Anadarko Petroleum 8-K/A Financial Statements and Exhibits

Exhibit 99.5

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Unaudited)

(Dollars in thousands, except share data)

ASSETS		June 30, 2006			December 31, 2005
Current assets:
Cash and cash equivalents	$	3,892		$	27,198
Trade accounts receivable, net		286,206			413,004
Margin deposits		16,744			31,217
Inventory		115,779			136,968
Assets from price risk management activities		50,253			48,988
Deferred tax asset		—			4,808
Other		20,081			14,010
Total current assets		492,955			676,193
Property and equipment:
Gas gathering, processing and transportation		1,365,944			1,290,278
Oil and gas properties and equipment (successful efforts method)		825,305			666,306
Construction in progress		450,189			286,641
		2,641,438			2,243,225
Less: Accumulated depreciation, depletion and amortization		(751,235	)		(684,904	)
Total property and equipment, net		1,890,203			1,558,321
Other assets:
Gas purchase contracts (net of accumulated amortization of $43,458 and $42,583, respectively)		30,450			32,071
Assets from price risk management activities		6,787			5,495
Investments in joint ventures		38,478			36,791
Other		28,730			25,763
Total other assets		104,445			100,120
TOTAL ASSETS	$	2,487,603		$	2,334,634
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	350,064		$	463,113
Accrued expenses		75,502			106,542
Liabilities from price risk management activities		24,111			34,343
Deferred tax liability		6,509			—
Dividends payable		5,699			5,660
Total current liabilities		461,885			609,658
Long-term debt		572,000			430,000
Liabilities from price risk management activities		3,080			—
Other long-term liabilities		67,682			66,427
Deferred income taxes, net		356,602			325,090
Total liabilities		1,461,249			1,431,175
Stockholders’ equity:
Common stock, par value $0.10; 100,000,000 shares authorized; 76,297,417 and 75,375,134 shares issued, respectively		7,628			7,565
Treasury stock, at cost; 50,032 common shares in treasury		(788	)		(788	)
Deferred compensation		—			(9,244	)
Additional paid-in capital		445,589			429,007
Retained earnings		564,699			471,860
Accumulated other comprehensive income		9,226			5,059
Total stockholders’ equity		1,026,354			903,459
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,487,603		$	2,334,634

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

1

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

	Six Months Ended June 30,
	2006			2005
Reconciliation of net income to net cash provided by operating activities:
Net income	$	104,231		$	57,335
Add income items that do not affect operating cash flows:
Depreciation, depletion and amortization		71,286			59,877
Loss on sale of assets		1,024			27
Deferred income taxes		44,900			19,775
Excess tax benefits from share-based payment awards		(2,379	)		—
Non-cash change in fair value of derivatives		(5,465	)		17,614
Compensation expense from restricted stock and stock options		11,637			926
Other non-cash items, net		(587	)		(1,532	)
Adjustments to working capital to arrive at net cash provided by operating activities:
Decrease in trade accounts receivable		123,555			71,601
(Increase) decrease in margin deposits		3,957			(8,946	)
Decrease in product inventory		22,457			1,933
(Increase) in other current assets		(18,267	)		(11,379	)
(Increase) in other assets and liabilities, net		(962	)		(565	)
(Decrease) in accounts payable		(84,504	)		(57,156	)
Increase (decrease) in accrued expenses		(5,219	)		10,592
Net cash provided by operating activities		265,664			160,102
Cash flows from investing activities:
Purchases of property and equipment, including acquisitions		(399,351	)		(193,112	)
Distributions from equity investees		—			613
Proceeds from the disposition of property and equipment		1,255			1,411
Net cash used in investing activities		(398,096	)		(191,088	)
Cash flows from financing activities:
Net proceeds from exercise of common stock options		10,321			2,735
Excess tax benefits from share-based payment awards		2,379			—
Change in outstanding checks		(34,207	)		6,335
Borrowings on revolving credit facility		2,415,700			1,789,015
Payments on revolving credit facility		(2,273,700	)		(1,754,015	)
Borrowings on long-term debt		—			25,000
Payments on long-term debt		—			(25,000	)
Debt issue costs paid		(14	)		(40	)
Dividends paid		(11,353	)		(7,396	)
Net cash provided by financing activities		109,126			36,634
Net increase (decrease) in cash and cash equivalents		(23,306	)		5,648
Cash and cash equivalents at beginning of period		27,198			390
Cash and cash equivalents at end of period	$	3,892		$	6,038

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

2

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,
	2006			2005			2006			2005
Revenues:
Sale of gas	$	576,716		$	678,087		$	1,348,377		$	1,374,306
Sale of natural gas liquids		171,986			149,481			339,402			282,450
Gathering, processing and transportation revenue		27,573			27,823			54,273			51,703
Price risk management activities		9,233			11,205			30,213			(9,043	)
Other		1,666			1,430			3,990			2,717
Total revenues		787,174			868,026			1,776,255			1,702,133
Costs and expenses:
Product purchases		592,861			707,516			1,368,993			1,414,870
Plant and transportation operating expense		29,963			26,831			62,179			54,530
Oil and gas exploration and production expense		35,909			24,059			64,427			48,955
Depreciation, depletion and amortization		35,924			30,799			71,286			59,877
Selling and administrative expense		21,296			17,536			41,144			30,096
(Earnings) from equity investments		(2,440	)		(2,246	)		(4,814	)		(4,380	)
Interest expense		5,419			4,033			8,604			7,553
Total costs and expenses		718,932			808,528			1,611,819			1,611,501
Income before taxes		68,242			59,498			164,436			90,632
Provision for income taxes:
Current		3,018			6,172			15,305			13,522
Deferred		22,855			15,697			44,900			19,775
Total provision for income taxes		25,873			21,869			60,205			33,297
Net income	$	42,369		$	37,629		$	104,231		$	57,335
Earnings per share of common stock	$	.56		$	.51		$	1.38		$	.77
Weighted average shares of common stock outstanding		75,459,422			74,234,424			75,269,376			74,191,346
Income attributable to common stock—assuming dilution	$	42,369		$	37,629		$	104,231		$	57,335
Earnings per share of common stock—assuming dilution	$	.55		$	.50		$	1.36		$	.76
Weighted average shares of common stock outstanding—assuming dilution		76,718,838			75,678,389			76,509,330			75,603,310

