Bill Barrett (BBG) 10-Q 2008 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2008

OR

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

For the transition period from            to            

Commission file number 001-32367

BILL BARRETT CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	80-0000545
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

1099 18th Street, Suite 2300 Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

(303) 293-9100

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a small reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x                                                                                      Accelerated filer  ¨

Non-accelerated filer  ¨ (Do not check if a smaller reporting company)           Smaller reporting company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨  Yes    x  No

There were 44,993,823 shares of $0.001 par value common stock outstanding on May 1, 2008.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION		3
Item 1.	Financial Statements	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	28
Item 4.	Controls and Procedures	30
PART II. OTHER INFORMATION		31
Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 3.	Defaults Upon Senior Securities	31
Item 4.	Submission of Matters to a Vote of Security Holders	31
Item 5.	Other Information	31
Item 6.	Exhibits	32
SIGNATURES		34

2

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31, 2008			December 31, 2007
	(in thousands, except share and per share data)
Assets:
Current Assets:
Cash and cash equivalents	$	60,923		$	60,285
Accounts receivable, net of allowance for doubtful accounts of $303 for December 31, 2007 and March 31, 2008		69,912			50,380
Prepayments and other current assets		6,763			3,425
Derivative assets		14			17,337
Deferred income taxes		31,898			—
Total current assets		169,510			131,427
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		1,563,511			1,472,834
Unevaluated oil and gas properties, excluded from amortization		245,812			231,521
Oil and gas properties held for sale, net, excluded from amortization		1,120			2,303
Furniture, equipment and other		16,534			16,113
		1,826,977			1,722,771
Accumulated depreciation, depletion, amortization and impairment		(574,526	)		(526,939	)
Total property and equipment, net		1,252,451			1,195,832
Deferred Financing Costs, Derivative Assets and Other		10,940			2,428
Total	$	1,432,901		$	1,329,687
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	78,161		$	84,773
Amounts payable to oil and gas property owners		21,064			22,209
Production taxes payable		29,185			24,819
Derivative liability and other current liabilities		86,784			7,767
Total current liabilities		215,194			139,568
Notes Payable		134,205			274,000
Convertible Senior Notes		172,500			—
Asset Retirement Obligations		36,101			35,003
Liabilities Associated with Assets Held for Sale		—			45
Deferred Income Taxes		121,002			99,149
Other Noncurrent Liabilities		4,583			8,411
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 44,760,955 and 44,958,657 shares issued and outstanding at December 31, 2007 and March 31, 2008, respectively, with 564,100 and 588,144 shares subject to restrictions, respectively		44			44
Additional paid-in capital		745,632			742,492
Retained earnings		56,913			26,205
Treasury stock, at cost: zero shares at December 31, 2007 and March 31, 2008		—			—
Accumulated other comprehensive income (loss)		(53,273	)		4,770
Total stockholders’ equity		749,316			773,511
Total	$	1,432,901		$	1,329,687

See notes to unaudited condensed consolidated financial statements.

3

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended March 31,
	2008			2007
	(in thousands, except share and per share amounts)
Operating and Other Revenues:
Oil and gas production	$	149,045		$	96,882
Unrealized derivative loss		(1,530	)		—
Other		1,687			1,498
Total operating and other revenues		149,202			98,380
Operating Expenses:
Lease operating expense		9,301			8,840
Gathering and transportation expense		9,399			5,126
Production tax expense		10,259			5,557
Exploration expense		641			1,606
Impairment, dry hole costs and abandonment expense		1,552			3,598
Depreciation, depletion and amortization		50,957			39,073
General and administrative expense		14,215			9,168
Total operating expenses		96,324			72,968
Operating Income		52,878			25,412
Other Income and Expense:
Interest and other income		472			532
Interest expense		(3,626	)		(2,875	)
Total other income and expense		(3,154	)		(2,343	)
Income before Income Taxes		49,724			23,069
Provision for Income Taxes		19,016			8,885
Net Income	$	30,708		$	14,184
Net Income Per Common Share, Basic	$	0.69		$	0.32
Net Income Per Common Share, Diluted	$	0.68		$	0.32
Weighted Average Common Shares Outstanding, Basic		44,279,033			43,931,828
Weighted Average Common Shares Outstanding, Diluted		45,225,160			44,201,207

See notes to unaudited condensed consolidated financial statements.

