas and, through our MIGC pipeline, transports a significant volume of gas out of this basin.

At June 30, 2003, we held the drilling rights on approximately 529,000 net acres in this basin, and as of December 31, 2002, we had established proven developed and undeveloped reserves totaling 414 Bcfe on a portion of this acreage, 52% of which are proven and developed. The drilling operations in the Powder River Basin through June 30, 2003 have primarily focused on developing reserves in the Wyodak coal, which is located on the east side of the coal bed development. We participated in the drilling of 273 gross wells through the first seven months of 2003. The average drilling and completion cost for our coal bed methane gas wells has approximated $90,000 to $120,000 per well, with average reserves per successful Wyodak well of approximately 275 MMcf. The majority of future development will be concentrated on developing the Big George and other coal seams. Much of the Big George coal seam is deeper and thicker than the Wyodak coal. We expect that as wells are drilled and developed in the Big George coal, the gas reserves and production per well and the average drilling and completion cost per well will increase.

We currently plan to participate in a total of 600 to 650 gross wells in 2003, which is a reduction from our original estimate of 845 wells. The reduction is the result of delays in receiving permits to drill on federal lands from the Bureau of Land Management, or BLM. Our share of production from wells in which we own an interest averaged approximately 109 MMcfe per day in the first six months of 2002 and increased to an average of approximately 122 MMcfe per day in the first six months of 2003. We currently anticipate production to remain relatively constant at this rate through the end of 2003, assuming that the issuance of permits on federal leases as a result of the Environmental Impact Statement, or EIS, as described below, are not further delayed.

Industry-wide, production from the Big George coal increased to approximately 99 MMcf per day in May 2003 from nine separate areas. This represents an increase of 212% since June 2002. We are currently evaluating 11 pilot areas and one development area in the Big George. We have marketable production quantities in the All Night Creek, Pleasantville and Kingsbury areas. In July 2003, these areas were producing a combined 32 gross MMcf per day, a 208% increase since June 2002. At December 31, 2002, we had proven reserves of 49 Bcfe in the Big George coal, primarily associated with the All Night Creek development area.

On April 30, 2003, the BLM issued the final Record of Decision, or ROD, in relation to its EIS regarding future Coal Bed Methane, or CBM, drilling in the Powder River Basin. The ROD requires additional surveys for plant and animal species, cultural surveys and noxious weed mitigation. We have filed permit applications for approval by the BLM under the terms of the new EIS, but are unable to predict the rate at which permits will be granted. This timing may also be affected by several lawsuits, which were filed on May 1, 2003 in the U.S. District Court in Billings, Montana challenging the BLM’s decision. While we believe that these lawsuits are unlikely to be successful, we are unable to predict the outcome of the litigation or the impact, if any, on the timing of our development. For further information, see "Part II—Other Information—Item1. Legal Proceedings" of this Form 10-Q.

Additionally, the Wyoming Department of Environmental Quality, or DEQ, has revised some standards for surface water discharge that have allowed the issuance of most of the permits that apply to the Cheyenne and Belle Fourche drainage areas. The majority of our existing production is from wells draining into these areas. Most of our undeveloped prospects from the Big George formation are located in the Powder River drainage area. The Wyoming DEQ will require additional water management techniques, such as containment or treating, in these areas pursuant to the conditions described in the EIS referred to above. While we believe these additional requirements will add to the cost of development of this area we do not believe they will have a significant impact on our results of operation or financial position.

Our 2003 capital budget in the Powder River Basin coal bed project includes approximately $45.2 million for drilling costs, production equipment and lease acquisitions, of which approximately $18.2 million was spent in the first six months of 2003. Depending upon future drilling success, we may need to make additional capital expenditures or leasing commitments to continue expansion in this basin. In addition, due to regulatory uncertainties, which are beyond our control, we can make no assurance that we will incur this level of capital expenditure during 2003.

