Anadarko Petroleum 8-K/A Financial Statements and Exhibits

Exhibit 99.3

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2005. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control-Integrated Framework. Based on our assessment using those criteria, management concluded that, as of December 31, 2005, our internal control over financial reporting are effective.

We conduct a portion of our oil and gas operations through joint operating agreements with other companies. Under a portion of these joint operating agreements, the other company is the operator of the well and charges us a proportional share of the cost of the well and the on-going well operations. Under the agreements, we have the contractual right to audit the charges billed to us, but we do not have the contractual right or ability to dictate or modify the internal controls over financial reporting of these entities and do not have the ability, in practice, to assess those controls. Therefore, the internal controls over financial reporting at these operations have not been included in our assessment of the effectiveness of the Company’s internal control over financial reporting. These oil and gas operations are owned through undivided interests and are accounted for under the proportionate consolidation method in our consolidated financial statements. These properties had total property, plant and equipment assets and total revenues of $368 million and $269 million, respectively, representing 16% and 7% of our corresponding consolidated financial statement amounts, and 57% and 66% of our corresponding Exploration and Production Segment amounts, as of and for the year ended December 31, 2005.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

/s/ PETER A. DEA

Peter A. Dea

Chief Executive Officer and President

/s/ WILLIAM J. KRYSIAK

William J. Krysiak

Executive Vice President – Chief Financial Officer

(Principal Financial and Accounting Officer)

2

Report of Independent Registered Public Accounting Firm

To the Board of Directors and

Stockholders of Western Gas Resources, Inc.:

We have completed integrated audits of Western Gas Resources, Inc.’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005 and audits of its 2004 and 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Western Gas Resources, Inc. and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of computing depletion for oil and gas properties effective January 1, 2004, its method of accounting for asset retirement obligations effective January 1, 2003, and its method of testing long-lived assets for impairment in 2003.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established inInternal Control – Integrated Framework issued by COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the

3

company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded its oil and gas operations managed by other joint interest operators from its assessment of internal control over financial reporting as of December 31, 2005 because the Company does not have the ability to dictate or modify the controls of these entities and does not have the ability, in practice, to assess those controls. We have also excluded the internal controls over financial reporting at these oil and gas operations managed by other joint interest operators from our audit of internal control over financial reporting. These oil and gas operations are owned through undivided interests and are accounted for under the proportionate consolidation method in the Company’s consolidated financial statements. These properties had total property, plant and equipment assets and total revenues of $368 million and $269 million, respectively, representing 16% and 7% of the corresponding consolidated financial statement amounts, as of and for the year ended December 31, 2005.

PricewaterhouseCoopers LLP

Denver, Colorado

March 14, 2006

4

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(000s, except share data)

	December 31,
	2005			2004
ASSETS
Current assets:
Cash and cash equivalents	$	27,198		$	390
Trade accounts receivable, net		413,004			385,811
Margin deposits		31,217			7,939
Product inventory		136,968			94,604
Assets from price risk management activities		48,988			19,893
Deferred tax asset		4,808			17,947
Other		14,010			12,494
Total current assets		676,193			539,078
Property and equipment:
Gas gathering, processing and transportation		1,290,278			1,150,904
Oil and gas properties and equipment (successful efforts method)		666,306			495,314
Construction in progress		286,641			150,273
		2,243,225			1,796,491
Less: Accumulated depreciation, depletion and amortization		(684,904	)		(570,582	)
Total property and equipment, net		1,558,321			1,225,909
Other assets:
Gas purchase contracts (net of accumulated amortization of $42,580 and $38,937, respectively)		32,071			27,704
Assets from price risk management activities		5,495			249
Investments in joint ventures		36,791			35,729
Other		25,763			26,676
Total other assets		100,120			90,358
TOTAL ASSETS	$	2,334,634		$	1,855,345
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	463,113		$	400,672
Accrued expenses		106,542			60,472
Liabilities from price risk management activities		34,343			4,321
Dividends payable		5,660			3,704
Total current liabilities		609,658			469,169
Long-term debt		430,000			382,000
Liabilities from price risk management activities		—			180
Other long-term liabilities		66,427			51,827
Deferred income taxes, net		325,090			267,400
Total liabilities		1,431,175			1,170,576
Stockholders’ equity:
Common stock, par value $.10; 100,000,000 shares authorized; 75,375,134 and 68,271,802 shares issued, respectively		7,565			7,430
Treasury stock, at cost; 50,032 common shares in treasury		(788	)		(788	)
Deferred compensation		(9,244	)		—
Additional paid-in capital		429,007			392,437
Retained earnings		471,860			281,428
Accumulated other comprehensive income		5,059			4,262
Total stockholders’ equity		903,459			684,769
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,334,634		$	1,855,345

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

5

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(000s)

	Year Ended December 31,
	2005			2004			2003
Reconciliation of net income to net cash provided by operating activities:
Net income	$	207,474		$	127,759		$	87,935
Add income items that do not affect operating cash flows:
Depreciation, depletion and amortization		128,783			95,536			73,906
Deferred income taxes		80,413			71,200			51,351
Distributions (less than) or more than equity income, net		(1,081	)		127			1,076
Loss (gain) on the sale of property and equipment		510			1,288			(156	)
Non-cash change in fair value of derivatives		(1,808	)		(15,027	)		(6,976	)
Compensation expense from restricted stock and stock options		3,786			646			376
Cumulative effect of change in accounting principle		—			(4,714	)		6,724
Other non-cash items, net		873			2,112			1,430
Adjustments to working capital to arrive at net cash provided by operating activities:
(Increase) in trade accounts receivable		(27,639	)		(127,042	)		(21,730	)
(Increase) decrease in margin deposits		(23,278	)		159			14,010
(Increase) decrease in product inventory		(39,789	)		(22,215	)		(25,136	)
(Increase) decrease in other current assets		(40,340	)		1,553			8,869
(Increase) in other assets and liabilities, net		(1,161	)		(5,019	)		(359	)
Increase in accounts payable		26,980			65,905			55,689
Increase (decrease) in accrued expenses		82,374			16,891			(2,787	)
Net cash provided by operating activities		396,097			209,159			244,222
Cash flows from investing activities:
Purchases of property and equipment, including acquisitions		(451,273	)		(306,266	)		(188,318	)
Proceeds from the disposition of property and equipment		2,860			1,501			5,983
(Contributions to) or distributions from equity investees		(15	)		2,310			(14,750	)
Net cash used in investing activities		(448,428	)		(302,455	)		(197,085	)
Cash flows from financing activities:
Net proceeds from exercise of common stock options		16,014			9,993			5,027
Change in outstanding checks		31,360			31,581			4,510
Payments for the redemption of preferred stock		—			(1,930	)		(1,201	)
Borrowings under long-term debt		25,000			100,000			25,000
Payments on long-term debt		(35,000	)		(190,000	)		(43,333	)
Borrowings under revolving credit facility		5,112,065			2,654,230			1,022,300
Payments on revolving credit facility		(5,054,065	)		(2,521,230	)		(1,024,900	)
Debt issue costs paid		(1,149	)		(2,086	)		(1,861	)
Dividends paid		(15,086	)		(12,988	)		(13,875	)
Net cash provided by (used in) financing activities		79,139			67,570			(28,333	)
Net increase (decrease) in cash and cash equivalents		26,808			(25,726	)		18,804
Cash and cash equivalents at beginning of year		390			26,116			7,312
Cash and cash equivalents at end of year	$	27,198		$	390		$	26,116

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

6

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(000s, except share and per share amounts)

	Year Ended December 31,
	2005			2004			2003
Revenues:
Sale of gas	$	3,200,886		$	2,518,281		$	2,463,757
Sale of natural gas liquids		654,842			450,761			346,109
Gathering, processing and transportation		106,366			90,874			83,672
Price risk management activities		(9,445	)		20,051			(16,386	)
Other		6,009			3,201			2,599
Total revenues		3,958,658			3,083,168			2,879,751
Costs and expenses:
Product purchases		3,210,200			2,540,799			2,456,441
Plant and transportation operating expense		115,524			95,868			88,344
Oil and gas exploration and production costs		113,594			77,608			52,245
Depreciation, depletion and amortization		128,783			95,536			73,906
Selling and administrative expense		60,113			52,246			40,423
(Gain) loss on sale of assets		510			1,288			(156	)
Loss from early extinguishment of debt		—			10,662			—
Earnings from equity investments		(10,133	)		(7,124	)		(7,356	)
Interest expense		17,597			19,562			25,627
Total costs and expenses		3,636,188			2,886,445			2,729,474
Income before income taxes		322,470			196,723			150,277
Provision for income taxes:
Current		34,583			2,478			4,267
Deferred		80,413			71,200			51,351
Total provision for income taxes		114,996			73,678			55,618
Income before cumulative effect of change in accounting principle		207,474			123,045			94,659
Cumulative effect of change in accounting principle, net of tax (expense) or benefit of ($2,710) and $3,967, respectively		—			4,714			(6,724	)
Net income	$	207,474		$	127,759		$	87,935
Preferred stock requirements		—			(835	)		(6,841	)
Income attributable to common stock	$	207,474		$	126,924		$	81,094
Earnings per share of common stock before cumulative effect of change in accounting principle	$	2.79		$	1.68		$	1.32
Cumulative effect of change in accounting principle per share of common stock, net of tax	$	—		$	0.07		$	(0.10	)
Earnings per share of common stock	$	2.79		$	1.75		$	1.22
Weighted average shares of common stock outstanding		74,409,704			72,419,980			66,412,229
Income attributable to common stock - assuming dilution	$	207,474		$	126,924		$	87,935
Earnings per share of common stock - assuming dilution	$	2.72		$	1.73		$	1.18
Weighted average shares of common stock outstanding - assuming dilution		76,200,131			73,494,747			74,694,420

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

7

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(000s, except share amounts)