4

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND

COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

	Common Stock		Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity			Comprehensive Income (loss)
Balance — December 31, 2006	$	44	$	727,486		$	(504	)	$	—		$	29,371		$	756,397
Cumulative effect of adoption of Financial Accounting Standards Board Interpretation No. (FIN) 48		—		—			(45	)		—			—			(45	)	$	—
Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding		—		7,602			—			(3,319	)		—			4,283			—
Stock-based compensation		—		10,723			—			—			—			10,723			—
Retirement of treasury stock		—		(3,319	)		—			3,319			—			—			—
Comprehensive income:
Net income		—		—			26,754			—			—			26,754			26,754
Effect of derivative financial instruments, net of $14,604 of taxes		—		—			—			—			(24,601	)		(24,601	)		(24,601	)
Total comprehensive income																		$	2,153
Balance — December 31, 2007	$	44	$	742,492		$	26,205		$	—		$	4,770		$	773,511
Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding		—		1,629			—			(2,295	)		—			(666	)	$	—
Stock-based compensation		—		3,806			—			—			—			3,806			—
Retirement of treasury stock		—		(2,295	)		—			2,295			—			—			—
Comprehensive income:
Net income		—		—			30,708			—			—			30,708			30,708
Effect of derivative financial instruments, net of $34,416 of taxes		—		—			—			—			(58,043	)		(58,043	)		(58,043	)
Total comprehensive loss																		$	(27,335	)
Balance — March 31, 2008	$	44	$	745,632		$	56,913		$	—		$	(53,273	)	$	749,316

See notes to unaudited condensed consolidated financial statements.

5

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three months Ended March 31,
	2008			2007
	(in thousands)
Operating Activities:
Net Income	$	30,708		$	14,184
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		50,957			39,073
Deferred income taxes		18,906			8,885
Impairment, dry hole costs and abandonment expense		1,552			3,598
Unrealized derivative loss		1,530			—
Stock compensation and other non-cash charges		3,974			2,069
Amortization of deferred financing costs		248			112
Gain on sale of properties		(172	)		(1,002	)
Change in operating assets and liabilities:
Accounts receivable		(19,532	)		958
Prepayments and other assets		(3,114	)		(1,483	)
Accounts payable, accrued and other liabilities		(3,082	)		(13,492	)
Amounts payable to oil and gas property owners		(1,145	)		4,316
Production taxes payable		4,366			1,636
Net cash provided by operating activities		85,196			58,854
Investing Activities:
Additions to oil and gas properties, including acquisitions		(114,992	)		(87,094	)
Additions of furniture, equipment and other		(605	)		(1,432	)
Proceeds from sale of properties		1,212			1,335
Net cash used in investing activities		(114,385	)		(87,191	)
Financing Activities:
Proceeds from debt		199,800			12,000
Principal payments on debt		(167,014	)		—
Proceeds from sale of common stock		1,629			352
Deferred financing costs and other		(4,588	)		(82	)
Net cash provided by financing activities		29,827			12,270
Increase (Decrease) in Cash and Cash Equivalents		638			(16,067	)
Beginning Cash and Cash Equivalents		60,285			41,322
Ending Cash and Cash Equivalents	$	60,923		$	25,255

See notes to unaudited condensed consolidated financial statements.

6

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

March 31, 2008

1. Organization

Bill Barrett Corporation (the “Company”, “we” or “us”), a Delaware corporation, is an independent oil and gas company engaged in the exploration, development and production of natural gas and crude oil. Since its inception in January 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States.

2. Summary of Significant Accounting Policies

Basis of Presentation.The accompanying Unaudited Condensed Consolidated Financial Statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information. Pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. In the opinion of management, the accompanying Unaudited Condensed Consolidated Financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of March 31, 2008 and our results of operations and cash flows for the three months ended March 31, 2007 and 2008. Operating results for the three months ended March 31, 2008 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, the uncertainty of exploration and development drilling results, and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, these Unaudited Condensed Consolidated Financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2007 previously filed with the SEC.

In the course of preparing the unaudited Condensed Consolidated Financial Statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

The most significant areas requiring the use of assumptions, judgments and estimates relate to volumes of natural gas and oil reserves used in calculating depletion, the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining future abandonment obligations, impairments of undeveloped properties, valuing deferred tax assets and estimating fair values of derivative instruments.

Oil and Gas Properties.The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Unaudited Condensed Consolidated Statements of Cash Flows pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs are also capitalized. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. The weighted average interest rate, including interest and commitment fees paid on the unused portion of the Company’s credit facility, amortization of deferred financing and debt issuance costs and the effects of interest rate hedges, used to capitalize interest was 7.1% for the three months ended March 31, 2007 and 5.7% for the three months ended March 31, 2008. The Company capitalized interest costs of $0.4 million for both the three months ended March 31, 2007 and 2008.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unevaluated properties are assessed periodically on a property-by-property basis, and any impairment in value is charged to expense. If the unevaluated properties are subsequently determined to be productive, the related costs are transferred to proved oil and gas properties. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered.