Greater Green River Basin. Our upstream assets in the Green River Basin of southwest Wyoming are located in the Jonah Field and Pinedale Anticline areas. As of June 30, 2003, we owned approximately 194,000 gross oil and gas leasehold acres, or approximately 33,000 net acres, in these areas. During the first six months of 2003, we participated in 16 gross wells, or two net wells, in these areas, at a cost of $2.4 million and experienced a success rate of 100%. Our capital budget for 2003 in the Jonah Field and Pinedale Anticline areas provides for expenditures of approximately $20.1 million for drilling costs and production equipment. Due to drilling and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure. During the remainder of 2003, we expect to participate in the drilling of 29 gross wells, or approximately three net wells on the Pinedale Anticline. The expected gross costs to drill a successful well in this area range from approximately $3.5 million to $5.0 million, depending on location of the well site and the depth of the well. Average well depths in this area range from approximately 13,000 feet to 14,200 feet and average gross reserves per successful well approximate 6 to 8 Bcfe. During the second quarter of 2003, we produced an average of 27 MMcfe per day, net, from these areas. We had established proven developed and undeveloped reserves totaling 161 Bcfe at December 31, 2002. There can be no assurance, however, as to the ultimate recovery of these reserves.

We continue to explore and develop our acreage position in the Sand Wash Basin in northwest Colorado, located in the Greater Green River Basin. We own approximately 208,000 gross oil and gas leasehold acres, or approximately 177,000 net acres, in this basin. The majority of this acreage is in the exploration phase and will be evaluated in 2003 and subsequent years. Our capital budget in this area provides for expenditures of approximately $5.3 million during 2003 for our participation in the drilling of six gross developmental wells, or four net wells, and three workovers of existing wells. Of the total 2003 capital budget, approximately $1.4 million was spent in the first six months of 2003.

Exploration. We are also actively seeking to add another core project that is focused on Rocky Mountain natural gas. We have acquired a substantial acreage position in one new area and will continue to evaluate the potential of this area. 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 this area.

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, 2003, we operated a total of 20 significant gathering, processing and treating facilities, or plant operations, with approximately 9,925 miles of gathering lines. These facilities are primarily located in five states and have a combined throughput capacity of 2.9 billion cubic feet, Bcf, per day of natural gas. Our operations are located in some of the most actively drilled oil and gas producing basins in the United States. Five of our processing plants can further separate, or fractionate, the mixed NGL stream into ethane, propane, normal butane and natural gasoline to obtain a higher value for the NGLs, and three of our plants are capable of processing and treating natural gas containing hydrogen sulfide or other impurities that require removal prior to delivery to market pipelines. In addition to our integrated upstream and midstream operations in the Powder River and Green River Basins in Wyoming, our core assets include our plant operations located in west Texas and Oklahoma. We believe that our core assets have stable production rates, provide a significant operating cash flow and continue to provide us with strategic growth opportunities.

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

We averaged 414 MMcf per day of CBM gathering volumes, including third-party gas, during the second quarter of 2003. This represents a 15 percent increase compared to the same period in 2002. Of that volume, approximately 107 MMcf per day was transported through our MIGC pipeline.

We are the construction manager and field operator of the Fort Union gathering system and header. The Fort Union system delivers coal bed methane gas to a treating facility near Glenrock, Wyoming and accesses interstate pipelines serving gas markets in the Rocky Mountain and Midwest regions of the United States. The gathering pipeline has a capacity of 635 MMcf per day. We have a long-term, firm gathering agreement with Fort Union for 83 MMcf per day of this capacity at $0.14 per Mcf.

Our capital budget in the Powder River Basin for midstream activities provides for expenditures of approximately $15.2 million during 2003, of which approximately $5.5 million was spent in the first half of the year. Depending upon our future drilling success, we may need to make additional capital expenditures or leasing commitments to continue expansion in this basin. Due to drilling, regulatory, commodity pricing and other uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure.

Green River Basin. Our midstream operations in the Green River Basin of southwest Wyoming are also fully integrated with our upstream operations in this area. Our midstream assets in this basin are comprised of the Granger and Lincoln Road facilities, or collectively the Granger complex, our 50% equity interest in Rendezvous, our Red Desert facility and our recently acquired Table Rock, Wamsutter and Desert Springs gathering systems. These facilities have a combined gathering capacity of 682 MMcf per day, and in the six months ended June 30, 2003, these facilities averaged throughput of 543 MMcf per day. Additionally, these systems have a combined processing capacity of 327 MMcf per day and in the six months ended June 30, 2003, processed an average of 215 MMcf per day.