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

3

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(Dollars in thousands, except share amounts)

	Shares of Common Stock	Shares of Common Stock in Treasury	Common Stock		Treasury Stock			Deferred Compensation			Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income Net of Tax			Total Stock- holders’ Equity
Balance at December 31, 2005	75,375,134	50,032	$	7,565	$	(788	)	$	(9,244	)	$	429,007		$	471,860		$	5,059		$	903,459
Comprehensive income:
Net income, first six months of 2006	—	—		—		—			—			—			104,231			—			104,231
Translation adjustments	—	—		—		—			—			—			—			848			848
Other comprehensive income:
From equity investees	—	—		—		—			—			—			—			84			84
Reclassification adjustment for settled contracts	—	—		—		—			—			—			—			(4,822	)		(4,822	)
Changes in fair value of outstanding hedge positions	—	—		—		—			—			—			—			14,518			14,518
Change in estimated ineffectiveness	—	—		—		—			—			—			—			320			320
Fair value of new hedge positions	—	—		—		—			—			—			—			(6,781	)		(6,781	)
Change in accumulated derivative comprehensive income	—	—		—		—			—			—			—			3,235			3,235
Total comprehensive income, net of tax	—	—		—		—			—			—			—			—			108,398
Stock options exercised	625,600	—		63		—			—			10,258			—			—			10,321
Compensation expense from common stock options	296,683	—		—		—			—			7,853			—			—			7,853
Excess tax benefit related to stock options exercised	—	—		—		—			—			3,931			—			—			3,931
Effect of change in accounting principle	—	—		—		—			9,244			(9,244	)		—			—			—
Compensation expense from restricted stock	—	—		—		—			—			3,784			—			—			3,784
Dividends declared on common stock	—	—		—		—			—			—			(11,392	)		—			(11,392	)
Balance at June 30, 2006	76,297,417	50,032	$	7,628	$	(788	)	$	—		$	445,589		$	564,699		$	9,226		$	1,026,354

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

4

WESTERN GAS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1—GENERAL

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

The interim consolidated financial statements presented herein should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2005. Reference is also made to our 2005 Form 10-K for definitions of terms used in this quarterly report on Form 10-Q. The interim Consolidated Financial Statements as of June 30, 2006 and for the three-month and six month periods ended June 30, 2006 and 2005 included herein are unaudited but reflect, in the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to fairly state the results for such periods. The results of operations for the three and six months ended June 30, 2006 are not necessarily indicative of the results of operations expected for the year ended December 31, 2006.

Proposed Merger of our Company. On June 23, 2006, we announced that we had entered into a merger agreement with Anadarko Petroleum Corporation, or Anadarko, whereby it is proposed that we will be merged with a wholly owned subsidiary of Anadarko. Our stockholders will receive $61.00 per common share in cash in the merger. The merger agreement has been approved by each company’s Board of Directors and was filed with the SEC on Form 8-K. We have scheduled a special meeting of our stockholders for August 23, 2006 to vote on, adopt the merger agreement and approve the merger. The merger is also subject to the satisfaction of customary closing conditions, including the receipt of necessary regulatory and governmental approvals. The merger will be completed as soon as practicable following satisfaction of these conditions, which could be as early as the end of August 2006. Should the merger be completed, our common stock will be de-listed with the New York Stock Exchange, or NYSE, and we will file a Form 15 with the SEC to deregister our common stock. Certain of our directors, officers and other stockholders, who collectively hold approximately 17.3 percent of Western’s outstanding shares, have entered into agreements to vote in favor of the merger.

The closing of our proposed merger would be an event of default under our revolving credit facility, which would entitle the lenders to terminate their commitments and demand payment of all outstanding and unpaid amounts there under. Further, our master shelf agreement contains cross default provisions, which would be triggered by the default under the revolving credit facility. Therefore, on or prior to the closing of the merger, the acquirer must renegotiate these agreements or repay all amounts due under them. Also, the closing of our proposed merger is also an event of default under some of our operating leases, which will entitle our counterparties to terminate their commitments and require a return of the related equipment. Therefore, upon the closing of the merger, the acquirer must renegotiate these agreements.

This Form 10-Q includes discussion regarding events that will or may trigger or occur upon completion of the merger. If the merger is not completed these events will not occur. In addition, the timing of the completion of the merger will affect the timing of these events. See also the first paragraph under Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the effect of the proposed merger on certain forward-looking statements included in this Form 10-Q.

Earnings Per Share of Common Stock.Earnings per share of common stock are computed by dividing net income by the weighted average shares of common stock outstanding. Earnings per share of common stock—assuming dilution is computed by dividing net income by the weighted average shares of common stock outstanding as adjusted for potential common shares.

The following table presents the dividends declared by us on our common stock (dollars in thousands, except per share amounts):

	Quarter Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Total dividends declared	$	5,750	$	3,732	$	11,392	$	7,425
Dividends declared per share of common stock	$	0.075	$	0.05	$	0.15	$	0.10

5

Common stock options granted 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,
	2006	2005	2006	2005
Weighted average shares of common stock outstanding	75,459,422	74,234,424	75,269,376	74,191,346
Potential common shares from common stock options	1,259,416	1,443,965	1,239,954	1,411,964
Weighted average shares of common stock outstanding—assuming dilution	76,718,838	75,678,389	76,509,330	75,603,310

The calculation of fully diluted earnings per share reflects potential common shares, if dilutive.