7

Materials and supplies consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market, on a first-in, first-out basis.

The following table sets forth the net capitalized costs and associated accumulated depreciation, depletion and amortization, including impairments, relating to the Company’s natural gas and oil producing activities including net capitalized costs associated with properties held for sale of $2.3 million ($0.3 million in total proved properties and $2.0 million in total unevaluated properties, net of $2.2 million of accumulated depreciation, depletion, amortization, and impairment) as of December 31, 2007 and $1.1 million in unevaluated properties as of March 31, 2008. See Note 5 for further information on properties held for sale.

	As of March 31, 2008			As of December 31, 2007
	(in thousands)
Proved properties	$	370,541		$	369,976
Wells and related equipment and facilities		1,056,701			974,005
Support equipment and facilities		130,935			123,020
Materials and supplies		5,334			6,132
Total proved oil and gas properties		1,563,511			1,473,133
Accumulated depreciation, depletion, amortization and impairment		(568,758	)		(521,691	)
Total proved oil and gas properties, net	$	994,753		$	951,442
Unevaluated properties	$	110,044		$	106,996
Wells and facilities in progress		136,888			126,529
Total unevaluated oil and gas properties, excluded from amortization	$	246,932		$	233,525

Net changes in capitalized exploratory well costs for the three months ended March 31, 2008 are reflected in the following table (in thousands):

Beginning of period	$	82,214
Additions to capitalized exploratory well costs pending the determination of proved reserves		65,981
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(56,191	)
Exploratory well costs charged to dry hole costs and abandonment expense (1)		(1,403	)
End of period	$	90,601

(1) Excludes expired leasehold abandonment expense of $0.1 million.

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of gross wells for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.

	March 31, 2008
	(in thousands)
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	71,704
Capitalized exploratory well costs that have been capitalized for a period greater than one year		18,897
End of period balance	$	90,601
Number of exploratory wells that have costs capitalized for a period greater than one year		101

As of March 31, 2008, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling are $18.9 million. Nearly all of our exploratory wells that have been capitalized for a period greater than one year are located in the Powder River Basin. In this basin, the Company drills wells into various coal seams. In order to produce gas from the coal seams, a period of dewatering lasting up to 24 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 addition to its wells in the Powder River Basin, the Company has two wells that have been capitalized for greater than one year. These wells, which are located in the Paradox and Uinta Basins, are either in a testing phase or are waiting on pipeline.

8

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

During the three months ended March 31, 2007 and 2008, the Company did not recognize any non-cash impairment charges.

The provision for depreciation, depletion, and amortization (“DD&A”) of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Oil is converted to natural gas equivalents, Mcfe, at the rate of one barrel to six Mcf. Taken into consideration in the calculation of DD&A are estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.

Stock-Based Compensation.The Company accounts for stock-based compensation in accordance with SFAS No. 123 (revised 2004),Share-Based Payment(“SFAS No. 123R”), which revises SFAS No. 123,Accounting for Stock-Based Compensation,and supersedes Accounting Principles Board (“APB”) Opinion No. 25,Accounting for Stock Issued to Employees.SFAS No. 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods and services, focusing primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R also addresses transactions in which an entity incurs liabilities in exchange for goods and services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments.

For awards granted before we were a public company (i.e. those granted prior to April 16, 2004, which is defined by SFAS No. 123R as the date we became a public company as a result of filing our Form S-1 registration statement with the SEC), we continue to use the minimum value method described under APB Opinion No. 25. For awards granted after we were a public company (those granted subsequent to April 16, 2004) and for new, modified, repurchased, or cancelled awards on or subsequent to our adoption of SFAS No. 123R on October 1, 2004, we recognized share-based employee compensation cost based on the fair value as computed under SFAS No. 123R. The Company continues to account for certain stock options under the original provisions of APB Opinion No. 25 because those options were issued prior to April 16, 2004, when we were considered a nonpublic entity as defined by SFAS No. 123R.

On May 9, 2007, the Compensation Committee of the Board of Directors of the Company approved a performance share program pursuant to the Company’s 2004 Stock Incentive Plan for the Company’s officers and other senior employees pursuant to which vesting of awards is contingent upon meeting various Company-wide performance goals. Upon commencement of the program and during each year of the program, the Compensation Committee will meet to approve target and stretch goals for certain operational or financial metrics that are selected by the Committee for the upcoming year and to determine whether metrics for the prior year have been met. These performance-based awards contingently vest over a period up to four years, depending on the level at which the performance goals are achieved. Each year for four years, it is possible for between 25 percent and 50 percent of the original shares to vest based on meeting performance goals. Twenty-five percent of the total grant will vest for metrics met at the target level, and an additional 25 percent of the total grant will vest for performance met at the stretch level. If the actual results for a metric are between the target levels and the stretch levels, the vested number of shares will be adjusted on a prorated basis of the actual results compared to the target and stretch goals. In any event, the total number of common shares that could become vested will not exceed the original number of performance shares granted. At the end of four years, any shares that have not vested will be forfeited. A total of 250,000 shares under the 2004 Stock Incentive Plan were set aside for this program.