Our 2003 capital budget for midstream activities in this basin provides for expenditures of approximately $81.3 million during 2003 of which $38.9 million was spent in the first half of the year. This capital budget includes approximately $28.1 million for gathering lines and installation of compression to expand the capacity of our Granger Complex , our Wamsutter gathering system and our Red Desert facility, $16.1 million for additional contributions to Rendezvous for the expansion of its system and $37.1 million for the acquisition of additional gathering systems in February 2003. Due to drilling, commodity pricing and regulatory uncertainties, which are beyond our control, there can be no assurance that we will incur this level of capital expenditure.

In 2001, we, together with an unrelated third-party, formed Rendezvous. Rendezvous gathers gas along the Pinedale Anticline for blending or processing at either our Granger Complex or at the third-party owned and operated Blacks Fork processing facility. Each company owns a 50% interest in Rendezvous, and we serve as field operator of its systems. Rendezvous has a capacity of 275 MMcf per day and in June 2003 was gathering 216 MMcf per day. An expansion of the system is scheduled to be completed in the fourth quarter of 2003. The expansion would extend the system approximately 24 miles further into the Pinedale Anticline as well as increase the capacity of the system to 350 MMcf per day at an estimated cost of $32.0 million gross, of which our share is approximately $16.0 million. As part of our expansion process, we are implementing a 100 MMcf per day processing capacity upgrade at our Granger plant at a cost of $1.0 million.

West Texas. Our primary assets in west Texas are the Midkiff/Benedum complex and the Gomez and Mitchell Puckett treating facility. These facilities process gas produced by third-parties in the Permian Basin, have a combined operational capacity of 565 MMcf per day and processed an average of 283 MMcf per day in the first half of 2003. Also for this period, these facilities produced an average of 205 MMcf per day of natural gas for delivery to sales markets and produced an average of 777 MGal per day of NGLs. Our capital budget in this area provides for expenditures of approximately $7.4 million during 2003, of which $2.1 million was spent in the first six months.

Oklahoma. Our primary assets in Oklahoma are the Chaney Dell and Westana systems. These facilities gather and process gas produced by third-parties in the Anadarko Basin and have a combined operational capacity of 175 MMcf per day. In the six months ended June 30, 2003, these facilities processed an average of 156 MMcf per day, produced an average of 137 MMcf per day of natural gas for delivery to sales markets and produced 306 MGal per day of NGLs. Our capital budget in this area provides for expenditures of approximately $15.7 million during 2003, of which approximately $4.5 million has been spent in the first six months.

Principal Facilities. The following tables provide information concerning our principal gathering, processing and treating facilities and transportation assets at June 30, 2003.

Facilities (1)	Year Placed In Service	Gas Gathering System Miles (2)	Gas Throughput Capacity (MMcf/D) (3)	Average for the Six Months Ended June 30, 2003
Facilities (1)	Year Placed In Service	Gas Gathering System Miles (2)	Gas Throughput Capacity (MMcf/D) (3)	Gas Throughput (MMcf/D) (4)	Gas Production (MMcf/D) (5)	NGL Production (MGal/D) (5)
Texas
Gomez Treating (6)	1971	386	280	85	77	—
Midkiff/Benedum	1949	2,243	165	134	88	776
Mitchell Puckett Treating (6)	1972	93	120	64	40	1
Wyoming
Coal Bed Methane Gathering	1990	1,310	525	413	217	—
Desert Springs Gathering (13)	1979	65	10	5	5	12
Fort Union Gas Gathering	1999	167	635	481	481	—
Granger (7)(8)(9)	1987	538	235	228	148	350
Hilight Complex (7)	1969	626	124	15	10	50
Kitty/Amos Draw (7)	1969	314	17	6	4	26
Lincoln Road (9)	1988	149	50	34	11	5
Newcastle (7)	1981	146	5	3	2	20
Red Desert (7)	1979	111	42	12	11	21
Rendezvous	2001	—	275	215	215	—
Reno Junction (8)	1991	—	—	—	-	103
Table Rock Gathering (13)	1979	101	20	14	14	—
Wamsutter Gathering (13)	1979	186	50	35	34	8
Wind River Gathering (13)	1979	109	80	43	43	—
Oklahoma
Chaney Dell/Westana	1966	3,137	175	156	137	306
New Mexico
San Juan River (6)	1955	140	60	30	24	47
Utah
Four Corners Gathering	1988	104	15	3	2	17
Total		9,925	2,883	1,976	1,563	1,742

			Average for the Six Months Ended June 30, 2003
Transportation Facilities (1)	Year Placed In Service	Transportation Miles(2)	Pipeline Capacity (MMcf/D)(2)	Gas Throughput (MMcf/D)(4)
MIGC (10)(12)	1970	245	130	165
MGTC (11)	1963	252	18	10
Total		497	148	175

Footnotes on following page.