Accumulated Other Comprehensive Income.Included in Accumulated other comprehensive income at June 30, 2006 were unrealized gains of $5.9 million, which is net of $3.4 million of deferred taxes, from the fair value of derivatives designated as cash flow hedges and unrealized gains of $848,000, which is net of $486,000 of deferred taxes, as a result of cumulative foreign currency translation adjustments.

The gains currently reflected in Accumulated other comprehensive income from the fair value of derivatives designated as cash flow hedges will be reclassified to earnings as the hedged gas or NGLs are sold. Based on the prices for our products on June 30, 2006, approximately $5.9 million of gains in Accumulated other comprehensive income will be reclassified to earnings, of which $1.4 million will be reclassified in the remainder of 2006.

Revenue Recognition. In the Gas Gathering, Processing and Treating segment, we recognize revenue for our services at the time the service is performed. We record revenue from our gas and NGL marketing activities, including sales of our equity production, upon transfer of title. In accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes as Defined in Issue No. 02-3”, we record revenue on our physical gas and NGL marketing activities on a gross basis versus sales net of purchases basis because we obtain title to all the gas and NGLs that we buy including third-party purchases, bear the risk of loss and credit exposure on these transactions, and it is our intention upon entering these contracts to take physical delivery of the product. Gas imbalances on our production are accounted for using the sales method. Gas imbalances on our production at June 30, 2006 and 2005 were immaterial. For our marketing activities we utilize mark-to-market accounting for our derivatives. In the Transportation segment, we realize revenue on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline.

At its September 2005 meeting, the Emerging Issues Task Force, or EITF, of the FASB approved Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” This Issue addresses the question of when it is appropriate to measure non-monetary purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. EITF 04-13 requires that two or more exchange transactions involving inventory with the same counterparty that are entered into in contemplation of one another should be combined for the purposes of evaluating the effect of APB Opinion No. 29, “Accounting for Nonmonetary Transactions”. This EITF is effective for transactions entered into or modified in the first interim or annual period beginning after March 15, 2006, which for us was the quarter ended June 30, 2006. To the extent transactions are required to be netted, this results in a reduction of revenues and costs by an equal amount, but the netting has no impact on net income or cash flows.

In order to minimize transportation costs or make product available at a location of our customer’s preference, from time to time, we will enter into arrangements to buy product from a party at one location and arrange to sell a like quantity of product to this same party at another location. In accordance with EITF 04-13, these transactions are required to be reported on a sales net of purchases basis. For the quarter and six months ended June 30, 2006, we reduced revenues and product purchases by $31.2 million for transactions which were entered into concurrently and with the intent to buy and sell like quantities with the same counterparty at different locations and at market prices at those locations.

6

Supplementary Cash Flow Information. Interest paid was $14.6 million and $11.7 million for the six months ended June 30, 2006 and 2005, respectively. A total of $16.5 million and $11.0 million was paid in income taxes in the six months ended June 30, 2006 and 2005, respectively. Asset retirement obligation assets and liabilities of $3.4 million and $7.7 million were recorded for the six months ended June 30, 2006 and 2005, respectively. The asset retirement and associated obligations are non-cash transactions for presentation on the Consolidated Statement of Cash Flows.

Property Acquisition. In March 2006, we acquired certain coal bed methane, or CBM, properties and related gathering assets in the Big George fairway of the Powder River Basin of Wyoming for an adjusted purchase price of $138.6 million. This acquisition was funded with amounts available under our revolving credit facility. The purchase price included the drilling rights on approximately 40,000 gross and net acres and 110 drilled wells. These properties had no production in the six months ended June 30, 2006 as approximately 70 of the drilled wells are currently dewatering and the remaining 40 wells are awaiting hookup.

NOTE 2—DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

A net gain was recognized in earnings through Sale of gas and Sale of natural gas liquids during the three and six months ended June 30, 2006 from hedging activities of $12.3 million and $20.8 million, respectively. A net loss was recognized in earnings through Sale of residue gas and Sale of natural gas liquids during the three and six months ended June 30, 2005 from hedging activities of $657,000 and $170,000, respectively.

In the second quarter of 2006, in order to properly align our hedged volumes of natural gas to our forecasted equity production, we discontinued hedge treatment on financial instruments for 30 MMcf per day of natural gas as the anticipated transaction is no longer probable. As a result, a pre-tax gain of $2.8 million was reclassified into earnings from Accumulated other comprehensive income.

NOTE 3—ADOPTION OF SFAS 123(R)

On January 1, 2006, we adopted Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment”, or SFAS 123(R), which requires the measurement and recognition of compensation expense for all share-based payment awards (including stock options) made to employees and directors based on estimated fair values. SFAS 123(R) supersedes our previous accounting under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”, or APB 25, for periods beginning in fiscal 2006. In March 2005, the SEC issued Staff Accounting Bulletin No. 107, or SAB 107, relating to SFAS 123(R). We considered the guidance of SAB 107 in our adoption of SFAS 123(R).

We adopted SFAS 123(R) using the modified prospective transition method, which requires the application of the accounting standard as of January 1, 2006. In accordance with the modified prospective transition method, our Consolidated Financial Statements for prior periods are not restated to reflect, and do not include, any impact of SFAS 123(R). We did not modify any outstanding stock options in anticipation of the adoption of SFAS 123(R). The effect of the change in accounting principle resulting from the adoption of SFAS 123(R) was recognized in our financial statements through the elimination of previously recognized deferred compensation costs, with offsetting amounts recorded in the Additional paid-in capital account within Stockholders’ equity.

Stock-based compensation expense recognized under SFAS 123(R) for the three and six months ended June 30, 2006 related to employee stock options, including compensation from our 2006 grants, is as presented in the following table.