	$2.625 Cumulative Convertible Preferred Stock		Shares of Common Stock	Shares of Common Stock in Treasury	Shares of $2.28 Cumulative Preferred Stock in Treasury			Common Stock		Treasury Stock			Unearned Compensation			Additional Paid-In Capital			Retained (Deficit) Earnings			Accumulated Other Comprehensive Income (Loss) Net of Tax			Notes Receivable from Key Employees			Total Stock- holders’ Equity
Balance at December 31, 2002	2,760,000		66,155,222	50,032	$	276		$	3,329	$	(788	)	$	—		$	381,066		$	92,773		$	(2,812	)	$	(295	)	$	473,549
Comprehensive income:
Net income, 2003	—		—	—		—			—		—			—			—			87,935			—			—			87,935
Translation adjustments	—		—	—		—			—		—			—			—			—			1,237			—			1,237
Reclassification adjustment for settled contracts	—		—	—		—			—		—			—			—			—			5,272			—			5,272
Changes in fair value of outstanding hedge positions	—		—	—		—			—		—			—			—			—			127			—			127
Fair value of new hedge positions	—		—	—		—			—		—			—			—			—			(2,266	)		—			(2,266	)
Change in accumulated derivative comprehensive income	—		—	—		—			—		—			—			—			—			3,133			—			3,133
Total comprehensive income, net of tax	—		—	—		—			—		—			—			—			—			—			—			92,305
Stock options exercised	—		415,180	—		—			24		—			—			3,570			—			—			—			3,594
Effect of re-priced options	—		—	—		—			—		—			—			904			—			—			—			904
Officer loans forgiven	—		—	—		—			—		—			—			—			—			—			295			295
Tax benefit related to stock options exercised	—		—	—		—			—		—			—			727			—			—			—			727
Dividends declared on common stock	—		—	—		—			—		—			—			—			(6,684	)		—			—			(6,684	)
Dividends declared on $2.625 cumulative convertible preferred stock	—		—	—		—			—		—			—			—			(6,783	)		—			—			(6,783	)
Conversion of $2.625 cumulative convertible preferred stock	(676,344	)	1,701,400	—		(68	)		85		—			—			(17	)		—			—			—			—
Redemption of $2.625 cumulative convertible preferred stock	(23,656	)	—	—		(2	)		—		—			—			(1,231	)		32			—			—			(1,201	)
Balance at December 31, 2003	2,060,000		68,271,802	50,032	$	206		$	3,438	$	(788	)	$	—		$	385,019		$	167,273		$	1,558		$	—		$	556,706
Comprehensive income:
Net income, 2004	—		—	—		—			—		—			—			—			127,759			—			—			127,759
Translation adjustments	—		—	—		—			—		—			—			—			—			816			—			816
Other comprehensive income from equity affiliates	—		—	—		—			—		—			—			—			—			(780	)		—			(780	)
Reclassification adjustment for settled contracts	—		—	—		—			—		—			—			—			—			2,266			—			2,266
Changes in fair value of outstanding hedge positions	—		—	—		—			—		—			—			—			—			16			—			16
Reduction due to estimated ineffectiveness	—		—	—		—			—		—			—			—			—			(8	)		—			(8	)
Fair value of new hedge positions	—		—	—		—			—		—			—			—			—			394			—			394
Change in accumulated derivative comprehensive income	—		—	—		—			—		—			—			—			—			2,668			—			2,668
Total comprehensive income, net of tax	—		—	—		—			—		—			—			—			—			—			—			130,463
Stock options exercised	—		681,703	—		—			54		—			—			9,939			—			—			—			9,993
Effect of re-priced options	—		—	—		—			—		—			—			646			—			—			—			646
Tax benefit related to stock options exercised	—		—	—		—			—		—			—			2,527			—			—			—			2,527
Dividends declared on common stock	—		—	—		—			—		—			—			—			(12,847	)		—			—			(12,847	)
Dividends declared on $2.625 cumulative convertible preferred stock	—		—	—		—			—		—			—			—			(789	)		—			—			(789	)
Conversion of $2.625 cumulative convertible preferred stock	(2,024,404	)	5,125,228	—		(204	)		255		—			—			(93	)		—			—			—			(42	)
Redemption of $2.625 cumulative convertible preferred stock	(35,596	)	—	—		(2	)		—		—			—			(1,918	)		32			—			—			(1,888	)
Two for one common stock split	—		—	—		—			3,683		—			—			(3,683	)		—			—			—			—
Balance at December 31, 2004	—		74,078,733	50,032	$	—		$	7,430	$	(788	)	$	—		$	392,437		$	281,428		$	4,262		$	—		$	684,769
Comprehensive income:
Net income, 2005	—		—	—		—			—		—			—			—			207,474			—			—			207,474
Translation adjustments	—		—	—		—			—		—			—			—			—			(1,585	)		—			(1,585	)
Other comprehensive income from equity affiliates	—		—	—		—			—		—			—			—			—			138			—			138
Reclassification adjustment for settled contracts	—		—	—		—			—		—			—			—			—			(394	)		—			(394	)
Changes in fair value of outstanding hedge positions	—		—	—		—			—		—			—			—			—			—			—			—
Reduction due to estimated ineffectiveness	—		—	—		—			—		—			—			—			—			(15	)		—			(15	)
Fair value of new hedge positions	—		—	—		—			—		—			—			—			—			2,653			—			2,653
Change in accumulated derivative comprehensive income	—		—	—		—			—		—			—			—			—			2,244			—			2,244
Total comprehensive income, net of tax	—		—	—		—			—		—			—			—			—			—			—			208,271
Stock options exercised	—		918,836	—		—			98		—			—			15,916			—			—			—			16,014
Effect of re-priced options	—		—	—		—			—		—			—			1,376			—			—			—			1,376
Tax benefit related to stock options exercised	—		—	—		—			—		—			—			7,661			—			—			—			7,661
Unearned compensation on restricted stock	—		377,565	—		—			37		—			(9,244	)		11,617			—			—			—			2,410
Dividends declared on common stock	—		—	—		—			—		—			—			—			(17,042	)		—			—			(17,042	)
Balance at December 31, 2005	—		75,375,134	50,032	$	—		$	7,565	$	(788	)	$	(9,244	)	$	429,007		$	471,860		$	5,059		$	—		$	903,459

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

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WESTERN GAS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - NATURE OF ORGANIZATION

Western Gas Resources, Inc. (the “Company”) explores for, develops and produces, gathers, processes and treats, transports and markets natural gas and natural gas liquids (“NGLs”). In its upstream operations, the Company explores for, develops and produces natural gas reserves primarily in the Rocky Mountain region of the United States and Canada. In its midstream operations the Company designs, constructs, owns and operates natural gas gathering, processing and treating facilities and owns and operates regulated transportation facilities, and offers marketing services in order to provide its customers with a broad range of services from the wellhead to the sales delivery point. The Company’s midstream operations are conducted in major gas-producing basins in the Rocky Mountain, Mid-Continent and Southwestern regions of the United States.

In 2002, the Company adopted a Stockholder Rights Plan under which Series A Junior Participating Preferred Stock Purchase Rights were distributed as a dividend at the rate of one-half of one right for each share of its common stock held by stockholders of record as of the close of business on April 9, 2002. Each right entitles the Stockholder, subject to adjustment, to buy one unit consisting of 1/100^th of a share of a new series of preferred stock for $180 per unit. The right generally will be exercisable only if a person or group acquires beneficial ownership of 15% or more of the Company’s then outstanding common stock or commences a tender or exchange offer upon consummation of which a person or group would beneficially own 15% or more of its then outstanding common stock. The rights will expire on March 22, 2011.

In June 2004, the Company completed a two-for-one split of its common stock, which was distributed in the form of a stock dividend. Stockholders of the Company’s common stock received one additional share for every share of common stock held on the record date of June 4, 2004. After the stock split, each share of common stock outstanding or thereafter issued includes or will include one-half of a Series A Junior Participating Preferred Stock purchase right. The Company has restated its financial information to reflect this split for all periods presented.

In February 1994, the Company issued 2,760,000 shares of $2.625 Cumulative Convertible Preferred Stock with a liquidation preference of $50 per share, at a public offering price of $50 per share, redeemable at the Company’s option on or after February 16, 1997 and convertible at the option of the holder into Common Stock at a per share conversion price of $19.88. In November 2003 and in December 2003, the Company issued notices of redemption for approximately 700,000 and 800,000 shares, respectively, of its $2.625 cumulative convertible preferred stock at the liquidation preference plus 0.525% premium. In relation to the notice of redemption issued in November 2003, in December 2003 a total of 1,701,400 common shares were issued and $1.2 million was paid in cash to complete the redemption. In relation to the notice of redemption issued in December 2003, in January 2004 a total of 1,979,244 common shares were issued and $672,000 was paid in cash. In March 2004, the Company issued an additional notice of redemption for the remaining 1,260,000 shares of its $2.625 cumulative convertible preferred stock. In April 2004, the Company issued an additional 3,113,582 shares of common stock to holders who elected to convert their shares and paid $391,000 in cash proceeds to complete this redemption. After these redemptions, the $2.625 cumulative convertible preferred stock was delisted from trading on the New York Stock Exchange and was deregistered by the Securities and Exchange Commission.

Significant Projects and Asset Divestitures

Acquisition of San Juan Properties.In October 2004, the Company acquired oil and gas assets in the San Juan Basin of New Mexico for approximately $82.2 million, plus assumed liabilities. The purchase also included related gathering systems, which are connected to the Company’s San Juan River plant. In connection with this acquisition, the Company increased Oil and gas properties and equipment by $72.6 million and increased Gas gathering, processing and transportation by $13.3 million.

Acquisition and Disposition of Gathering Systems. In February 2005, the Company acquired certain natural gas gathering and processing assets in the eastern Greater Green River Basin for approximately $28.3 million.

In February 2003, the Company acquired several gathering systems in Wyoming, primarily located in the Greater 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 did not integrate directly into the Company’s existing systems, and accordingly these systems were sold in 2003. During the year ended December 31, 2003, the income generated by the assets sold was immaterial.

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Powder River Basin Coal Bed Methane.The Company continues to develop its Powder River Basin coal bed methane reserves and expand the associated gathering system. During the years ended December 31, 2005, 2004 and 2003, the Company expended approximately $174.5 million, $106.9 million and $71.0 million, respectively, on this project.

Greater Green River Basin.The Company’s assets in southwest Wyoming and northwest Colorado include the Granger and Lincoln Road facilities (collectively the “Granger Complex”), the Company’s 50% equity interest in Rendezvous Gas Services, L.L.C. (“Rendezvous”), the Patrick Draw facility, the Red Desert facility, the Wamsutter gathering system, and production from the Jonah Field, Pinedale Anticline and Sand Wash areas. During the years ended December 31, 2005, 2004 and 2003, the Company expended approximately $108.2 million, $63.9 million and $102.5 million, respectively, in this area.

Subsequent Events

In February 2006, the Company signed an agreement for the purchase of certain CBM properties and related gathering assets in the Big George fairway of the Powder River Basin of Wyoming from an undisclosed seller for approximately $136.7 million before adjustments. Closing is expected to occur on or before March 15, 2006 and will be funded with amounts available under the Company’s revolving credit facility. The purchase price includes the drilling rights on approximately 40,000 gross and net acres and 110 drilled wells. Approximately 70 of the drilled wells are currently dewatering and the remaining 40 wells are awaiting hookup.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies followed by the Company and its wholly owned subsidiaries are presented here to assist the reader in evaluating the financial information contained herein. The Company’s accounting policies are in accordance with generally accepted accounting principles.

Principles of Consolidation. The consolidated financial statements include the accounts of the Company and the Company’s wholly owned subsidiaries. All material inter-company transactions have been eliminated in consolidation. The Company’s interest in certain non-controlled investments is accounted for by the equity method. The Company proportionately consolidates less than 100 percent-owned affiliate partnerships in which the company has an undivided interest.

Inventories.The cost of gas and NGL inventories are determined by the weighted average cost method on a location-by-location basis. Gas and NGL inventory which has been sold forward is accounted for on a specific identification basis. Product inventory is accounted for at the lower of cost or market and includes $127.4 million and $88.8 million of gas and $2.9 million and $1.6 million of NGLs at December 31, 2005 and 2004, respectively.

Property and Equipment.Property and equipment is recorded at cost, including capitalized interest. Interest incurred during the construction period of new projects is capitalized and amortized over the life of the associated assets. Repair and maintenance of property and equipment is expensed as incurred.

Depreciation 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 the life of the equipment or the hydrocarbon reserves serviced by the equipment.

In connection with the adoption of SFAS No. 143 on January 1, 2003, a review was completed of the Company’s operating assets. As a result of this evaluation, the operating lives and salvage values of the associated equipment was reevaluated, and the Company extended the useful life of many of its operating assets and adjusted the estimated salvage value of its operating equipment. These adjustments resulted in an approximate $10.7 million, or $0.10 per share of common stock—assuming dilution, decrease in depreciation, depletion and amortization in the year ended December 31, 2003, from the expense calculated using the previous useful lives. The adjustments to the salvage value and depreciable lives of the Company’s assets were treated as a revision of an estimate and were accounted for on a prospective basis.

In December 2004, the Company placed into service a new 200 MMcf per day processing facility adjacent to its Granger Complex. This facility straddles a third-party regulated pipeline and processes its gas to meet pipeline specifications. The facility’s capacity is contractually committed to this service, and the contract for processing this gas requires a monthly charge to be paid by the pipeline regardless of the amount of gas processed. These fees total approximately $2.2 million per year and the contract has a remaining term of nine years. In accordance with EITF 01-08, “Determining Whether an Arrangement Contains a Lease”, facilities that are built to provide services to one specific customer should be evaluated for potential treatment as capital leases. The Company has determined that accounting for this contract as a capital lease is appropriate. On the Consolidated Balance Sheet, at December 31, 2005 and 2004 related to this transaction, the Company had receivables of $20.6 million and $22.4 million, respectively, in Other assets for the fixed portion of the non-current future lease payments plus the unguaranteed residual value at the end of the lease term and $2.2 million for

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both years in Other Current assets. The Company also had deferred revenue on the Consolidated Balance Sheet at December 31, 2005 and 2004 totaling $15.7 million and $17.8 million, respectively, in Other long-term liabilities for the non-current deferred revenue and $2.0 million for both years in Accrued expenses for the current portion.

Oil and Gas Properties and Equipment.The Company follows the successful efforts method of accounting for oil and gas exploration and production activities. Acquisition costs, development costs and successful exploration costs are capitalized. Upon surrender or impairment of undeveloped properties, the original cost is charged against income. Developed and undeveloped leaseholds with proved reserves are depleted by the units-of-production method based on estimated proved reserves. Development costs and related equipment are depleted and depreciated by the units-of-production method based on estimated proved developed reserves.

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 years ended December 31, 2005, 2004 and 2003 (000s).