(1) Our interest in all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%); Fort Union gathering system (13%) and Rendezvous (50%). We operate all facilities, and all data include our interests and the interests of other joint interest owners and producers of gas volumes dedicated to the facility. Unless otherwise indicated, all facilities shown in the table are gathering, processing or treating facilities.

(2) Gas gathering system miles, transportation miles and pipeline capacity are as of June 30, 2003.

(3) Gas throughput capacity is as of June 30, 2003 and represents capacity in accordance with design specifications unless other constraints exist, including permitting or field compression limits.

(4) Aggregate wellhead natural gas volumes collected by a gathering system or volumes transported by a pipeline.

(5) Volumes of gas and NGLs are allocated to a facility when a well is connected to that facility; volumes exclude NGLs fractionated for third-parties.

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

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

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

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

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

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

(12) Pipeline capacity represents certificated capacity at the Powder River junction only and does not include interruptible capacity or capacity at other delivery points.

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

Transportation. We own and operate MIGC, Inc. an interstate pipeline located in the Powder River Basin in Wyoming, and MGTC, Inc. an intrastate pipeline located in northeast Wyoming. MIGC charges a Federal Energy Regulatory Commission, or FERC, approved tariff and is connected to pipelines owned by Colorado Interstate Gas Company, Williston Basin Interstate Pipeline Company, Kinder Morgan Interstate Pipeline Co., Wyoming Interstate Company, Ltd. and MGTC. During the six months ended June 30, 2003, MIGC transported an average of 165 MMcf per day. It is anticipated that MIGC will continue to operate around that level through the remainder of 2003. MIGC earns fees on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline. Contracts for firm capacity on MIGC range in duration from one month to six years and the fees charged average $0.33 per Mcf in the first six months of 2003.

The FERC has implemented changes over the past several years to restrict transactions between regulated pipelines and affiliated companies. In addition, the FERC has proposed to limit the use of affiliates’ employees in the operation of regulated entities. We can make no assurances as to the ultimate regulations passed by the FERC or the effects such regulations may have on the operating costs of MIGC or our financial position.

MGTC provides transportation and gas sales to the Wyoming cities of Gillette, Moorcroft and Wright at rates that are subject to the approval of the Wyoming Public Service Commission. During the six months ended June 30, 2003, MGTC transported an average of 10 MMcf per day.

Marketing.

Gas. We market gas produced at our wells and our plants and purchased from third-parties to end-users, local distribution companies, or LDCs, pipelines and other marketing companies throughout the United States and Canada. In addition to our offices in Denver, we have 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. For the six months ended June 30, 2003, our total gas sales volumes averaged 1.4 Bcf per day, of which 470 MMcf per day was produced at our plants or from our producing properties.

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 Rocky Mountain region has traded at a substantial discount to the mid-continent and west coast areas as a result of limited pipeline capacity from the region. In the six months ended June 30, 2003, as a result of our firm transportation capacity, we realized an approximate $0.57 per Mcf improvement in price for natural gas relative to the price that would have been received if these capacity rights had not existed. In the second quarter of 2003, additional pipeline capacity out of the Rocky Mountain region went into service. This pipeline expansion contributed to a reduction in the price difference between the Rocky Mountain region and mid-continent market center to approximately $0.62 per Mcf in June

2003 as compared to an average of $2.30 per Mcf in the first quarter of 2003. We expect this additional pipeline capacity to continue to an ongoing impact on the price difference between the Rocky Mountain and Mid-Continent regions. The remainder of our equity production of natural gas in the Rocky Mountain region that is not transported to the mid-continent is hedged for the remainder of 2003 using financial instruments.

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

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, or ethane, propane, iso-butane, normal butane, natural gasoline and condensate, produced at our plants and purchased from third-parties, in the Rocky Mountain, Mid-Continent and Southwestern regions of the United States. A majority of our production of NGLs moves to the Gulf Coast area, which is the largest NGL market in the United States. Through the development of end-use markets and distribution capabilities, we seek to ensure that products from our plants move on a reliable basis, avoiding curtailment of production. For the six months ended June 30, 2003, NGL sales averaged 1,640 MGal per day, of which 1,375 MGal per day was produced at our plants.