(Amounts in thousands, except per share amounts)	Quarter ended June 30, 2006			Six Months ended June 30, 2006
Incremental stock-based compensation expense recognized through earnings	$	4,058		$	6,900
Related deferred income tax benefit		(419	)		(958	)
Decrease in net income		3,639			5,942
Decrease in earnings per share of common stock		0.05			0.08
Decrease in earnings per share of common stock—assuming dilution		0.05			0.08
Stock-based compensation expense capitalized	$	536		$	953

SFAS 123(R) requires us to estimate the fair value of stock options on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods in our Consolidated Statement of Operations. Prior to the adoption of SFAS 123(R), we accounted for stock-based awards to employees and directors using the intrinsic value method in accordance with APB 25 as then allowed under Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation”, or SFAS 123. Under the intrinsic value method, with the exception of the options granted under the Chief Executive Officer and President’s Plan and our restricted stock, no stock-based compensation expense had been recognized in our Consolidated Statement of Operations, because the exercise price of our stock options granted to employees and directors equaled the fair market value of the underlying stock at the date of grant.

7

Stock-based compensation expense to be recognized is based on the fair value of those share-based payment awards that are ultimately expected to vest during the period. Stock-based compensation expense recognized in our Consolidated Statement of Operations for the three and six months ended June 30, 2006 includes compensation expense for share-based payment awards granted in 2006 and granted prior to, but not yet vested, as of January 1, 2006. Compensation expense for the awards granted prior to January 1, 2006 is based on the grant date fair value estimated in accordance with the pro forma provisions of SFAS 123. Compensation expense for the share-based payment awards granted subsequent to December 31, 2005 was based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R). In conjunction with the adoption of SFAS 123(R), we continued our method of attributing the value of stock-based compensation using the straight-line single option method. As stock-based compensation expense recognized in the Consolidated Statement of Operations for the three and six months ended June 30, 2006 is based on awards ultimately expected to vest, it is reduced for estimated forfeitures. SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. At June 30, 2006, the compensation expense related to non-vested awards to be recognized in future periods totaled $23.0 million. The weighted average period over which this expense is expected to be recognized is 2.1 years; however, in connection with the proposed merger of Western with Anadarko, all outstanding options will fully vest and convert to the right to receive a cash payment from the acquirer at the closing of the transaction.

In accordance with the adoption of SFAS 123(R), we continue to use the Black-Scholes option pricing model for the valuation of share-based awards. Our determination of fair value of share-based payment awards on the date of grant using the Black-Scholes model is affected by our stock price as well as assumptions regarding variables, including, but not limited to, our expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise behaviors. In our estimate of the fair value of the share-based payment awards, we utilize historical volatility of our common stock over 250 weeks. In our opinion, the historical volatility and the Black-Scholes model provide an appropriate measure of the fair value of our employee stock options.

On November 10, 2005, the Financial Accounting Standards Board, issued FASB Staff Position, or FSP, No. 123(R)-3, “Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards.” This FSP allows us to take up to one year from the later of our initial adoption of SFAS 123(R) or the effective date of the FSP to evaluate the available transition alternative related to the accounting for the tax effects of share-based payment awards that are partially or fully-vested as of the adoption date. We have not yet elected which transition method we will utilize.

NOTE 4—SHARE BASED COMPENSATION

In the first six months of 2006, we granted our employees and directors options to purchase approximately 733,000 shares of our common stock at the market (as defined in the plans) based on the average closing price for the ten days prior to grant, and approximately 297,000 shares of restricted common stock. In the first six months of 2005, we granted options to purchase 916,000 shares of our common stock at the market based on the average closing price for the ten days prior to grant and approximately 362,000 shares of restricted common stock to our employees and directors. In all cases, the grant date was the date on which the grants were approved by our board of directors, or the date on which an employee commenced employment. 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 and on disqualifying dispositions of qualified stock options. For the six months ended June 30, 2006 and 2005, we recognized a tax benefit from our stock options of $3.9 million and $900,000, respectively.

The following is a summary of the options granted to purchase our common stock and the weighted average fair value per share of the options granted during the three and six months ended June 30, 2006 and 2005, respectively.

	Three Months Ended June 30,				Six Months Ended June 30,
2002 Plan	2006		2005		2006		2005
Options granted		10,465		54,200		16,665		137,200
Weighted average fair value per share	$	15.62	$	14.04	$	15.41	$	15.01
2005 Plan
Options granted		—		746,726		660,026		746,726
Weighted average fair value per share		—	$	13.25	$	19.17	$	13.25
2002 Directors Plan
Options granted		36,000		32,000		56,000		32,000
Weighted average fair value per share	$	19.80	$	14.79	$	19.68	$	14.79

8

During the six months ended June 30, 2006, the values for the options granted were estimated using the Black-Scholes option-pricing model with the following assumptions:

	2002 Plan	2005 Plan	2002 Directors Plan
Risk-free interest rate	5.26%	5.11%	5.34%
Expected life (in years)	4.6	4.6	4.6
Expected volatility	32%	32%	32%
Expected dividends (quarterly)	$0.075	$0.075	$0.075

The following table summarizes the number of stock options exercisable and available for grant under our benefit plans at June 30, 2006:

	Per Share Price Range		1997 Plan	1999 Plan	1999 Directors Plan	CEO Plan	2002 Plan	2002 Directors Plan	2005 Plan
Exercisable:
June 30, 2006	$	0.01–5.00	1,202	—	2,600	—	—	—	—
	$	5.01–10.00	1,800	—	—	—	—	—	—
	$	10.01-15.00	—	6,002	—	450,000	—	—	—
	$	15.01-20.00	—	286,384	—	—	441,008	56,000	—
	$	20.01-25.00	—	—	—	—	1,112	—	—
	$	25.01-30.00	—	30,366	—	—	175,587	18,667	—
	$	30.01-35.00	—	—	—	—	44,445	9,333	199,730
	$	35.01-40.00	—	—	—	—	291	—	834
		TOTAL	3,002	322,752	2,600	450,000	662,443	84,000	200,564
Available for Grant:
June 30, 2006			745,204	22,056	—	—	65,262	36,000	1,135,608