	2005			2004			2003
Beginning balance at January 1,	$	48,546		$	25,083		$	18,795
Additions to capitalized exploratory well costs pending the determination of proved reserves		66,954			30,683			12,804
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		(11,857	)		(6,900	)		(4,655	)
Capitalized exploratory well costs charged to expense		(1,847	)		(320	)		(1,861	)
Ending balance at December 31,	$	101,796		$	48,546		$	25,083

Period end capitalized exploratory well costs (000s) and number of gross wells at December 31, 2005:

			Number of wells
Exploratory well costs capitalized for a period of one year or less	$	66,874	426
Exploratory well costs capitalized for a period of between one and two years		20,900	288
Exploratory well costs capitalized for a period of between two and three years		5,935	72
Exploratory well costs capitalized for a period of between three and four years		5,467	96
Exploratory well costs capitalized for a period of more than four years		2,620	99
Total exploratory well costs capitalized at December 31, 2005	$	101,796	981

Substantially all of the Company’s exploratory wells that have been capitalized for a period greater than one year are located in the Powder River Basin. In this basin, the Company drills wells into various coal seams. These wells are completed and lease-operating costs are being 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, the Company drills additional exploratory wells in these areas.

Effective January 1, 2004, the Company redefined the asset groupings for the calculation of depreciation and depletion on its oil and gas properties from a well-by-well basis to a field wide basis for each of the Jonah, Pinedale and Sand Wash fields and to a grouping of all wells drilled into related coal seams for the Powder River Basin. This change resulted in an increase in Depreciation, depletion and amortization expense of $4.9 million in 2004. The change in the depreciation and depletion methodology is treated as a change in accounting principle. Accordingly, the Accumulated depreciation, depletion and amortization for these assets has been recalculated under the new methodology. The cumulative effect of the change in depreciation and depletion methodology for the year ended

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December 31, 2004 was a benefit of $4.7 million, net of tax and is presented in the Consolidated Statement of Operations under the caption Cumulative effect of change in accounting principle, net of tax.

Income Taxes.Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. These temporary differences are determined and accounted for in accordance with SFAS No. 109, “Accounting for Income Taxes.”

Foreign Currency Adjustments.The Company has two subsidiaries in Canada. The functional currency of these subsidiaries is the Canadian dollar. The assets and liabilities associated with these subsidiaries are translated into U.S. dollars at the exchange rate as of the balance sheet date and revenues and expenses at the weighted-average of exchange rates in effect during each reporting period. The translation change for the years ended December 31, 2005, 2004 and 2003 were ($1.6) million, $816,000 and $1.2 million, respectively, net of tax, included as a separate component in Stockholders’ equity.

Revenue Recognition.In the Gas Gathering, Processing and Treating segment, the Company recognizes revenue for its services at the time the service is performed. The Company records revenue from its gas and NGL marketing activities, including sales of the Company’s 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”, the Company records revenue on its physical gas and NGL marketing activities on a gross basis versus sales net of purchases basis because it obtains title to all the gas and NGLs that it buys including third-party purchases, bears the risk of loss and credit exposure on these transactions, and it is the Company’s intention upon entering these contracts to take physical delivery of the product. Gas imbalances on the Company’s production are accounted for using the sales method. Gas imbalances on the Company’s production at December 31, 2005 and 2004 are immaterial. For its marketing activities the Company utilizes mark-to-market accounting for its derivatives. In the Transportation segment, the Company realizes 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. See additional discussion in “Note 9 – Business Segments and Related Information”.

In order to minimize transportation costs or make product available at a location of the customer’s preference, from time to time, the Company 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 will be required to be reported on a sales net of purchases basis. This EITF is effective for transactions entered into or modified after March 15, 2006. To the extent transactions are required to be netted, it will result in a reduction of revenues and costs by an equal amount, but will have no impact on net income or cash flows. For the years ended December 31, 2005, 2004 and 2003, the Company recorded revenues of $148.7 million, $92.6 million and $95.5 million, respectively, and product purchases of $140.8 million, $86.7 million and $84.2 million, respectively, for transactions which were entered into concurrently and with the intent to buy and sell like quantities with the same counter party at different locations and at market prices at those locations.

Accounting for Derivative Instruments and Hedging Activities. The Company recognizes the change in the market value of all derivatives as either assets or liabilities in the statement of financial position, and measures those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction. See additional discussion in “Note 4- Commodity Risk Management”

Comprehensive Income.Accumulated other comprehensive income is reported as a separate component of Stockholders’ equity. Accumulated other comprehensive income includes cumulative translation adjustments for foreign currency transactions and the change in fair market value of cash flow hedges. The Company’s accumulated gains on cash flow hedges at December 31, 2005 totaled $2.7 million and will be reclassified into earnings during 2006. These items are separately reported on the Consolidated Statement of Changes in Stockholders’ Equity.

Impairment of Long-Lived Assets.The Company reviews its long-lived assets whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company’s assets are evaluated at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets. In order to determine whether an impairment exists, the Company compares its net book value of the asset to the undiscounted expected future net cash flows, primarily determined by applying future prices estimated by management over the shorter of the lives of the facilities or the reserves supporting the facilities or oil and gas properties. If an impairment exists, write-downs of assets are based upon the fair market value of the asset, usually based on expected future net cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset. For unevaluated oil and gas properties, the Company annually reviews its development plans and drilling history in that area to determine if an impairment of those properties is warranted.

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The Company reviews its assets at the plant facility, the related group of plant facilities or the oil and gas producing field or producing coal seam level. Prior to 2003, the Company completed its impairment analysis on its oil and gas producing properties on an individual well-by-well basis. In the fourth quarter of 2003, the Company conducted a review of its oil and gas producing properties, which included an evaluation of the geologic formations and production history for the Company’s producing properties. This review indicated that the cash flows from individual wells in its operating areas were not largely independent of the cash flows of other wells producing in the same field or coal seam. As a result of this review, the Company redefined the asset groupings to a field wide analysis for impairment for the Jonah, Pinedale and Sand Wash Basins and a grouping of all wells drilled into related coal seams for the Powder River Basin. These asset groupings were used to determine if any impairment was necessary for the years ended December 31, 2005, 2004 and 2003, and it was determined that none of the asset groups were impaired.

Asset Retirement Obligations.The Company accounts for asset retirement obligations in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), which was adopted by the Company on January 1, 2003. SFAS 143 requires the Company to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Under the provisions of SFAS 143, asset retirement obligations are capitalized as part of the carrying value of the long-lived asset. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense through depreciation or depletion of the asset. The majority of the Company’s asset retirement obligations relate to dismantling plants and related facilities and reclaiming the sites and plugging and abandoning oil and gas wells. The Company adopted SFAS No. 143 on January 1, 2003 and recorded an $11.5 million increase to Property and equipment, a $4.4 million increase to Accumulated depreciation, depletion and amortization, a $17.8 million increase to Other long-term liabilities and a $6.7 million non-cash, 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 years ended December 31, 2005 and 2004 (000’s):

	2005			2004
Asset retirement obligation as of January 1	$	32,664		$	20,644
Liability accrued upon capital expenditures		13,315			3,562
Changes due to revisions of estimated retirement costs		1,472			7,262
Liability settled		(539	)		(139	)
Accretion of discount expense		2,940			1,335
Asset retirement obligation as of December 31	$	49,852		$	32,664

Earnings Per Share of Common Stock.Earnings per share of common stock are computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding. In addition, earnings per share of common stock—assuming dilution is computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding as adjusted for potential common shares. Income attributable to common stock is net income less preferred stock dividends. The following table presents the dividends declared by the Company for each class of its outstanding equity securities (000’s, except per share amounts):

	Year Ended December 31,
	2005		2004		2003
Common Stock	$	17,042	$	12,847	$	6,684
Preferred Stock		—		835		6,783
Total Dividends Declared	$	17,042	$	13,682	$	13,467
Dividends Declared Per Share:
Common Stock	$	0.22	$	0.18	$	0.10
Preferred Stock		—	$	0.81	$	2.82

Common stock options, unvested restricted stock granted and, until the final conversion or redemption in April 2004, the Company’s $2.625 cumulative convertible preferred stock are potential common shares. The following is a reconciliation of the weighted average shares of common stock outstanding to the weighted average common shares outstanding – assuming dilution. The share information presented reflects the two-for-one common stock split completed in 2004.

	Year Ended December 31,
	2005	2004	2003
Weighted average shares of common stock outstanding	74,409,704	72,419,980	66,412,229
Potential common shares from:
Common stock options	1,790,427	1,074,767	1,413,353
$2.625 Cumulative Convertible Preferred Stock	—	—	6,868,838
Weighted average shares of common stock outstanding - assuming dilution	76,200,131	73,494,747	74,694,420

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The calculation of fully diluted earnings per share reflects potential common shares, if dilutive, and any related preferred dividends.

Concentration of Credit Risk.Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of trade accounts receivable and over-the-counter (“OTC”) swaps and options. The risk related to trade accounts receivable is limited due to the large number of entities comprising the Company’s customer base and their dispersion across geographic locations. The Company records its trade accounts receivable at the invoiced amount, which does not include interest. The risk related to OTC swaps and options is limited due to the investment grade nature of the Company’s counter-parties and the ability of the Company to clear many of its OTC transactions through the New York Mercantile Exchange (“NYMEX”). For contracts cleared on the NYMEX, the NYMEX guarantees payment or delivery.

The Company continually monitors and reviews the credit exposure to its marketing counter parties. In the second half of 2005, the prices of natural gas and NGLs, and therefore the Company’s credit exposures, increased significantly. Additionally, as a result of the damage in the Gulf States caused by hurricanes Katrina and Rita, several of the Company’s counterparties experienced a significant amount of damage to their operating assets. In September 2005, one of the Company’s customers, a utility serving the New Orleans area, filed for bankruptcy protection under Chapter 11 of the Bankruptcy Code. At the time of the bankruptcy filing, the Company had an outstanding account receivable from this utility of $4.1 million. In the third quarter of 2005, the Company reserved $800,000 against this amount, which represents its best estimate of the current market value of this receivable. During 2004 and 2003, the Company did not increase its allowance for doubtful accounts. The Company records an allowance for doubtful accounts on a specific identification basis, and the balance in the allowance for doubtful accounts was $829,000 and $648,000, respectively, at December 31, 2005 and 2004.

Cash and Cash Equivalents.Cash and cash equivalents includes all cash balances and highly liquid investments with an original maturity of three months or less.

Supplementary Cash Flow Information.Interest paid, including capitalized interest, was $28.2 million, $22.3 million, and $28.0 million, respectively, for the years ended December 31, 2005, 2004 and 2003. Capitalized interest associated with construction of new projects was $7.7 million, $2.5 million and $1.8 million, respectively, for the years ended December 31, 2005, 2004 and 2003. Income taxes paid were $35.7 million, $9.4 million and $11.1 million, respectively, for the years ended December 31, 2005, 2004 and 2003. At December 31, 2005 and 2004, lease receivables of $22.6 million and $24.6 million, respectively, and unearned revenue liabilities of $17.7 million and $19.8 million, respectively, were recorded for the lease of the Granger 200MMcf per day straddle plant. Asset retirement obligation assets of $14.8 million and $10.7 million were recorded for capitalized assets and asset retirement obligation liabilities of $17.2 million and $12.1 million were recorded for the years ending December 31, 2005 and 2004, respectively. At December 31, 2005 and 2004, the Company had outstanding disbursements to vendors and producers totaling $97.8 million and $66.4 million, respectively, which were reclassified to Accounts payable. The change in outstanding disbursements to vendors and producers is presented as a component of Cash flows from financing activities in the Statement of Cash Flows.

The Company enters into derivative contracts to mitigate the impact of changes in commodity prices on the results of its operations. As these contracts are considered a key component of the Company’s operations, the Company classifies the cash flows related to these contracts in Net cash provided by operating activities on the Consolidated Statement of Cash Flows.

Stock Compensation.As permitted under SFAS No. 123, “Accounting for Stock-Based Compensation”, the Company has 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”. The Company has complied with the pro forma disclosure requirements of SFAS No. 123 as required under the pronouncement. The Company realizes 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. For the years ended December 31, 2005 and 2004, this tax benefit of $7.7 million and $2.5 million, respectively, was credited to Additional paid-in capital.