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our commodity price risk management program has two primary objectives. The first goal is to preserve and enhance the value of our equity volumes of gas and NGLs with regard to the impact of commodity price movements on cash flow and net income in relation to those anticipated by our operating budget. The second goal is to manage price risk related to our marketing activities to protect profit margins. This risk relates to fixed price purchase and sale commitments, the value of storage inventories and exposure to physical market price volatility.

We utilize a combination of fixed price forward contracts, exchange-traded futures and options, as well as fixed index swaps, basis swaps and options traded in the over-the-counter, or OTC, market to accomplish these goals. These instruments allow us to preserve value and protect margins because corresponding losses or gains in the value of the financial instruments offset gains or losses in the physical market.

We also use financial instruments to reduce basis risk. Basis is the difference in price between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations.

We enter into futures transactions on the New York Mercantile Exchange, or NYMEX, and through OTC swaps and options with various counterparties, consisting primarily of investment banks, financial institutions and other natural gas companies. We conduct credit reviews of all of our OTC counterparties and have agreements with many of these parties that contain collateral requirements. We generally use standardized swap agreements that allow for offset of positive and negative OTC exposures. OTC exposure is marked-to-market daily for the credit review process. Our exposure to OTC credit risk is reduced by our ability to require a margin deposit from our counterparties based upon the mark-to-market value of their net exposure. We are also subject to margin deposit requirements under these same agreements and under margin deposit requirements for our NYMEX transactions. Primarily as a result of our equity hedge positions for natural gas and liquid products, we have posted margin totaling $3.0 million with various counterparties at July 31, 2003.

We continually monitor and review the credit exposure to our marketing counterparties. Additionally, beginning in 2001, we became increasingly concerned with our credit exposure to our customers, primarily a category of our customers generally known as “energy merchants.” Energy merchants create liquidity in the marketplace for natural gas transactions and have historically been some of our largest suppliers and customers. In order to minimize our credit exposures, we have utilized existing netting agreements to reduce our net credit exposure, established new netting agreements with additional customers, terminated several long-term marketing obligations, negotiated accelerated payment terms with several customers, and reduced the amount of credit which we make available to various customers. 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.

In July 2003, one of our marketing counterparties filed a petition for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy code. As a result, we terminated our agreements with this counterparty. At the time of the termination, we were holding approximately $1.7 million of collateral from this counterparty; accordingly, we do not expect this bankruptcy filing to have any impact on our results of operations, financial position or cash flows.

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 July 31, 2003, we have hedged approximately 51% of our projected 2003 equity natural gas volumes and approximately 78% of our estimated equity production of crude oil, condensate, and NGLs. We have also begun to enter into hedges for our projected 2004 equity natural gas volumes and for our estimated equity production of crude oil, condensate, and NGLs. All of these contracts are designated and accounted for as cash flow hedges. As such, gains and losses related to the effective portions of the changes in the fair value of the derivatives are recorded in Accumulated other comprehensive income, a component of Stockholders’ equity. Any gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Product purchases when the hedged transactions occur. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Non-cash change in the fair value of derivatives. We regularly use crude oil swaps in hedging the variability in the sales price of butanes, which may result in hedge ineffectiveness from time to time. During the six months ended June 30, 2003, we did not recognize any losses from the ineffective portions of our hedges. Overall, our hedges are expected to continue to be “highly effective” under SFAS 133 in the future.

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

Outstanding Equity Hedge Positions and the Associated Basis for 2003. The following table details our hedge positions as of July 31, 2003. In order to determine the hedged price to the particular operating region, deduct the basis differential from the NYMEX price. The prices for NGLs do not include the cost of the hedges of approximately $465,000.

Product	Quantity and NYMEX or Settlement Price	Hedge of Basis Differential
Natural gas	50,000 MMbtu per day with an average price of $3.94 per MMbtu.	Mid-Continent – 20,000 MMbtu per day with an average basis price of ($0.15) per MMbtu.

	20,000 MMbtu per day with a minimum price of $3.50 per MMbtu and an average maximum price of $4.43 per MMbtu.	Permian – 5,000 MMbtu per day with an average basis price of ($0.13) per MMbtu.
		Rocky Mountain – 45,000 MMbtu per day with an average basis price of ($0.78) per MMbtu.