The following table summarizes the stock option activity related to options outstanding under our benefit plans during the six months ended June 30, 2006:

	Per Share Price Range		1997 Plan		1999 Plan		1999 Directors Plan		CEO Plan		2002 Plan		2002 Directors Plan	2005 Plan
Balance at 12/31/05			6,002		550,815		6,600		495,000		1,817,154		112,000	744,726
Granted	$	43.43-48.51	—		—		—		—		16,665		56,000	660,026
Exercised	$	2.76-35.71	(3,000	)	(138,868	)	(4,000	)	(45,000	)	(280,614	)	—	(39,765	)
Forfeited or expired	$	16.48-50.05	—		(4,968	)	—		—		(51,426	)	—	(40,360	)
Balance at 6/30/06			3,002		406,979		2,600		450,000		1,501,779		168,000	1,324,627
Weighted-average remaining contractual life (years)			1.6		4.8		0.8		3.3		5.0		5.2	6.0

The following table summarizes the weighted average option exercise price information under our benefit plans during the six months ended June 30, 2006:

	1997 Plan			1999 Plan			1999 Directors Plan			CEO Plan			2002 Plan			2002 Directors Plan		2005 Plan
Balance at December 31, 2005	$	5.11		$	19.32		$	2.76		$	12.51		$	24.31		$	24.99	$	31.86
Granted		—			—			—			—			48.38			49.44		43.43
Exercised		(5.82	)		(17.19	)		(2.76	)		(12.51	)		(21.44	)		—		(31.85	)
Forfeited or expired		—			(28.35	)		—			—			(26.30	)		—		(36.62	)
Balance at June 30, 2006	$	4.41		$	18.13		$	2.76		$	12.51		$	25.05		$	33.14	$	37.48

The total aggregate intrinsic value of options exercised in the first six months of 2006 was approximately $15.1 million. The total aggregate intrinsic value of exercisable options at June 30, 2006 was approximately $68.8 million and the total aggregate intrinsic value of outstanding options at June 30, 2006 was approximately $124.2 million.

The following table summarizes the status of the shares of outstanding restricted stock as of June 30, 2006 and changes during the six months ended June 30, 2006:

	2005 Plan
Balance at 12/31/05		377,565
Granted		296,683
Vested		(114,353	)
Forfeited or expired		(28,773	)
Balance at 6/30/06		531,122
Weighted-average grant date fair value per share of restricted stock	$	41.74
Weighted-average remaining contractual life (years)		1.4

9

As discussed in Note 3 above, prior to January 1, 2006, we were not required to record compensation expense for share-based payment awards. If we had recorded compensation expense in the second quarter and first six months of 2005 for grants under our stock-based compensation plans consistent with SFAS 123 (R), our Net income, 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,				Six Months Ended June 30,
	2005		2005		2005		2005
	As Reported		Pro Forma		As Reported		Pro Forma
Net income	$	37,629	$	35,062	$	57,335	$	53,089
Net income attributable to common stock		37,629		35,062		57,335		53,089
Earnings per share of common stock		0.51		0.47		0.77		0.71
Earnings per share of common stock—assuming dilution		0.50		0.46		0.76		0.70
Stock-based employee compensation cost, net of related tax effects, included in net income		412		—		585		—
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied	$	—	$	2,979	$	—	$	4,831

NOTE 5—SEGMENT REPORTING

We operate in four principal business segments, as follows: 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.

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

Substantially all gas flowing through our gathering, processing and treating facilities is supplied under three types of contracts providing for the purchase, gathering, treating or processing of natural gas for periods ranging from one month to 20 years or in some cases for the life of the oil and gas lease. Approximately 64% of our plant facilities’ gross margin, or revenues at the plant less product purchases, or 31% of our plant facilities’ throughput volume for the month of June 2006, was under percentage-of-proceeds agreements where we are typically responsible for the marketing of the gas and NGLs. Under these agreements, we pay producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs. Revenue is recognized under these contracts when the gas or NGLs are sold and the related product purchases are recorded as a percentage of the sale of the product.

Approximately 25% of our plant facilities’ gross margin, or 54% of our plant facilities’ throughput volume, for the month of June 2006 was under contracts that are primarily fee-based from which we receive a set fee for each Mcf of gas gathered and/or processed. This type of contract provides us with a steady revenue stream that is not dependent on commodity prices, except to the extent that low prices may cause a producer to delay drilling or shut in production. Revenue is recognized under these contracts when the related services are rendered.

10

Approximately 11% of our plant facilities’ gross margin, or 15% of our plant facilities’ throughput volume, for the month of June 2006 was under contracts with keepwhole arrangements or wellhead purchase contracts. Under the keepwhole contracts, we retain the NGLs recovered by the processing facility and keep the producers whole by returning to the producers at the tailgate of the plant an amount of gas equal on a Btu basis to the natural gas received at the plant inlet. The keepwhole component of the contracts permits us to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, we are adversely affected when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream. Revenue is recognized under these contracts when the product is sold.

Exploration and Production. The activities of the Exploration and Production segment, also referred to as upstream operations, primarily consist of 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 and remits to the Exploration and Production segment all of the proceeds from the sales of gas and a proportional share of transportation charges. Also included in this segment are our Canadian exploration and development operations, which are conducted through our wholly owned subsidiary Western Gas Resources Canada Company and which are immaterial for separate presentation.