The Company had options covering 27,000 and 49,438 common shares outstanding at December 31, 2004 and 2003, respectively, which were treated as re-priced options and had no such options outstanding at December 31, 2005. The Company is required to record compensation expense (if not previously accrued) equal to the number of unexercised re-priced options multiplied by the amount by which its stock price at the end of any quarter exceeds $10.5021 per share. Based on the Company’s per share stock price at December 31, 2005, 2004 and 2003 of $47.09, $29.25 and $23.63, respectively; expense of $506,000, $310,000 and $529,000 was recorded in the years ended December 31, 2005, 2004 and 2003, respectively.

In 2005, the Company granted 383,000 shares of restricted common stock to its employees. In conjunction with the grant of restricted common stock, the Company will record as compensation expense over the three-year vesting period, the value of the restricted common stock on the date of grant. Accordingly, the Company recorded compensation expense of $2.4 million related to its restricted stock in the year ended December 31, 2005.

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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 the Company’s common stock granted during the years ended December 31, 2005, 2004 and 2003, respectively.

	Year Ended December 31,
	2005	2004	2003
1999 Stock Option Plan	—	140,876	—
2002 Stock Option Plan	157,750	956,841	1,129,900
2002 Directors’ Plan	32,000	32,000	32,000
2005 Plan	746,726	—	—
Total options granted	936,476	1,129,717	1,161,900

The following is a summary of the weighted average fair value per share of the options granted during the years ended December 31, 2005, 2004 and 2003, respectively.

	Year Ended December 31,
	2005		2004		2003
1999 Stock Option Plan		—	$	13.12		—
2002 Stock Option Plan	$	15.44	$	13.09	$	9.77
2002 Directors’ Plan	$	14.79	$	12.13	$	10.70
2005 Plan	$	13.25		—		—

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

	1999 Stock Option Plan					2002 Stock Option Plan									2002 Directors’ Plan									2005 Stock Option Plan
	2005	2004			2003	2005			2004			2003			2005			2004			2003			2005			2004	2003
Risk-free interest rate	—		3.74	%	—		4.37	%		3.77	%		3.47	%		4.38	%		4.46	%		2.59	%		4.27	%	—	—
Expected life (in years)	—		7		—		7			7			7			7			7			7			6		—	—
Expected volatility	—		39	%	—		37	%		39	%		53	%		37	%		40	%		54	%		37	%	—	—
Expected dividends (quarterly)	—	$	0.05		—	$	0.05		$	0.05		$	0.025		$	0.05		$	0.05		$	0.025		$	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 the Company had recorded compensation expense for its grants under its stock-based compensation plans consistent with the fair value method under this pronouncement, the Company’s 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 (000s, except per share amounts):

	2005				2004				2003
	As Reported		Pro forma		As Reported		Pro forma		As Reported		Pro forma
Net income	$	207,474	$	199,328	$	127,759	$	122,597	$	87,935	$	84,495
Net income attributable to common stock		207,474		199,328		126,924		121,762		81,094		77,654
Earnings per share of common stock		2.79		2.68		1.75		1.68		1.22		1.17
Earnings per share of common stock - assuming dilution		2.72		2.63		1.73		1.67		1.18		1.14
Stock-based employee compensation cost, net of related tax effects, included in net income	$	2,238		N/A	$	428		N/A	$	576		N/A
Stock-based employee compensation cost, net of related tax effects, includable in net income if the fair value based method had been applied		N/A	$	10,384		N/A	$	5,590		N/A	$	4,016

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The fair market value of the options at grant date is amortized over the appropriate vesting period for purposes of calculating compensation expense.

Use of Estimates and Significant Risks.The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management 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, including depletion, during the reporting period. Therefore, the reported amounts of the Company’s assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. These estimates are evaluated on an ongoing basis, utilizing historical experience, consultation with experts and other methods considered reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the estimates used. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

The Company is subject to a number of risks inherent in the industry in which it operates, including price volatility, counterparty credit risk, the success of its drilling programs and other gas supply. The Company’s financial condition, results of operations and cash flows will depend significantly upon the prices received for gas and NGLs. These prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond the control of the Company. In addition, the Company must continually connect new wells to its gathering systems in order to maintain or increase throughput levels to offset natural declines in dedicated volumes. The number of new wells drilled by the Company and other producers will depend upon, among other factors, prices for gas and oil, the drilling budgets of third-party producers, the energy and tax policies of the federal and state governments, the pace at which permits required for drilling and production operations are obtained, and the availability of foreign oil and gas, none of which are within the Company’s control.

Recently Issued Accounting Pronouncements.

SFAS No. 123(R).SFAS No. 123(R), “Share Based Payment”was issued in December 2004 and must be adopted no later than annual periods beginning after June 15, 2005. This pronouncement requires companies to expense the fair value of employee stock options and other forms of stock based compensation. Currently, the Company is complying with the pro forma disclosure requirements of SFAS No. 123,“Accounting for Stock Based Compensation” which are included in “Note 2 – Summary of Significant Accounting Policies to Consolidated Financial Statements”.

Effective January 1, 2006, the Company will adopt Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment,” (“SFAS 123(R)”) which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors including employee stock options and employee stock purchases related to the Employee Stock Purchase Plan (“employee stock purchases”) based on estimated fair values. SFAS 123(R) supersedes the Company’s previous accounting under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) for periods beginning in fiscal 2006. In March 2005, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 107 (“SAB 107”) relating to SFAS 123(R). The Company will apply the provisions of SAB 107 in its adoption of SFAS 123(R).

The Company will adopt SFAS 123(R) using the modified prospective transition method, which requires the application of the accounting standard as of January 1, 2006, the first day of the Company’s fiscal year 2006. The Company’s Consolidated Financial Statements as of and for the three months ended March 31, 2006 will reflect the impact of SFAS 123(R). In accordance with the modified prospective transition method, the Company’s Consolidated Financial Statements for prior periods will not be restated to reflect, and will not include, any impact of SFAS 123(R). Stock-based compensation expense to be recognized under SFAS 123(R) for the three months ended March 31, 2006 will be approximately $2.5 million for stock-based compensation expense related to employee stock options.

SFAS 123(R) requires companies to estimate the fair value of share-based payment awards 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 the Company’s Consolidated Statement of Operations. Prior to the adoption of SFAS 123(R), the Company accounted for stock-based awards to employees and directors using the intrinsic value method in accordance with APB 25 as allowed under Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). Under the intrinsic value method, with the exception of the Chief Executive Officer and President’s Plan, no stock-based compensation expense had been recognized in the Company’s Consolidated Statement of Operations, since the exercise price of the Company’s stock options granted to employees and directors equaled the fair market value of the underlying stock at the date of grant.

Stock-based compensation expense to be recognized is based on the value of the portion of share-based payment awards that is ultimately expected to vest during the period. Stock-based compensation expense to be recognized in the Company’s Consolidated

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Statement of Operations for the first quarter of fiscal 2006 will include compensation expense for share-based payment awards granted prior to, but not yet vested as of January 1, 2006. This expense will be 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 will be 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), the Company will continue its 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 first quarter of fiscal 2006 will be based on awards ultimately expected to vest, it will be 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. In the Company’s pro forma information required under SFAS 123, presented in Note 2 under the heading “Stock Compensation”, for the periods prior to fiscal 2006, the Company also estimated compensation expense based on awards ultimately expected to vest.

In accordance with the adoption of SFAS 123(R), the Company will continue to use the Black-Scholes option pricing model (“Black-Scholes model”) for the valuation of share-based awards. The Company’s determination of fair value of share-based payment awards on the date of grant using the Black-Scholes model is affected by the Company’s stock price as well as assumptions regarding variables, including, but not limited to the Company’s expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise behaviors. In management’s opinion, the Black-Scholes model provides an accurate measure of the fair value of the Company’s employee stock options.

On November 10, 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position No. FAS 123(R)-3 “Transition Election Related to Accounting for Tax Effects of Share-Based Payment Awards” (“FSP”). This FSP allows the Company to take up to one year from the later of its initial adoption of SFAS 123(R) or the effective date of the FSP to evaluate the available transition alternatives related to the accounting for the tax effects of share-based payment awards. Accordingly, the Company is considering the alternatives and has not yet elected a transition method.

SFAS No. 151.SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4”was issued in November 2004 and is effective for the Company for inventory costs incurred in fiscal years beginning after June 15, 2005, and will be applied prospectively. SFAS No. 151 amends APB Opinion No. 43, Chapter 4, “Inventory Pricing” to clarify the accounting for abnormal amounts of costs and the allocation of fixed production overheads. The Company believes that the adoption of SFAS No. 151 will not affect its earnings, financial position or cash flows.

EITF No. 04-13.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 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”.

In order to minimize transportation costs or make product available at a location of our customer’s preference, from time to time, the Company 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 will be required to be reported on a sales net of purchases basis. This EITF is effective for transactions entered into or modified after March 15, 2006. To the extent transactions are required to be netted, it will result in a reduction of revenues and costs by an equal amount, but will have no impact on net income or cash flows.

In accordance with EITF 03-11, the Company records revenue on these transactions on a gross basis versus sales net of purchases basis because the Company obtains title to the product that it buys, bears the risk of loss, credit and performance exposure on these transactions, and takes physical delivery of the product. For the years ended December 31, 2005, 2004 and 2003, the Company recorded revenues of $148.7 million, $92.6 million and $95.5 million, respectively, and product purchases of $140.8 million, $86.7 million and $84.2 million, respectively, for transactions which were entered into concurrently and with the intent to buy and sell like quantities with the same counter party at different locations and at market prices at those locations.

FASB Interpretation No. 47.FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143”, or FIN 47, was issued in March 2005 and is effective for fiscal periods ending after December 15, 2005. FIN 47 clarifies the term “conditional asset retirement obligation” as used in FASB Statement 143, “Accounting for Asset Retirement Obligations”. Conditional asset retirement obligations as used in FASB Statement 143 refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform an asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Accordingly, an entity is required to recognize a liability for the fair

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value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. When sufficient information exists, uncertainty about the timing and (or) method of settlement should be factored into the measurement of the liability. The Company adopted this interpretation in the fourth quarter of 2005 and the adoption did not have a material impact on its results of operation, financial position or cash flows.

NOTE 3 - RELATED PARTIES

From time to time, the Company enters into joint ventures and partnerships in order to reduce risk, create strategic alliances and to establish itself in oil and gas producing basins in the United States. It is our policy that all transactions entered into by the Company with its related parties are consummated in the ordinary course of business and on terms that would be comparable to those obtained from third parties.

Fort Union. Fort Union Gas Gathering, L.L.C. (“Fort Union”), owns a gathering pipeline and treater in the Powder River Basin. At December 31, 2005 and 2004, the Company owned an approximate 15% and 13% interest, respectively, in Fort Union and is the construction manager and field operator. The Company accounts for its investment in this entity under the equity method of accounting as it has significant influence over the operations of this entity. Construction and expansions of the gathering header and treating system were project financed by Fort Union. At December 31, 2005, Fort Union had total project financing debt outstanding of $29.2 million. 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 the Company’s guarantee of $4.3 million of the debt of Fort Union. This guarantee is not reflected on the Consolidated Balance Sheet.

The Company has entered into long-term agreements for firm gathering services on 83 MMcf per day of capacity for $0.14 per Mcf on Fort Union. The Company acts as field operator of Fort Union and charges a monthly overhead fee to cover such services. In 2005, 2004 and 2003, the Company received overhead fees from Fort Union totaling $11,000, $43,000 and $(2,000), respectively, and the Company paid to Fort Union a total of $7.2 million, $5.0 million and $6.4 million for gathering services, respectively. At December 31, 2005 and 2004, the Company had a net amount due to Fort Union of $663,500 and $7,000, respectively. At December 31, 2005, the Company’s investment in Fort Union totaled $5.4 million and is included in Investments in joint ventures on the Consolidated Balance Sheet.

Rendezvous. At December 31, 2005 and 2004, the Company owned a 50% interest in Rendezvous Gas Services, L.L.C., (“Rendezvous”) and the Company serves as field operator of its systems. Rendezvous was formed in 2001 to gather gas for the Company and other third parties along the Pinedale Anticline for blending or processing at either the Company’s Granger Complex or at a third-party owned processing facility. The Granger Complex utilizes Rendezvous to deliver significant volumes of gas contractually dedicated to the Granger Complex for processing or blending. In December 2005, approximately 76% of the gas processed or blended at the Granger Complex was delivered to the facility by Rendezvous. The other 50% owner in Rendezvous is a large utility with oil and gas production and gathering and processing assets in the same area. At December 31, 2005, the Company had a total of $31.4 million invested in this venture and it is accounted for under the equity method of accounting. The investment is included in Investments in joint ventures on the Consolidated Balance Sheet. The Company charges a monthly overhead fee to act as field operator of Rendezvous and an overhead charge for capital projects it constructs on behalf of the venture. In 2005 and 2004, the Company received overhead fees as field operator from Rendezvous totaling $100,000 for both years and overhead fees on capital projects totaling $24,800 and $42,800, respectively. In 2005 and 2004, the Company paid to Rendezvous a total of $7.4 million and $3.9 million, respectively, for gathering services. At December 31, 2005 and 2004, the Company had a net amount due to Rendezvous of $501,000 and $1.2 million, respectively.