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

Butanes	50,000 Barrels of crude oil per month. Floor at $24.00 per barrel. (Crude oil is used as a surrogate for butanes).	Not Applicable

Propane	100,000 Barrels per month. Average minimum and maximum price of $0.37 per gallon and $0.50 per gallon, respectively.	Not Applicable

Ethane	75,000 Barrels per month. Average minimum and maximum price of $0.25 per gallon and $0.37 per gallon, respectively.	Not Applicable

Outstanding Equity Hedge Positions and the Associated Basis for 2004. The following table details our hedge positions as of July 31, 2003. In order to determine the hedged price to the particular operating region, deduct the basis differential from the NYMEX price. The prices for NGLs do not include the cost of the hedges of approximately $339,000.

Product	Quantity and NYMEX or Settlement Price	Hedge of Basis Differential
Natural gas	30,000 MMbtu per day with a minimum price of $4.00 per MMbtu and an average maximum price of $8.88 per MMbtu.	Mid-Continent – 25,000 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.

Crude Oil	25,000 Barrels of crude oil per month with a minimum price of $22.00 per barrel and an average maximum price of $30.15 per barrel.	Not Applicable

Butanes	25,000 Barrels of crude oil per month. Floor at $22.00 per barrel. (Crude oil is used as a surrogate for butanes).	Not Applicable

Account balances related to equity and transportation hedging transactions at June 30, 2003 were $2.9 million in Current Assets from price risk management activities, $22.0 million in Current Liabilities from price risk management activities, $800,000 in Non-current assets from price risk management activities, $40,000 in Non-current liabilities from price risk management activities, ($6.8) million in Deferred income taxes payable, net, and a $11.8 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Shareholders’ Equity. Based on prices as of June 30, 2003, approximately $12.6 million of losses in Accumulated other comprehensive income will be reclassified to earnings in 2003 and $746,000 of gains in Accumulated other comprehensive income will be reclassified to earnings in 2004.

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

Fair value of contracts outstanding at December 31, 2002	$	63
Decrease in value due to change in price	(32,762			)
Increase in value due to new contracts entered into during the period	19,102
Losses realized during the period from existing and new contracts	2,329
Changes in fair value attributable to changes in valuation techniques	—
Fair value of contracts outstanding at June 30, 2003	$		(11,268	)

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

	Fair Value of Contracts at June 30, 2003
Source of Fair Value	Total Fair Value			Maturing In 2003			Maturing In 2004-2005		Maturing In 2006-2007			Maturing Thereafter
Exchange published prices	$	(17,728	)	$	(19,314	)	$	1,586	—			—
Other actively quoted prices (1)	10,774			9,681			1,101		$	(8	)	—
Other valuation methods (2)	(4,314		)	(5,501		)	1,187		—			—
Total fair value	$	(11,268	)	$	(15,134	)	$	3,874	$	(8	)	—

(1) Other actively quoted prices are derived from broker quotations, trade publications, and industry indices.

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

Foreign Currency Derivative Market Risk. As a normal part of our business, we enter into physical gas transactions which are payable in Canadian dollars. We enter into forward purchases and sales of Canadian dollars from time to time to fix the cost of our future Canadian dollar denominated natural gas purchase, sale, storage, and transportation obligations. This is done to protect marketing margins from adverse changes in the U.S. and Canadian dollar exchange rate between the

time the commitment for the payment obligation is made and the actual payment date of such obligation. As of June 30, 2003, the net notional value of such contracts was approximately $12.8 million in Canadian dollars, which approximates fair market value.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures.

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

Changes in internal controls over financial reporting.

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

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Western Gas Resources, Inc. and Lance Oil & Gas Company, Inc. v. Williams Production RMT Company., (Defendant), Civil Action No. CO2-10-394, District Court, County of Sheridan, Wyoming. As reported in our Form 10-Q for the quarter ended March 31, 2003, in October 2002, we filed a complaint for declaratory relief and damages related to a dispute arising under a development agreement and other agreements between the parties. We amended this complaint in July 2003 to assert additional contractual claims, and the Defendant responded with additional counterclaims seeking declaratory relief and damages. The dispute centers on Defendant’s acquisition of Barrett by merger consummated on August 2, 2001. We believe we were entitled to a preferential right to purchase certain properties of Barrett located in the Powder River Basin of Wyoming and that our consent was required prior to Barrett’s assignment of its interests in the Agreements to the Defendant. We also believe that Barrett (now Defendant) should no longer be the operator of these properties as a consequence of the merger transaction.