Exploratory lease rentals and geological and geophysical costs are charged to expense as incurred. Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination of whether a well has found proved reserves is based on a process that relies on interpretations of available geological, geophysical, and engineering data. If an exploratory well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether proved reserves have been found only as long as: i) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made, and ii) drilling of additional exploratory wells is under way or firmly planned for the near future. If the drilling of additional exploratory wells in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired, and its costs are charged to expense.

The following table reflects the net changes in capitalized exploratory well costs during the six months ended June 30, 2006 (dollars in thousands).

	Six Months Ended June 30, 2006
Beginning balance at December 31, 2005	$	101,796
Additions to capitalized exploratory well costs pending the determination of proved reserves		68,216
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		(5,731	)
Capitalized exploratory well costs charged to expense		(342	)
Ending balance at June 30, 2006	$	163,938

Period end capitalized exploratory well costs (000s) and number of gross wells at June 30, 2006 are as follows:

	Exploratory Well Costs		Number of wells
Exploratory well costs capitalized for a period of one year or less	$	107,588	645
Exploratory well costs capitalized for a period of greater than one year		56,350	691
Total exploratory well costs capitalized at June 30, 2006	$	163,938	1,336

Substantially all of our exploratory wells that have been capitalized for a period greater than one year are located in the Powder River Basin. In this basin, we drill wells into various coal seams. After these wells are completed, lease-operating costs are incurred. In order to produce gas from the coal seams, a period of dewatering lasting from a few to thirty-six months, or in some cases longer, is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering, and to classify the reserves as proved. In order to accelerate the dewatering time, we drill additional exploratory wells in these areas.

11

Marketing. Our Marketing segment markets gas and NGLs extracted at our gathering, processing and treating facilities and produced from our Exploration and Production segment and buys and sells gas and NGLs in the United States and Canada from and to a variety of customers. In this segment, revenues for sales of product are recognized at the time the gas or NGLs are delivered to the customer and title passes. Revenues in this segment are sensitive to changes in the market prices of the underlying commodities. The marketing of products purchased from third-parties typically results in low operating margins relative to the sales price. We sell our products under agreements with varying terms and conditions in order to match seasonal and other changes in demand. Also included in this segment are our Canadian marketing operations, which are conducted through our wholly owned subsidiary WGR Canada, Inc. and which are immaterial for separate presentation.

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

Segment Information.The following tables set forth our segment information as of and for the three and six months ended June 30, 2006 and 2005 (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.

Quarter Ended June 30, 2006:

	Gas Gathering and Processing			Exploration and Production			Marketing		Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas and NGLs	$	710		$	3,232		$	731,995	$	460		$	—		$	—		$	736,397
Equity hedges		952			11,353			—		—			—			—			12,305
Gathering, processing and transportation revenue		25,654			—			—		1,919			—			—			27,573
Total revenues from unaffiliated customers		27,316			14,585			731,995		2,379			—			—			776,275
Inter-segment revenues		284,573			85,061			15,031		3,125			153			(387,943	)		—
Price risk management activities		(1,630	)		853			10,010		—			—			—			9,233
Interest income and Other, net		1,232			(13	)		10		1			20,112			(19,676	)		1,666
Total revenues		311,491			100,486			757,046		5,505			20,265			(407,619	)		787,174
Product purchases and operating expenses		243,231			48,680			752,794		1,794			155			(387,921	)		658,733
(Earnings) from joint ventures		(2,440	)		—			—		—			—			—			(2,440	)
Segment operating profit		70,700			51,806			4,252		3,711			20,110			(19,698	)		130,881
Depreciation, depletion and amortization		13,472			19,745			2		454			2,251			—			35,924
Selling and administrative expense		(1	)		(46	)		—		27			21,325			(9	)		21,296
Interest expense		—			—			299		(397	)		25,194			(19,677	)		5,419
Income before income taxes	$	57,229		$	32,107		$	3,951	$	3,627		$	(28,660	)	$	(12	)	$	68,242
Identifiable assets:
Property and equipment and other allocated assets	$	917,601		$	903,320		$	215,951	$	80,383		$	428,081		$	(96,211	)	$	2,449,125
Investment in joint ventures		32,073			—			—		1,221			1,128,509			(1,123,325	)		38,478
Total identifiable assets	$	949,674		$	903,320		$	215,951	$	81,604		$	1,556,590		$	(1,219,536	)	$	2,487,603

12

Quarter ended June 30, 2005

	Gas Gathering and Processing			Exploration and Production		Marketing		Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas and NGLs	$	959		$	3,040	$	823,816	$	409		$	—		$	—		$	828,224
Equity hedges		(1,035	)		378		—		—			—			—			(657	)
Gathering, processing and transportation revenue		26,154			—		—		1,669			—			—			27,823
Total revenues from unaffiliated customers		26,078			3,418		823,816		2,078			—			—			855,390
Inter-segment sales		300,326			78,376		24,940		3,353			10			(407,005	)		—
Price risk management activities		(37	)		—		11,242		—			—			—			11,205
Interest income and Other, net		1,089			122		21		—			12,656			(12,457	)		1,431
Total revenues		327,456			81,916		860,019		5,431			12,666			(419,462	)		868,026
Product purchases and operating expenses		278,758			34,403		849,780		2,429			—			(406,964	)		758,406
(Earnings) from joint ventures		(2,246	)		—		—		—			—			—			(2,246	)
Segment operating profit		50,944			47,513		10,239		3,002			12,666			(12,498	)		111,866
Depreciation, depletion and amortization		11,594			16,899		35		436			1,835			—			30,799
Selling and administrative expense		(213	)		61		—		151			17,546			(9	)		17,536
Interest expense		—			3		587		(194	)		16,094			(12,457	)		4,033
Income before income taxes	$	39,563		$	30,550	$	9,617	$	2,609		$	(22,809	)	$	(32	)	$	59,498
Identifiable assets:
Property and equipment and other allocated assets	$	763,801		$	553,848	$	150,722	$	74,958		$	399,644		$	(68,763	)	$	1,874,210
Investment in Joint Ventures		32,675			—		—		1,150			857,160			(854,901	)		36,084
Total identifiable assets	$	796,476		$	553,848	$	150,722	$	76,108		$	1,256,804		$	(923,664	)	$	1,910,294