Officer Transactions. In prior years, the Company had entered into agreements committing the Company to loan to certain key employees an amount sufficient to exercise their options as each portion of their options vests under the Key Employees’ Incentive Stock Option Plan. The loan and accrued interest were to be forgiven if the employee was continually employed by the Company and upon a resolution of the board of directors. At December 31, 2002, loans related to 55,000 shares of common stock totaling $295,000 were outstanding under these programs. Pursuant to the terms of an agreement entered into in 2001, these loans were forgiven in May 2003. As of December 31, 2003, there were no loans outstanding under these programs and the program is no longer in effect. In prior years, the Company had accrued for the forgiveness of this loan. In October 2001, the Company’s former Chief Executive Officer and President retired. The Company had entered into a consulting agreement with this executive providing for a payment of $175,000 that was made in May 2003.

NOTE 4 - COMMODITY RISK MANAGEMENT

Risk Management Activities.The Company’s commodity price risk management program has two primary objectives. The first goal is to preserve and enhance the value of its 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 the Company’s operating budget. The second goal is to

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manage price risk related to the Company’s 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.

The Company utilizes 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 the Company 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.

The Company also uses 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.

The Company enters into futures transactions on the NYMEX and OTC swaps and options with various counterparties, consisting primarily of investment banks, financial institutions and other natural gas companies. The Company conducts credit reviews of all of its OTC counterparties and has agreements with many of these parties that contain collateral requirements. The Company generally uses standardized swap agreements that allow for offset of positive and negative OTC exposures with the same counterparty. OTC exposure is marked-to-market daily for the credit review process. Our exposure to OTC credit risk is reduced by the Company’s ability to require a margin deposit from its counterparties based upon the mark-to-market value of their net exposure. The Company is also subject to margin deposit requirements under these same agreements and under margin deposit requirements for its NYMEX transactions. At December 31, 2005 and 2004, the Company had posted margin deposits totaling $31.2 million and $7.9 million, respectively, with various counterparties.

The use of financial instruments may expose the Company to the risk of financial loss in certain circumstances, including instances when (i) the Company’s equity volumes are less than expected, (ii) the Company’s customers fail to purchase or deliver the contracted quantities of natural gas or NGLs, or (iii) the Company’s OTC counter parties fail to perform. To the extent that the Company engages in hedging activities, it may be prevented from realizing the benefits of favorable price changes in the physical market. However, it is similarly insulated against decreases in such prices.

All hedging contracts related to our equity production are designated and accounted for as cash flow hedges. As such, gains and losses related to the effective portions of the changes in the fair value of the derivatives are recorded in Accumulated other comprehensive income, a component of Stockholders’ equity. Realized gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Sale of gas or Sale of natural gas liquids when the hedged transactions occur. Realized and unrealized gains or losses represented by the periodic or final cash settlements from economic hedges are included in Price risk management activities on the Consolidated Statement of Operations. Economic hedges are financially settled derivatives that either were not designated or did not qualify as hedges under SFAS No. 133. These are marked-to-market through earnings.

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 effective at offsetting changes in the price of the forecasted transaction being hedged so that the Company’s exposure to the risk of commodity price changes is reduced. To meet this requirement, the Company hedges the price of the commodity, and if applicable, the basis between that derivative’s contract delivery location and the cash market location used for the actual sale of the product. This structure attains a high level of effectiveness, ensuring that a change in the price of the forecasted transaction will result in an equal and opposite change in the price of the derivative instrument hedging the transaction. In 2004 and 2003, the Company utilized crude oil as a surrogate hedge for natural gasoline, butane and condensate. In 2005, the Company utilized crude oil as a surrogate hedge for natural gasoline and condensate. These hedges were tested for effectiveness at inception and on a quarterly basis thereafter. Regression analysis based on a five-year period of time was used for these tests. In the first quarter of 2004, the Company determined in its quarterly effectiveness testing that its hedges of equity butane production which utilized crude oil puts as a surrogate were no longer effective hedges. Therefore, in the first quarter of 2004, the Company discontinued cash flow hedge accounting treatment on these instruments. The value of these financial instruments remained in Accumulated other comprehensive income and was reclassified to the Company’s results of operations in 2004 as the underlying transactions occurred. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Price risk management activities. During the year ended December 31, 2005, 2004 and 2003, the Company recognized losses of $208,000, $159,000 and $110,000, respectively, from the ineffective portions of its hedges.

In 2003, in order to properly align the Company’s hedged volumes of natural gas to its forecasted equity production, the Company 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 from Accumulated other comprehensive income. There were no gains or losses reclassified into earnings as a result of the discontinuance of cash flow hedges in 2005 or 2004.

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Account balances related to equity hedging transactions at December 31, 2005 were $23.4 million in Current Assets from price risk management activities, $19.3 million in Current Liabilities from price risk management activities, $1.5 million in Deferred income tax payable, net, and a $2.7 million after-tax unrealized gain in Accumulated other comprehensive income, a component of Stockholders’ Equity. Based on the commodity prices as of December 31, 2005, the after-tax gain will be re-classified from Accumulated other comprehensive income to Sale of gas or Sale of natural gas liquids during 2006.

Natural Gas Derivative Market Risk. As of December 31, 2005, the Company held a notional quantity of approximately 286 Bcf of natural gas futures, swaps and options extending from January 2006 to October 2008 with a weighted average duration of approximately six months. This was comprised of approximately 105 Bcf of long positions and 181 Bcf of short positions in these instruments. As of December 31, 2004, the Company held a notional quantity of approximately 342 Bcf of natural gas futures, swaps and options extending from January 2005 to October 2006 with a weighted average duration of approximately five months. This was comprised of approximately 151 Bcf of long positions and 191 Bcf of short positions in these instruments.

Crude Oil and NGL Derivative Market Risk. As of December 31, 2005, the Company held a notional quantity of approximately 50,400 MGal of NGL futures, swaps and options extending from January 2006 to December 2006 with a weighted average duration of approximately six months. This was comprised of approximately 25,200 MGal of long positions and 25,200 MGal of short positions in these instruments. As of December 31, 2004, the Company held a notional quantity of approximately 163,800 MGal of NGL futures, swaps and options extending from January 2005 to December 2005 with a weighted average duration of approximately six months. This was comprised of approximately 100,800 MGal of long positions and 63,000 MGal of short positions in these instruments.

Foreign Currency Derivative Market Risk. As a normal part of its business, the Company enters into physical gas transactions which are payable in Canadian dollars. The Company enters into forward purchases and sales of Canadian dollars from time to time to fix the cost of its 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 December 31, 2005, the Company had sold forward contracts for $45.7 million in Canadian dollars in exchange for $38.9 million in U.S. dollars, and the fair market value of these contracts was a loss of $490,000 in U.S. dollars. As of December 31, 2004, the Company had sold forward contracts for $31.3 million in Canadian dollars in exchange for $24.0 million in U.S. dollars, and the fair market value of these contracts was a liability of $2.1 million in U.S. dollars.

NOTE 5 - DEBT

The following summarizes the Company’s consolidated debt at the dates indicated (000s):

	December 31,
	2005		2004
Variable Rate Revolving Credit Facility	$	285,000	$	227,000
Master Shelf and Subordinated Notes		145,000		155,000
Total long-term debt	$	430,000	$	382,000

Variable Rate Revolving Credit Facility.At December 31, 2005, the commitment under the revolving credit facility was $700 million and it matures in November 2010. At December 31, 2005, $285.0 million was outstanding under this facility. Loans made under this facility are secured by a pledge of the capital stock of our significant subsidiaries, and these subsidiaries also guarantee the borrowings under the facility.

The borrowings under the Company’s credit facility bear interest at Eurodollar rates or a base rate, as requested by it, plus an applicable percentage based on its debt to capitalization ratio. The base rate is the agent’s published prime rate. The Company also pays a quarterly commitment fee on undrawn amounts ranging between 0.10% and 0.30%, depending on its debt to capitalization ratio. This fee is paid on unused amounts of the commitment. As of December 31, 2005, the interest rate payable on borrowings under this facility was approximately 5.3% per year. Under the credit facility, the Company is subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55% and maintaining a ratio of EBITDA, as defined in the credit facility, to interest over the last four quarters in excess of 3.0 to 1.0. The credit facility ranks equally with borrowings under the Company’s master shelf agreement with The Prudential Insurance Company. This facility has been rated Ba1 by Moody’s and BB+ by Standard and Poor’s.

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Master Shelf Agreement.Amounts outstanding under the Company’s master shelf agreement at December 31, 2005 are as indicated in the following table (dollars in thousands):

Issue Date	Amount		Interest Rate		Final Maturity	Principal Repayment Schedule
July 28, 1995	$	20,000	7.61	%	July 28, 2007	$10,000 on July 28, 2006 and 2007
June 30, 2004		100,000	5.92	%	June 30, 2011	Single payment at maturity
January 18, 2005		25,000	5.57	%	January 18, 2015	Single payment at maturity
Total	$	145,000

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

In December 2004, the Company gave notice to Prudential of its intention to prepay the $25 million note due January 17, 2008. This note bore interest at 6.36% per annum and was prepaid at par on January 18, 2005. To fund the prepayment, the Company issued a new $25 million note to Prudential, due January 2015 and bearing interest at 5.57% per annum. During 2006, the Company will make scheduled payments totaling $10.0 million on this facility. The Company intends to fund this repayment with funds available under the revolving credit facility.

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

Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2005 (000s):

2006	$	10,000
2007		10,000
2008		—
2009		—
2010		285,000
Thereafter		125,000
Total	$	430,000

NOTE 6 - FINANCIAL INSTRUMENTS

The Company, using available market information and valuation methodologies, has determined the estimated fair values of the Company’s financial instruments as follows (000s):

	December 31, 2005				December 31, 2004
	Carrying Value		Fair Value		Carrying Value		Fair Value
Cash and cash equivalents	$	27,198	$	27,198	$	390	$	390
Margin deposits		31,217		31,217		7,939		7,939
Trade accounts receivable		413,004		413,004		385,811		385,811
Accounts payable		463,113		463,113		400,672		400,672
Long-term debt		430,000		422,381		382,000		384,544
Derivative contracts	$	20,140	$	20,140	$	15,641	$	15,641

Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided herein are not necessarily indicative of the amount that the Company could realize upon the sale or refinancing of such financial instruments. The Company in estimating the fair value of its financial instruments used the following methods and assumptions:

Cash and cash equivalents, margin deposits, trade accounts receivable and accounts payable.Due to the short-term nature of these instruments, the carrying value approximates the fair value.

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Long-term debt.The Company’s long-term debt was comprised of fixed and floating rate facilities. The fair market value for the fixed rate debt was estimated using discounted cash flows based upon the Company’s current borrowing rates for debt with similar maturities. The floating rate portion of the long-term debt was borrowed on a revolving basis, which accrues interest at current rates; as a result, carrying value approximates fair value of this outstanding debt.

Derivative contracts.Fair value represents the amount at which the instrument could be exchanged in a current arms-length transaction.

NOTE 7 - INCOME TAXES

The provision for income taxes for the years ended December 31, 2005, 2004 and 2003 is comprised of (000s):

	2005		2004		2003
Current:
Federal	$	31,816	$	820	$	4,002
State and foreign		2,767		1,658		265
Total Current		34,583		2,478		4,267
Deferred:
Federal		78,006		69,069		49,567
State and foreign		2,407		2,131		1,784
Total deferred		80,413		71,200		51,351
Total tax provision	$	114,996	$	73,678	$	55,618

Not included above is the tax (expense) and benefit, respectively, allocated to the cumulative effect of a change in accounting principle of approximately ($2.7) million and $4.0 million for the years ended December 31, 2004 and 2003. There were no such items in 2005.