In the fourth quarter of 2002, the Defendant asserted breach of contract claims against us. The Defendant also claimed damages under its gathering agreement with us. We believe that the Defendant’s assertions are without merit. We have also asserted breach of contract claims against the Defendant for its operating practices. The parties began mediation of these issues in the first quarter of 2003. At this time, we are unable to predict the outcome of this litigation or the claims scheduled for mediation.

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

Wyoming Department of Revenue. As reported in our Form 10-Q for the quarter ended March 31, 2003, we The Wyoming Department of Revenue has conducted an audit of Lance Oil & Gas Company, Inc. for the period from January 1, 1998 through December 31, 1999. On March 24, 2003, the Department of Revenue notified us that it had assessed additional severance taxes and increased taxable value for ad valorem tax purposes. The additional severance and ad valorem taxes claimed by the Department of Revenue amount to $196,000 and $351,000, respectively, together with statutory interest. We believe that the Wyoming Department of Revenue claims are without merit and intend to vigorously contest their assessments. On April 23, 2003, we filed a Notice of Appeal with the Wyoming State Board of Equalization.

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

National Pipeline Mapping System. In July 2003, we received correspondence from the U.S. Department of Transportation regarding our failure to submit information for incorporation into the National Pipeline Mapping System within six months of enactment of the Pipeline Safety Improvement Act of 2002. We are working with the U.S. Department of Transportation Office of Pipeline Safety to supply the required information. We are unable to predict whether we will be subject to any fines or penalties under the Act, and what the amount of such fines would be if imposed.

Challenges to the Powder River Basin EIS. On May 1, 2003, two lawsuits were filed challenging the Federal Bureau of Land Management’s Record of Decision on the Environmental Impact Statement issued on April 30, 2003 as it relates to the State of Wyoming. The respective suits are Western Organization of Resource Councils vs. Kathleen Clarke et al., Case No. CV-03-70-BLG-RWA, U.S. District Court for the District of Montana and American Lands Alliance v. U.S. Bureau of Land Management et al., Case No. CV-03-71-BLG-RWA, U.S. District Court for the District of Montana.

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

Other Litigation. We are involved in various other litigation and administrative proceedings arising in the normal course of business. In the opinion of our management, any liabilities that may result from these claims will not, individually or in the aggregate, have a material adverse effect on our financial position or results of operations.

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 16, 2003:

Joseph E. Reid and Ward Sauvage were elected as Class Two Directors to serve until their terms expire in 2006 and until their successors have been elected. A total of 26,484,228 and 26,485,028 shares, respectively, were voted for and 3,679,148 and 3,678,348 shares, respectively, were withheld for Joseph E. Reid and Ward Sauvage. There were no broker non-votes or abstentions.

PricewaterhouseCoopers LLP appointment to serve as our independent auditors for the fiscal year ending December 31, 2003 was ratified. A total of 30,046,832 shares were voted for, 113,858 were voted against and there were 2,686 abstentions. There were no broker non-votes or abstentions

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)	Exhibits:

	Exhibit Number		Description

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

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

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

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

	31.1		Section 302 Certification of the Chief Executive Officer.

	31.2		Section 302 Certification of the Chief Financial Officer.

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


(b)	Reports on Form 8-K:

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

		•		Current Report on Form 8-K filed on May 20, 2003 (dated May 19, 2003) announcing the election of a new Chairman of the Board.

		•		Current Report on Form 8-K furnished on May 8, 2003 (dated May 8, 2003) announcing financial results for the quarter ending March 31, 2003.

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

SIGNATURES

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

	WESTERN GAS RESOURCES, INC.
	(Registrant)


Date: August 14, 2003	By:	/s/ PETER A. DEA
		Peter A. Dea
		Chief Executive Officer and President


Date: August 14, 2003	By:	/s/WILLIAM J. KRYSIAK
		William J. Krysiak
		Executive Vice President - Chief Financial Officer
		(Principal Financial and Accounting Officer)

Exhibit Index

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

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

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

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

31.1		Section 302 Certification of the Chief Executive Officer.

31.2		Section 302 Certification of the Chief Financial Officer.

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