Six months ended June 30, 2006

	Gas Gathering and Processing			Exploration and Production			Marketing		Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas and NGLs	$	1,009		$	6,143		$	1,658,341	$	1,462		$	—		$	—		$	1,666,955
Equity hedges		2,053			18,771			—		—									20,824
Gathering, processing and transportation revenue		50,516			—			—		3,757			—			—			54,273
Total revenues from unaffiliated customers		53,578			24,914			1,658,341		5,219			—			—			1,742,052
Inter-segment sales		617,272			186,587			41,849		6,467			268			(852,443	)		—
Price risk management activities		(1,755	)		(2,604	)		34,572		—			—			—			30,213
Interest income and Other, net		2,874			82			13		1			37,770			(36,750	)		3,990
Total revenues		671,969			208,979			1,734,775		11,687			38,038			(889,193	)		1,776,255
Product purchases and operating expense		549,850			89,036			1,705,265		3,930			273			(852,755	)		1,495,599
(Earnings) from joint ventures		(4,814	)		—			—		—			—			—			(4,814	)
Segment operating profit (loss)		126,933			119,943			29,510		7,757			37,765			(36,438	)		285,470
Depreciation, depletion and amortization		27,076			38,881			3		917			4,409			—			71,286
Selling and administrative expense		(4	)		740			—		292			40,133			(17	)		41,144
Interest expense		—			—			729		(709	)		45,333			(36,749	)		8,604
Income before income taxes	$	99,861		$	80,322		$	28,778	$	7,257		$	(52,110	)	$	328		$	164,436
Identifiable assets:
Property and equipment and other allocated assets	$	917,601		$	903,320		$	215,951	$	80,383		$	428,081		$	(96,211	)	$	2,449,125
Investment in Joint Ventures		32,073			—			—		1,221			1,128,509			(1,123,325	)		38,478
Total identifiable assets	$	949,674		$	903,320		$	215,951	$	81,604		$	1,556,590		$	(1,219,536	)	$	2,487,603

13

Six months ended June 30, 2005

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas and NGLs	$	781		$	7,075		$	1,647,915		$	1,154		$	—		$	—		$	1,656,925
Equity hedges		(1,774	)		1,604			—			—			—			—			(170	)
Gathering, processing and transportation revenue		48,446			(162	)		—			3,419			—			—			51,703
Total revenues from unaffiliated customers		47,453			8,517			1,647,915			4,573			—			—			1,708,458
Inter-segment sales		576,179			147,643			42,644			6,795			20			(773,281	)		—
Price risk management activities		(125	)		—			(8,918	)		—			—			—			(9,043	)
Interest income and Other, net		2,194			128			21			—			22,338			(21,963	)		2,718
Total revenues		625,701			156,288			1,681,662			11,368			22,358			(795,244	)		1,702,133
Product purchases and operating expenses		526,849			69,826			1,689,826			5,098			—			(773,244	)		1,518,355
(Earnings) from joint ventures		(4,380	)		—			—			—			—			—			(4,380	)
Segment operating profit (loss)		103,232			86,462			(8,164	)		6,270			22,358			(22,000	)		188,158
Depreciation, depletion and amortization		22,872			32,528			71			839			3,567			—			59,877
Selling and administrative expense		(182	)		61			—			148			30,089			(20	)		30,096
Interest expense		5			4			589			(348	)		29,266			(21,963	)		7,553
Income before income taxes	$	80,537		$	53,869		$	(8,824	)	$	5,631		$	(40,564	)	$	(17	)	$	90,632
Identifiable assets:
Property and equipment and other allocated assets	$	763,801		$	553,848		$	150,722		$	74,958		$	399,644		$	(68,763	)	$	1,874,210
Investment in Joint Ventures		32,675			—			—			1,150			857,160			(854,901	)		36,084
Total identifiable assets	$	796,476		$	553,848		$	150,722		$	76,108		$	1,256,804		$	(923,664	)	$	1,910,294

NOTE 6—LEGAL PROCEEDINGS

Doyle and Margaret M. Hartman, et al. v. Questar Exploration and Production Company et al. In the District Court of Sublette County, Wyoming, Civil Action No. 2006-6843. On March 31, 2006, the plaintiffs filed a complaint against a group of ten defendants, including our subsidiary Lance Oil & Gas Company, Inc. The plaintiffs claim that they hold a five percent net profits interest which they allege was created in 1954 and burdened certain oil and gas leases in the original federal Pinedale Unit in the Pinedale Anticline. The relief sought by the plaintiffs includes a declaration that they hold a valid, continuing net profits interest applicable to certain identified leases, enforcement of the net profits interest, compensatory damages, an accounting of the status of the net profits interest, and interest and penalties under the Wyoming Royalty Payment Act.

United States of America and ex rel. Jack J. Grynberg v. Western Gas Resources, Inc., et al., United States District Court, District of Colorado, Civil Action No. 97-D-1427.We, along with over 300 other natural gas companies, are defendants in litigation filed on September 30, 1997, in 72 separate actions filed by Mr. Grynberg on behalf of the federal government. The allegations made by Mr. Grynberg are that established gas measurement and royalty calculation practices improperly deprived the federal government of appropriate natural gas royalties and violate 31U.S.C. 3729(a)(7) of the False Claims Act. The cases have been consolidated to the United States District Court for the District of Wyoming. Discovery on the jurisdictional issues is being completed to determine if this matter qualifies as a qui tam, or class, action. The defendants’ joint Motion to Dismiss was argued before a special master on March 17 and 18, 2005 and, as a result thereof, the special master has recommended to the court that claims against several of the defendants, including Western, be dismissed. The recommendation is pending before the court.