Temporary differences and carry-forwards which give rise to the deferred tax liabilities (assets) at December 31, 2005 and 2004, net of the tax effect of the cumulative change in accounting principle, are as follows (000s):

	2005			2004
Property and equipment	$	329,652		$	280,565
Differences between the book and tax basis of acquired assets		9,727			10,505
Hedging derivatives		1,525			1,795
Total deferred income tax liabilities		340,904			292,865
Alternative Minimum Tax (“AMT”) credit carry-forwards		(20,622	)		(43,412	)
Total deferred income tax assets		(20,622	)		(43,412	)
Net deferred income taxes	$	320,282		$	249,453

The differences between the provision for income taxes at the statutory rate and the actual provision for income taxes, before the tax effect of the change in accounting principle, for the years ended December 31, 2005, 2004 and 2003 are summarized as follows (000s):

	2005			%		2004		%	2003		%
Income tax before effect of change in accounting principle at statutory rate	$	112,865		35.0		$	68,853	35.0	$	52,597	35.0
State income taxes, net of federal benefit		3,483		1.1			2,125	1.1		1,893
Federal and state effect of non-deductibility of CFTC settlement		—		—			2,518	1.3		—	—
Canada income taxes, effect of disallowed loss on sale of stock and other miscellaneous items		(1,352	)	(0.4	)		182	0.1		1,128	0.8
Total	$	114,996		35.7		$	73,678	37.5	$	55,618	37.1

At December 31, 2005 and 2004, the Company had AMT credit carry-forwards for federal income tax purposes of approximately $20.6 million and $43.4 million, respectively. These carry-forwards have no expiration.

The Company believes that the AMT credit carry-forwards will be realized because they are substantially offset by existing taxable temporary differences reversing or are expected to be realized by achieving future profitable operations based on the Company’s dedicated and owned reserves, past earnings history and projections of future earnings.

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At December 31, 2005, the Company had net operating loss carryovers (“NOLs”) for various states which are immaterial and the Company does not expect to benefit from their utilization. Accordingly, a valuation allowance has been recorded against the entire amount of the NOL.

NOTE 8 - COMMITMENTS AND CONTINGENT LIABILITIES

Litigation.

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.The Company, 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.

Price, et al. v. Gas Pipelines, Western Gas Resources, Inc., et al., District Court, Stevens County, Kansas, Case No. 99-C-30.Western is a defendant in litigation filed on September 23, 1999, along with numerous other natural gas companies, in which Mr. Price is claiming an under measurement of gas and Btu volumes throughout the country. The Company 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. The Company believes that Mr. Price’s claims are without merit and intends to vigorously contest the allegations in this case.

J.P. Morgan Trust Company, National Association, in its Capacity as Trustee of the FI Liquidating Trust v. Oneok Inc. et al., United States District Court, for the District of Kansas, Case No. 05-2389CM.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 the Company and other defendants to this action. 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. The Company believes that the claims are without merit and intends to vigorously contest the allegations in this case.

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 the Company 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. The Company believes that the claims are without merit and intends to vigorously contest the allegations in this case.

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

Commitments.

Lease Commitments.As a normal course of the Company’s business operations, the Company enters into operating leases for office space and office, communication and transportation equipment. In addition, primarily to support its growing development in the

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Powder River Basin coal bed development, the Company has entered into operating leases for compression equipment. These leases are classified as operating leases and have terms ranging from one month to ten years. The majority of the leases for compression have purchase options at various times throughout the primary terms of the agreements and have renewal provisions. Rental payments under operating leases have totaled $18.4 million, $15.3 million and $13.8 million in 2005, 2004 and 2003, respectively. Future operating lease payments by year under these leases are as follows (000s):

2006	$	17,313
2007		16,255
2008		14,631
2009		11,103
2010		8,168
Thereafter		4,598
Total	$	72,068

Firm Transportation Capacity.The Company enters into firm transportation agreements with interstate pipeline companies as a part of its marketing operations and to ensure that its equity production has access to downstream markets. At December 31, 2005, these agreements have terms ranging from one month to twelve years. Payments under these agreements have totaled $38.9 million, $29.3 million and $26.4 million in 2005, 2004 and 2003, respectively. Future payments by year under these agreements are as follows (000s):

2006	$	43,156
2007		43,881
2008		40,781
2009		34,064
2010		25,154
Thereafter		57,698
Total	$	244,734

Storage Capacity. The Company enters into storage agreements with various third parties primarily as part of its marketing operations. Payments under these agreements totaled $7.0 million, $6.2 million and $5.2 million in 2005, 2004 and 2003, respectively. As of December 31, 2005, the Company had contracts in place for approximately 17.0 Bcf of storage capacity at various third-party facilities. The associated contract periods have an average term of 32 months. Future payments by year under these agreements are as follows (000s):

2006	$	8,884
2007		4,908
2008		2,948
2009		2,100
2010		1,663
Thereafter		7,258
Total	$	27,761

Post Retirement Benefits.In the first quarter of 2005, the Company’s board of directors approved the Amended and Restated Directors’ Health Plan, which is available to persons who were directors as of January 1, 2005. The terms of the Plan provide that for the duration of each director’s tenure on the board, the director, and the director’s eligible spouse, if any, is entitled to elect to receive substantially similar benefits as provided to executive officers under the Company’s group health plan and a supplemental coverage plan. Following each director’s retirement from the board, the director, and the director’s eligible spouse, if any, will remain entitled to participate in the Plan until reaching the age of Medicare eligibility. Upon a director or covered spouse attaining Medicare eligibility age, Medicare will become the primary health insurance for such person and the Company will at that time provide supplemental health coverage only. In the event that any retired director or spouse, if any, becomes entitled to participate in another employer sponsored health plan and is obligated to bear less than one-half of the cost of such coverage, then that plan will become the primary health coverage for such person for the duration of such entitlement. As of December 31, 2005, a third-party actuary estimates that the present value of total projected benefits under this plan to the directors will total approximately $1.0 million. This amount will be accrued over the remaining period of their current terms. As of December 31, 2005, the Company has accrued $480,000 for this future benefit obligation.

NOTE 9 - BUSINESS SEGMENTS AND RELATED INFORMATION

The Company operates 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 its internal

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forecast and these segments are consistent with the Company’s 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, collectively with the Marketing and Transportation segments referred to as the midstream operations, the Company connects producers’ wells (including those of the Company’s Exploration and Production segment) to its gathering systems for delivery of natural gas to its processing or treating plants, processes the natural gas to extract NGLs and treats the natural gas in order to meet pipeline specifications. In some areas, where no processing is required, the Company gathers and compresses producers’ gas and delivers it to pipelines for further delivery to market. Except for volumes taken in kind by the Company’s producers, the Marketing segment sells the gas and NGLs extracted at most of its facilities.

In this segment, the Company recognizes revenue for its services at the time the service is performed. Included in this segment is the Company’s Powder River Basin coal bed methane gathering operation, which gathers gas from producers, including the Company’s Exploration and Production segment. In 2003, this service for the Exploration and Production segment was performed under a percentage-of-proceeds contract and in 2004 and 2005, this service was performed under a fee-based contract. The change of contract type had no effect on the Operating profit of either the Gathering, Processing and Treating segment or the Exploration and Production segment.

Substantially all gas flowing through the Company’s 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 the Company’s plant facilities’ gross margin, or revenues at the plant less product purchases, for the month of December 2005 was under percentage-of-proceeds agreements in which the Company is typically responsible for the marketing of the gas and NGLs. Under these agreements, the Company pays producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs. Revenue is recognized when the gas or NGLs are sold and the related product purchases are recorded as a percentage of the sale of the product.

Approximately 17% of the Company’s plant facilities’ gross margin for the month of December 2005 was under contracts that are primarily fee-based from which the Company receives a set fee for each Mcf of gas gathered and/or processed. This type of contract provides the Company 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.

Approximately 2% of the Company’s plant facilities’ gross margin for the month of December 2005 was under contracts with “keepwhole” arrangements or wellhead purchase contracts. Under the keepwhole contracts, the Company retains the NGLs recovered by the processing facility and keeps 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 the Company to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, the Company is 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 when the product is sold.

Exploration and Production. The activities of the Exploration and Production segment, also referred to as upstream operations, include the exploration and development of gas properties in the Rocky Mountain area, including those where the Company’s 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 its proportional share of transportation charges. Also included in this segment are the Company’s Canadian exploration and development operations, which are conducted through its wholly owned subsidiary Western Gas Resources Canada Company and which are immaterial for separate presentation.

Marketing. The Company’s Marketing segment markets gas and NGLs extracted at its gathering, processing and treating facilities and produced from its exploration and production assets and buys and sells gas and NGLs in the United States and Canada from and to a variety of customers. In this segment, revenues for sales of product are recognized at the time the gas or NGLs are delivered to the customer and 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. The Company sells its products under agreements with varying terms and conditions in order to match seasonal and other changes in demand. Also included in this segment are the Company’s Canadian marketing operations, which are conducted through its wholly owned subsidiary WGR Canada, Inc. and which are immaterial for separate presentation.

During the years ended December 31, 2005, 2004 and 2003, the Company sold gas to a variety of customers including end-users, pipelines, energy merchants, local distribution companies and others. In 2005, no single customer accounted for more than

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approximately 13% of the Company’s consolidated revenues from the sale of gas, or 10% of total consolidated revenue. In 2004, no single customer accounted for more than approximately 9% of the Company’s consolidated revenues from the sale of gas, or 7% of total consolidated revenue. In 2003, no single customer accounted for more than 6% of the Company’s consolidated revenues from the sale of gas, or 5% of total consolidated revenue.

During the years ended December 31, 2005, 2004 and 2003, the Company sold NGLs to a variety of customers including end-users, fractionators, chemical companies, energy merchants and other customers. In 2005, one customer accounted for approximately 23% of the Company’s consolidated revenues from the sale of NGLs, or 3% of total consolidated revenue. This customer is a large integrated energy company. In 2004, one customer accounted for approximately 51% of the Company’s consolidated revenues from the sale of NGLs, or 7% of total consolidated revenue. This customer is a large integrated energy company. In 2003, two customers accounted for approximately 49% of the Company’s consolidated revenues from the sale of NGLs, or 6% of total consolidated revenue. One of these customers is a large integrated energy company and the other is a large petrochemical company.

Transportation. The Transportation segment reflects the operations of the Company’s MIGC, Inc. and MGTC, Inc. pipelines. The revenue presented in this segment is derived from transportation of gas for the Company’s Marketing segment and third parties. In this segment, the Company realizes 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 table sets forth the Company’s segment information as of and for the three years ended December 31, 2005, 2004 and 2003 (000s). Due to the Company’s 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.