14

Price, et al. v. Gas Pipelines, Western Gas Resources, Inc., et al., District Court, Stevens County, Kansas, Case No. 99-C-30.We are a defendant in litigation filed on September 23, 1999, along with numerous other natural gas companies, in which Mr. Price is claiming an under measurement of gas and Btu volumes throughout the country. We, along with other natural gas companies, filed a motion to dismiss for failure to state a claim. The court denied these motions to dismiss. The court denied plaintiff’s motion for certification as a class and, in the third quarter of 2003, the plaintiff amended and refiled for certification as a class. On May 12, 2003, Mr. Price filed a further claim,Will Price et al v. Western Gas Resources, Inc. et al., District Court, Stevens County, Kansas, Case No. 03C23, relating to certain matters previously removed from the foregoing action.

In re: Western States Wholesale Natural Gas Antitrust Litigation, J.P. Morgan Trust Company, National Association, in its Capacity as Trustee of FLI Liquidating Trust v. The Williams Companies, Inc., et al., United States District Court, District of Nevada, MDL 1566 CV-S-03-1431-PMP.On October 17, 2005, the plaintiff, in its capacity as the liquidating trustee of the successor in interest to Farmland Industries, Inc., filed an amended complaint, joining us and other defendants to this action, originally filed in the District Court of Wyandotte County, Kansas. The defendants removed the case to the U.S. District Court for the District of Kansas, following which the Judicial Panel on Multi District Litigation entered a transfer order centralizing the action in the U.S. District Court for the District of Nevada for coordinated and consolidated pretrial proceedings. On April 21, 2006, the plaintiff’s motion to remand to Kansas state court was denied. The complaint claims that the defendants violated the Kansas Restraint of Trade Act by reporting allegedly “misleading or knowingly inaccurate reports concerning trade information” to trade publications that compile and publish indices of natural gas prices for natural gas trading hubs throughout the United States. The complaint asserts that these alleged activities had the effect of increasing prices charged by the defendants for natural gas and preventing full and free competition. The plaintiff seeks to recover damages in the amount of the full consideration of its purchases of natural gas during the time period from January 1, 2000 through December 31, 2001, together with its costs of litigation including attorney’s fees.

Learjet, Inc., Cross Oil Refining & Marketing, Inc. Topeka Unified School District 501, on Behalf of Themselves and All Other Similarly Situated Direct Purchasers of Natural Gas in the State of Kansas v. Oneok, Inc. et al, In the District Court of Wyandotte County, Kansas, Civil Action No. 05-CV-1500. On November 4, 2005, the plaintiffs, on behalf of themselves and all others similarly situated, filed an amended Petition for Damages, joining us and other defendants to this action. The Petition claims that the defendants violated the Kansas Restraint of Trade Act by reporting allegedly “misleading or knowingly inaccurate reports concerning trade information” to trade publications that compile and publish indices of natural gas prices for natural gas trading hubs throughout the United States. The complaint asserts that the allegedly anticompetitive effect of the defendant’s actions was to artificially inflate the prices paid by the plaintiffs for natural gas. The plaintiffs are bringing the action as a class action on behalf of all persons and entities in Kansas who made direct purchases of natural gas, for their own use and or consumption, during the time period from January 1, 2000 through October 31, 2002. The plaintiffs are seeking judgment for the full consideration of their purchases of natural gas purchased during such time period, together with costs of litigation including attorney’s fees.

In the Matter of the Notice of Violation, Docket Number 3852-06, Issued to Lance Oil & Gas Company, Inc., Department of Environmental Quality, Water Quality Division, State of Wyoming.On January 26, 2006, we received a Notice of Violation issued by the State of Wyoming Department of Environmental Quality, Water Quality Division, for the un-permitted discharge of coal bed methane produced water at our Spotted Horse Facility in Campbell County. We have undertaken remedial steps to address the items contained in the Notice of Violation and, in May 2006, we paid a settlement in the amount of $100,000.

In the Matter of the Notice of Violation, WES-1252-0501, Environment Department, Air Quality Bureau, State of New Mexico. On March 6, 2006, we received a Notice of Violation pertaining to operations at our San Juan River Gas Plant located west of Farmington, New Mexico, containing two alleged violations. On April 4, 2006, we met with the Environment Department to discuss the notices and any potential monetary penalties. This matter is still pending.

In addition to the above claims, we are involved in various other litigation and administrative proceedings arising in the normal course of business. While the outcome of claims in litigation is inherently uncertain, and it is not possible to predict the ultimate outcome, we intend to vigorously contest the allegations in the previously described matters. 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 results of operations, financial position, or cash flows.

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NOTE 7—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 they become effective.

SFAS No. 155. In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments, an Amendment of SFAS No. 133 and No. 140”. This statement resolves issues addressed in SFAS Implementation Issue D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” This statement is effective in the annual period commencing after September 15, 2006. We do not believe that the adoption of this statement will have a material impact on our results of operation, financial position or cash flows.

EITF No. 06-3.At its May 2006 meeting, the Emerging Issues Task Force, or EITF, of the FASB approved Issue No. 06-3,“How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation).” The scope of this issue includes any tax assessed by a governmental authority that is imposed on a revenue producing transaction between a seller and a customer. This EITF is effective for periods beginning after December 15, 2006 and requires that the presentation of taxes on either a gross or net basis is an accounting policy decision that should be disclosed in the footnotes along with the amount of such taxes. The adoption of this EITF will not have a material impact on our results of operations, financial position or cash flows.

FIN No. 48. In July 2006, the FASB issued FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109.” This Interpretation provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding derecognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not expect that this Interpretation will have a material impact on our financial position, results of operations or cash flows.

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