Year Ended December 31, 2005:

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	3,242		$	3,766		$	3,198,980		$	2,317		$	—		$	—		$	3,208,305
Sale of natural gas liquids		57			—			663,987			—			—			—			664,044
Equity hedges:
Gas		(45	)		(7,375	)		—			—			—			—			(7,420	)
Liquids		(9,201	)		—			—			—			—			—			(9,201	)
Gathering, processing and transportation revenue		99,677			(162	)		—			6,851			—			—			106,366
Total revenues from unaffiliated customers:		93,730			(3,771	)		3,862,967			9,168			—			—			3,962,094
Inter-segment revenues		1,391,987			402,833			85,708			13,811			38			(1,894,377	)		—
Price risk management activities		23			11,103			(20,571	)		—			—			—			(9,445	)
Interest Income		—			18			23			1			51,975			(52,017	)		—
Other, net		4,586			172			27			—			1,224			—			6,009
Total revenues		1,490,326			410,355			3,928,154			22,980			53,237			(1,946,394	)		3,958,658
Product purchases		1,150,022			4,339			3,902,530			4,502			—			(1,851,193	)		3,210,200
Plant and transportation operating Expense		112,827			233			314			6,289			—			(4,139	)		115,524
Oil and gas exploration and production expense		—			152,226			—			—			—			(38,632	)		113,594
(Earnings) from equity investments		(10,133	)		—			—			—			—			—			(10,133	)
Segment operating profit		237,610			253,557			25,310			12,189			53,237			(52,430	)		529,473
Depreciation, depletion and amortization		46,722			72,575			141			1,829			7,516			—			128,783
Selling and administrative expense		(6	)		—			—			—			60,157			(38	)		60,113
(Gain) loss from sale of assets		(477	)		4			0			983			—			—			510
Interest expense		5			4			1,492			(855	)		68,967			(52,016	)		17,597
Income before income tax	$	191,366		$	180,974		$	23,677		$	10,232		$	(83,403	)	$	(376	)	$	322,470
Identifiable assets:
Other allocated assets	$	11,723		$	11,284		$	257,863		$	45,414		$	523,450		$	(110,212	)	$	739,522
Equity investments		31,428			—			—			877			1,035,511			(1,031,025	)		36,791
Property and equipment		814,890		$	647,323		$	11			34,762			61,335			—			1,558,321
Total identifiable assets	$	858,041		$	658,607		$	257,874		$	81,053		$	1,620,296		$	(1,141,237	)	$	2,334,634

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Year Ended December 31, 2004:

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	3,666		$	9,554		$	2,495,913		$	1,779		$	—		$	—		$	2,510,912
Sale of natural gas liquids		5			—			467,081			—			—			—			467,086
Equity hedges:
Gas		649			6,720			—			—			—			—			7,369
Liquids		(16,325	)		—			—			—			—			—			(16,325	)
Gathering, processing and transportation revenue		84,148			—			—			6,726			—			—			90,874
Total revenues from unaffiliated customers		72,143			16,274			2,962,994			8,505			—			—			3,059,916
Inter-segment revenues		1,051,981			252,797			54,321			14,128			—			(1,373,227	)		—
Price risk management activities		(12	)		—			20,063			—			—			—			20,051
Interest income		—			4			—			1			20,181			(20,186	)		—
Other, net		1,210			12			(43	)		49			1,973			—			3,201
Total revenues		1,125,322			269,087			3,037,335			22,683			22,154			(1,393,413	)		3,083,168
Product purchases		871,426			2,450			2,999,426			4,559			—			(1,337,062	)		2,540,799
Plant and transportation operating expense		92,143			23			(167	)		7,150			—			(3,281	)		95,868
Oil and gas exploration and production expense		—			110,473			—			—			—			(32,865	)		77,608
Earnings from equity investments		(7,124	)		—			—			—			—			—			(7,124	)
Segment operating profit		168,877			156,141			38,076			10,974			22,154			(20,205	)		376,017
Depreciation, depletion and amortization		38,585			47,911			123			1,655			7,262			—			95,536
Selling and administrative expense		—			—			—			—			52,292			(46	)		52,246
(Gain) loss from sale of assets		224			(520	)		—			(15	)		300			1,299			1,288
Loss from early extinguishment of debt		—			—			—			—			10,662			—			10,662
Interest expense		—			42			295			(328	)		39,739			(20,186	)		19,562
Income before income taxes	$	130,068		$	108,708		$	37,658		$	9,662		$	(88,101	)	$	(1,272	)	$	196,723
Identifiable assets:
Other allocated assets	$	32,042		$	7,160		$	146,248		$	47,457		$	419,139		$	(76,286	)	$	575,760
Equity investment		35,729			—			—			2,559			570,638			(573,197	)		35,729
Property and equipment		674,011			463,052			17			36,665			52,733			(569	)		1,225,909
Total identifiable assets	$	741,782		$	470,212		$	146,265		$	86,681		$	1,042,510		$	(650,052	)	$	1,837,398

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Year Ended December 31, 2003:

	Gas Gathering and Processing			Exploration and Production			Marketing			Trans- portation			Corporate			Eliminating Entries			Total
Revenues from unaffiliated customers:
Sale of gas	$	5,041		$	4,746		$	2,476,736		$	1,098		$	—		$	—		$	2,487,621
Sale of natural gas liquids		11			—			357,504			—			—			—			357,515
Equity hedges:
Gas		(2,358	)		(21,505	)		—			—			—			—			(23,863	)
Liquids		(11,407	)		—			—			—			—			—			(11,407	)
Gathering, processing and transportation revenue		76,621			—			—			7,051			—			—			83,672
Total revenues from unaffiliated customers		67,908			(16,759	)		2,834,240			8,149			—			—			2,893,538
Inter-segment revenues		1,081,358			221,266			38,510			14,093			—			(1,355,227	)		—
Price risk management activities		(11	)		(866	)		(15,509	)		—			—			—			(16,386	)
Interest income		—			42			—			3			12,490			(12,535	)		—
Other, net		1,967			21			4			42			565			—			2,599
Total revenues		1,151,222			203,704			2,857,245			22,287			13,055			(1,367,762	)		2,879,751
Product purchases		948,518			2,289			2,820,495			2,982			—			(1,317,843	)		2,456,441
Plant and transportation operating expense		82,810			328			318			7,680			—			(2,792	)		88,344
Oil and gas exploration and production expense		—			86,856			—			—			—			(34,610	)		52,246
Earnings from equity investments		(7,356	)		—			—			—			—			—			(7,356	)
Segment operating profit		127,250			114,231			36,432			11,625			13,055			(12,517	)		290,076
Depreciation, depletion and amortization		30,676			33,321			141			1,689			8,078			—			73,905
Selling and administrative expense		—			—			—			—			40,481			(58	)		40,423
(Gain) loss from sale of assets		123			(194	)		—			586			53			(724	)		(156	)
Interest expense		—			24			262			(154	)		38,030			(12,535	)		25,627
Income before income taxes	$	96,451		$	81,080		$	36,029		$	9,504		$	(73,587	)	$	800		$	150,277
Identifiable assets:
Other allocated assets	$	4,067		$	7,001		$	103,603		$	40,628		$	326,537		$	(66,708	)	$	415,128
Equity investment		—			—			—			—			632,622			(593,333	)		39,289
Property and equipment		608,623			288,954			1,531			39,010			57,912			731			996,761
Total identifiable assets	$	612,690		$	295,955		$	105,134		$	79,638		$	1,017,071		$	(659,310	)	$	1,451,178

NOTE 10 - EMPLOYEE BENEFIT PLANS

Retirement Plan.A discretionary retirement plan (a defined contribution plan) exists for all domestic Company employees meeting certain service requirements. The Company may make annual discretionary contributions to the plan as determined by the board of directors, and during the two years ended December 31, 2004 and through May 30, 2005, the match of employee contributions was a sliding scale of 60% to 100% of the first 5% of employee compensation based upon years of service. Effective as of June 1, 2005, the match of employee contributions was increased to equal 100% of the first 6% of employee compensation. In addition, employee vesting of Company contributions was accelerated to a three-year vesting period. Contributions are made to Fidelity Management Trust Company, as trustee. The trustee invests the funds in accordance with the participants’ investment elections into mutual funds and a fund to purchase the Company’s common stock. The discretionary contributions made by the Company were $3.3 million, $3.1 million and $2.2 million, for the years ended December 31, 2005, 2004 and 2003, respectively. The matching contributions were approximately $2.0 million, $1.5 million and $1.4 million for the years ended December 31, 2005, 2004 and 2003, respectively.

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1999 Non-Employee Directors Stock Option Plan.Effective March 1999, the board of directors of the Company adopted a 1999 Non-Employee Directors’ Stock Option Plan (“1999 Directors Plan”) that authorized the granting of options to purchase 30,000 shares of the Company’s common stock. During 1999, the board approved options grants covering 30,000 shares to several board members. Under this plan, each of these options becomes exercisable as to 33 1/3% of the shares covered by it on each anniversary from the date of grant. This plan terminates on the earlier of March 12, 2009 or the date on which all options granted under the plan have been exercised in full.

1993, 1997 and 1999 Stock Option Plans.The 1993 Stock Option Plan (“1993 Plan”), the 1997 Stock Option Plan (“1997 Plan”), and the 1999 Stock Option Plan (“1999 Plan”) became effective on March 29, 1993, May 21, 1997, and May 21, 1999, respectively, after approvals by the Company’s stockholders. Each plan is intended to be an incentive stock option plan in accordance with the provisions of Section 422 of the Internal Revenue Code of 1986, as amended. The Company reserved 2,000,000 shares of common stock for issuance upon exercise of options under each of the 1993 Plan and the 1997 Plan and 1,500,000 shares of common stock for issuance upon exercise of options under the 1999 Plan. The 1993 Plan terminated on March 29, 2003. The 1997 Plan and the 1999 Plan will terminate on the later of May 21, 2007 and May 21, 2009, respectively, or the date on which all the respective options granted under each of the plans have expired or been exercised in full. Although options covering 745,204 shares are available to be granted under the 1997 Plan, no further options will be granted under this plan. During 2004, options covering 140,876 shares were granted under the 1999 Plan.

Chief Executive Officer and President’s Plan (“CEO Plan”).Pursuant to the Employment Agreement, dated October 15, 2001, and the Stock Option Agreement, dated as of November 1, 2001, between the Company and Peter A. Dea, the Company’s Chief Executive Officer and President, non-qualified stock options were granted for the purchase of 600,000 shares of the Company’s common stock. The exercise price of the options was equal to $2.50 below the closing price per share on the effective date of the Employment Agreement. The stock options are subject to the conditions of the Agreements and vest equally over four years. The difference between the closing price on the effective date and the exercise price is being amortized over four years as compensation expense. This option plan will terminate on the earlier of October 15, 2010 or the date on which all options granted under the plan have been exercised in full. On August 1, 2005, the Company entered into a new employment agreement with Mr. Dea, which due to recent changes in the tax laws required that he exercise, on or before March 15, 2006, 150,000 of the options to purchase shares of the Company’s common stock, which vested on November 15, 2005. Otherwise, per this agreement, these options will expire if not exercised.

2002 Non-Employee Directors Stock Option Plan.Effective May 2002, the stockholders approved the 2002 Non-Employee Directors’ Stock Option Plan (“2002 Directors Plan”) that authorized the granting of options to purchase 220,000 shares of the Company’s common stock. The 2002 Directors Plan provides for a three-year vesting schedule while the non-employee director serves on the Company’s board. Under this plan, a newly elected non-employee director will be granted 10,000 options to acquire common stock as of the date of election. The 2002 Directors Plan also provides for an annual grant on the date of the Company’s annual meeting to each non-employee director of 4,000 options to acquire common stock. The purchase price of the stock under each option shall be the fair market value of the stock at the time such option is granted and no options shall be re-priced. The 2002 Directors Plan requires the non-employee director to exercise the option at the earlier of ten years from the date of the plan or within five years of the date each portion vests. The non-employee director’s right to exercise options under the 2002 Directors Plan is subject to continuous service since the grant was made. If the non-employee director dies or becomes disabled (within the meaning of the 2002 Directors Plan) or a change of control occurs, then all of the options granted to the non-employee director shall become 100% exercisable. The 2002 Directors Plan will terminate on the later of May 17, 2012 or the date on which all options granted under the plan have expired or been exercised in full. During 2005, 2004 and 2003, a total of 32,000, 32,000 and 32,000 options, respectively, were granted under this plan.

2002 Stock Option Plan. Effective May 2002, the stockholders approved the 2002 Stock Incentive Plan (“2002 Plan”) that authorized the granting of options to purchase 2,500,000 shares of the Company’s common stock. No employee may be granted more than 250,000 options to acquire common stock in any fiscal year. The 2002 Plan requires the employee to exercise the option at the earlier of ten years from the date of the 2002 Plan or within five years of the date each portion vests. The employee’s right to exercise options under the 2002 Plan is subject to continuous employment since the grant was made. If the employee dies, becomes disabled (within the meaning of the 2002 Plan) or a change of control occurs, then all of the options granted to the employee shall become 100% exercisable. The 2002 Plan will terminate on the later of May 17, 2012 or the date on which all options granted under the plan have expired or been exercised in full. During 2005, 2004 and 2003, a total of 157,750, 956,841 and 1,129,900 options, respectively, were granted under this plan.

2005 Stock Option Plan. Effective May 2005, the stockholders approved the 2005 Stock Incentive Plan (“2005 Plan”) that authorized the granting of options to purchase 2,500,000 shares of the Company’s common stock and the granting of 1,500,000 shares of restricted common stock. No employee may be granted more than 250,000 options to acquire common stock or 150,000 shares of

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restricted common stock in any fiscal year. The 2005 Plan requires the employee to exercise the options at the earlier of five years of the date each portion vests or seven years from the date the options are granted. The employee’s right to exercise options under the 2005 Plan is subject to continuous employment since the grant was made. If a change of control occurs, then all of the options granted to the employee shall become 100% exercisable and all restricted shares become vested. The 2005 Plan will terminate on the later of May 6, 2015 or the date on which all options granted under the plan have expired or been exercised in full. During 2005, a total of 746,726 options and 382,545 restricted shares were granted under this plan.

Under each of the 1997, 1999, 2002 and 2005 plans (including the non-employee director plans), the board of directors of the Company determines and designates from time to time those employees of the Company to whom options or restricted shares are to be granted. If any option terminates or expires prior to being exercised, the shares relating to such option are released and may be subject to re-issuance pursuant to a new option. The board of directors has the right to, among other things, fix the method by which the price is determined and the terms and conditions for the grant or exercise of any option. The purchase price of the stock under each option shall be the average closing price for the ten days prior to the grant. Under the 1997, 1999, 2002 and 2005 Plans, the board of directors has the authority to set the vesting schedule from 20% per year to 33 1/3% per year. Under each of the plans, the employee must exercise the option within five years of the date each portion vests.

The following table summarizes the number of stock options exercisable and available for grant under the Company’s benefit plans at December 31, 2005, 2004 and 2003:

	Per Share Price Range		1997 Plan	1999 Plan	1999 Directors Plan	CEO Plan	2002 Plan	2002 Directors Plan	2005 Plan
Exercisable:
December 31, 2005	$	0.01-5.00	—	—	6,600	—	—	—	—
	$	5.01-10.00	6,002	—	—	—	—	—	—
	$	10.01-15.00	—	11,002	—	495,000	—	—	—
	$	15.01-20.00	—	342,608	—	—	534,188	46,662	—
	$	20.01-25.00	—	—	—	—	23	—	—
	$	25.01-30.00	—	28,106	—	—	193,048	6,667	—
	$	30.01-35.00	—	—	—	—	11,667	—	—
		TOTAL	6,002	381,716	6,600	495,000	738,926	53,329	—
December 31, 2004	$	0.01-5.00	36,536	—	6,600	—	—	—	—
	$	5.01-10.00	11,000	—	—	—	—	—	—
	$	10.01-15.00	—	33,672	—	450,000	—	—	—
	$	15.01-20.00	—	586,038	—	—	395,961	32,000	—
	$	20.01-25.00	—	—	—	—	5,000	—	—
		TOTAL	47,536	619,710	6,600	450,000	400,961	32,000	—
December 31, 2003	$	0.01-5.00	109,266	—	—	—	—	—	—
	$	5.01-10.00	65,320	800	16,700	—	—	—	—
	$	10.01-15.00	—	71,762	—	300,000	—	—	—
	$	15.01-20.00	—	575,504	—	—	84,882	10,666	—
		TOTAL	174,586	648,066	16,700	300,000	84,882	10,666	—
Available for Grant:
December 31, 2005		—	—	17,088	—	—	30,501	92,000	1,755,274
December 31, 2004		—	—	4,500	—	—	122,340	124,000	—
December 31, 2003		—	—	120,876	—	—	1,006,972	156,000	—

The following table summarizes the stock option activity under the Company’s benefit plans:

	Per Share Price Range		1993 Plan		1997 Plan		1999 Plan		1999 Directors Plan		CEO Plan		2002 Plan		2002 Directors Plan		2005 Plan
Balance at 12/31/02			110,054		318,810		1,262,766		16,700		600,000		375,994		36,000		—
Granted	$	16.18-22.33	—		—		—		—		—		1,129,900		32,000		—
Exercised	$	2.30-18.17	(16,028	)	(144,224	)	(130,402	)	—		—		(36,160	)	—		—
Forfeited or expired	$	6.63-18.91	(94,026	)	—		(668	)	—		—		(12,866	)	(4,000	)	—
Balance at 12/31/03			—		174,586		1,131,696		16,700		600,000		1,456,868		64,000		—
Granted	$	23.56-31.06	—		—		140,876		—		—		956,841		32,000		—
Exercised	$	2.30-19.02	—		(127,050	)	(375,653	)	(10,100	)	—		(168,900	)	—		—
Forfeited or expired	$	13.32-28.35	—		—		(24,500	)	—		—		(72,209	)	—		—
Balance at 12/31/04			—		47,536		872,419		6,600		600,000		2,172,600		96,000		—
Granted	$	28.52-50.13	—		—		—		—		—		157,750		32,000		746,726
Exercised	$	2.30-34.00	—		(41,534	)	(309,016	)	—		(105,000	)	(447,286	)	(16,000	)	—
Forfeited or expired	$	15.37-31.85	—		—		(12,588	)	—		—		(65,910	)	—		(2,000	)
Balance at 12/31/05			—		6,002		550,815		6,600		495,000		1,817,154		112,000		744,726
Weighted-average remaining contractual life (years)			—		2.4		5.3		0.8		3.7		5.9		4.9		6.1

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The following table summarizes the weighted average option exercise price information under the Company’s benefit plans:

	1993 Plan			1997 Plan			1999 Plan			1999 Directors Plan			CEO Plan			2002 Plan			2002 Directors Plan			2005 Plan
Balance at 12/31/02	$	9.87		$	4.87		$	16.34		$	2.76		$	12.51		$	16.49		$	18.91		$	—
Granted		—			—			—			—			—			18.91			19.38			—
Exercised		(9.21	)		(5.30	)		(11.79	)		—			—			(16.52	)		—			—
Forfeited or expired		(14.51	)		—			(11.73	)		—			—			(16.48	)		(18.91	)		—
Balance at 12/31/03	$	—		$	4.52		$	16.87		$	2.76		$	12.51		$	18.37		$	19.15		$	—
Granted		—			—			28.35			—			—			28.45			27.69			—
Exercised		—			(4.94	)		(16.93	)		(2.76	)		—			(17.86	)		—			—
Forfeited or expired		—			—			(15.68	)		—			—			(18.67	)		—			—
Balance at 12/31/04	$	—		$	3.37		$	18.72		$	2.76		$	12.51		$	22.83		$	21.99		$	—
Granted		—			—			—			—			—			34.25			34.00			31.86
Exercised		—			(3.12	)		(17.50	)		—			(12.51	)		(20.62	)		(24.99	)		—
Forfeited or expired		—			—			(22.89	)		—			—			(24.39	)		—			(31.85	)
Balance at 12/31/05	$	—		$	5.11		$	19.32		$	2.76		$	12.51		$	24.31		$	24.99		$	31.86

NOTE 11 - QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):

The following summarizes certain quarterly results of operations (000s, except per share amounts):

	Operating Revenues		Gross Profit (a)		Income Before Cumulative Effect of Change in Accounting Principle		Earnings Per Share of Common Stock Before Cumulative Effect of Change in Accounting Principle		Net Income		Earnings Per Share of Common Stock		Earnings Per Share of Common Stock – Assuming Dilution
2005 quarter ended:
March 31	$	834,107	$	47,214	$	19,706	$	0.27	$	19,706	$	0.27	$	0.26
June 30		868,026		81,067		37,629		0.51		37,629		0.51		0.50
September 30		961,410		37,355		10,735		0.14		10,735		0.14		0.14
December 31		1,295,115		235,054		139,404		1.87		139,404		1.87		1.82
	$	3,958,658	$	400,690	$	207,474	$	2.79	$	207,474	$	2.79	$	2.72
2004 quarter ended:
March 31	$	779,680	$	62,594	$	29,720	$	0.42	$	34,434	$	0.49	$	0.49
June 30		725,838		61,033		13,649		0.19		13,649		0.19		0.18
September 30		693,679		44,922		19,465		0.26		19,465		0.26		0.26
December 31		883,971		111,932		60,211		0.81		60,211		0.81		0.80
	$	3,083,168	$	280,481	$	123,045	$	1.68	$	127,759	$	1.75	$	1.73

(a) Excludes selling and administrative, interest and income tax expenses, (gains) or losses on sale of assets, loss from early extinguishment of debt, and the cumulative effect of the change in accounting principle.

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SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):

Costs.The following tables set forth capitalized costs at December 31, 2005, 2004 and 2003 and costs incurred for oil and gas producing activities for the years ended December 31, 2005, 2004 and 2003 (000s):

	2005			2004			2003
Capitalized costs:
Proved properties	$	660,500		$	475,448		$	315,635
Unproved properties		203,563			134,519			83,384
Total		864,063			609,967			399,019
Less accumulated depreciation and depletion		(212,993	)		(149,624	)		(111,658	)
Net capitalized costs	$	651,070		$	460,343		$	287,361
Costs incurred:
Acquisition of properties
Proved	$	1,339		$	47,775		$	14,202
Unproved		12,001			36,776			10,279
Development costs		168,352			95,466			60,479
Exploration costs		86,700			38,098			18,089
Total costs incurred	$	268,392		$	218,115		$	103,049

Results of Operations.The results of operations for oil and gas producing activities, excluding corporate overhead and interest costs, for the years ended December 31, 2005, 2004 and 2003 are as follows (000s):

	2005			2004			2003
Revenues from sale of oil and gas:
Sales	$	13,539		$	10,767		$	5,905
Inter-segment sales		392,351			251,585			220,107
Total		405,890			262,352			226,012
Production costs		(148,091	)		(106,732	)		(86,800	)
Exploration costs		(10,271	)		(7,093	)		(6,764	)
Depreciation, depletion and amortization		(69,783	)		(46,977	)		(31,385	)
Income tax expense		(111,059	)		(68,426	)		(57,342	)
Results of operations	$	66,686		$	33,124		$	43,721

Reserve Quantity Information.Reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and of future net cash flows expected there from prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in commodity prices and operating costs. Any significant revision of reserve estimates could materially adversely affect the Company’s financial condition, results of operations and cash flows.

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The following table sets forth information for the years ended December 31, 2005, 2004 and 2003 with respect to changes in the Company’s proved (i.e. proved developed and undeveloped) reserves, all of which are in the United States.

	Natural Gas (MMcf)		Crude Oil (MBbls)
December 31, 2002	580,664		1,213
Revisions of previous estimates	(65,474	)	571
Extensions and discoveries	191,751		887
Purchases of reserves in place	14,005		57
Production	(52,222	)	(75	)
December 31, 2003	668,724		2,653
Revisions of previous estimates	(82,300	)	(85	)
Extensions and discoveries	241,300		1,058
Purchases of reserves in place	26,676		112
Sales of reserves in place	(9,072	)	—
Production	(54,892	)	(97	)
December 31, 2004	790,436		3,641
Revisions of previous estimates	(76,519	)	(279	)
Extensions and discoveries	246,449		886
Sales of reserves in place	(2,035	)	—
Production	(62,246	)	(124	)
December 31, 2005	896,085		4,124
Proved developed reserves, included above:
December 31, 2002	265,300		400
December 31, 2003	282,374		823
December 31, 2004	316,563		1,209
December 31, 2005	391,477		1,247

Standardized Measures of Discounted Future Net Cash Flows.Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities”. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.

Future cash inflows are computed by applying year-end prices of oil and gas relating to the Company’s proved reserves to the year-end quantities of those reserves.

The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, or their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Also included in this caption are asset retirement obligations.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.

An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

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Information with respect to the Company’s estimated discounted future cash flows from its oil and gas properties for the years ended December 31, 2005, 2004 and 2003 is as follows (000s):

	2005			2004			2003
Future cash inflows	$	6,633,731		$	3,872,043		$	3,152,573
Future production costs		(1,865,312	)		(950,891	)		(710,999	)
Future development costs		(499,934	)		(411,257	)		(275,302	)
Future income tax expense		(1,408,954	)		(838,615	)		(740,314	)
Future net cash flows		2,859,531			1,671,280			1,425,958
10% annual discount for estimated timing of cash flows		(1,439,269	)		(872,035	)		(740,598	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	1,420,262		$	799,245		$	685,360

Principal changes in the Company’s estimated discounted future net cash flows for the years ended December 31, 2005, 2004 and 2003 are as follows (000s):

	2005			2004			2003
As of January 1,	$	799,245		$	685,360		$	360,652
Sales and transfers of oil and gas produced, net of production costs		(257,800	)		(155,620	)		(139,211	)
Net changes in prices and production costs related to future production		678,939			(35,978	)		578,659
Development costs incurred during the period		168,352			95,466			60,479
Changes in estimated future development costs		(82,773	)		(78,593	)		(22,565	)
Changes in extensions and discoveries		579,649			365,896			272,110
Revisions of previous quantity estimates		(282,097	)		(161,703	)		(321,395	)
Purchases (sales) of reserves in place		(4,684	)		25,643			22,898
Accretion of discount		120,064			104,118			53,655
Net change in income taxes		(298,633	)		(45,344	)		(179,922	)
As of December 31,	$	1,420,262		$	799,245		$	685,360

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