For the year ended December 31, 2007, the performance goals consisted of annual production growth (weighted at 30%), additions to our natural gas and oil reserves (weighted at 30%), finding and development costs (weighted at 30%), and general and administrative expenses (weighted at 10%). The weighting was determined by the Compensation Committee. Each metric is independent so that vesting can occur for one or more metrics even if the goals are not achieved for other metrics. Also for the year ended December 31, 2007, the Compensation Committee required that an initial threshold level for finding and development costs be met before any of the performance shares would vest. In future years of the program, the Compensation Committee may impose initial threshold levels based on this or other metrics. Based upon Company performance in 2007, 30% of the performance shares granted in 2007 vested in February 2008, and the Company recognized the remaining $0.5 million of compensation costs related to these awards.

As new goals are established each year, a new grant date and a new fair value are created for financial reporting purposes for those shares that could potentially vest in the upcoming year. Compensation cost is recognized based upon the probability that the performance goals will be met. If such goals are not met, no compensation cost is recognized and any previously recognized compensation cost is reversed.

9

In February 2008, the Compensation Committee approved the performance metrics for vesting of the performance shares based on 2008 performance. For the year ending December 31, 2008, the performance goals consisted of annual production growth (weighted at 30%), additions to our natural gas and oil reserves (weighted at 30%), finding and development costs (weighted at 30%), and lease operating expenses (weighted at 10%). Also for the year ending December 31, 2008, the Compensation Committee requires that an initial threshold level for finding and development costs be met before any of the performance shares will vest. For the three months ended March 31, 2008, 159,460 performance-based nonvested equity shares of common stock, which represents the remaining unvested performance shares that were granted in 2007, along with 11,200 newly granted performance-based nonvested equity shares of common stock, were subject to the new grant date and the fair value was remeasured at a weighted-average of $42.83 per share. Of those performance-based nonvested equity shares, 121,900 could potentially vest if all performance goals are met at the stretch level. Based upon the number of shares expected to vest through February 2009, the Company recognized $0.3 million of non-cash stock-based compensation associated with these shares.

During the three months ended March 31, 2008, the Company granted 672,600 options to purchase shares of common stock with a weighted average exercise price of $42.86 per share, 191,300 nonvested equity shares of common stock and 11,200 performance-based nonvested equity shares of common stock. We recorded non-cash stock-based compensation related to option, nonvested equity share, and performance-based nonvested equity share awards of $1.9 million and $3.5 million for the three months ended March 31, 2007 and 2008, respectively, including $0.8 million associated with the performance-based nonvested equity shares. As of March 31, 2008, there were $32.8 million of total compensation costs related to grants of nonvested stock options and nonvested equity shares of common stock grants that are expected to be recognized over a weighted-average period of 2.9 years. This amount includes $1.5 million related to the performance-based nonvested equity shares that is expected to be recognized ratably over the next 10 months based on current expectations for 2008 performance.

The Company’s directors may elect to receive their annual retainer and meeting fees in the form of the Company’s common stock issued pursuant to the Company’s 2004 Stock Incentive Plan. After each quarter, shares with a value equal to the fees payable for that quarter, calculated using the closing price on the last trading day before the end of the quarter, will be delivered to each outside director who elected before that quarter to receive shares for payment of the director fees. For the three months ended March 31, 2008, the Company issued 1,330 shares of common stock for payment of the director fees and recognized $0.06 million of non-cash stock-based compensation associated with those shares.

New Accounting Pronouncements.In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157,Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and expands disclosure requirements regarding fair value measurement. The Company partially adopted SFAS No. 157 as of January 1, 2008, pursuant to FASB Staff Position (“FSP”) No. FAS 157-2,Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008.

In accordance with FSP No. FAS 157-2, the Company did not apply SFAS No. 157 to nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities, including nonfinancial long-lived assets measured at fair value for an impairment assessment under SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, and asset retirement obligations initially measured at fair value under SFAS No. 143,Accounting for Asset Retirement Obligations. The Company is still required to apply SFAS No. 157 to recurring fair value measurements of financial and non-financial instruments, which affects the fair value disclosures of our financial derivatives within the scope of SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. See Note 8 for fair value disclosures.

In February 2007, the FASB issued SFAS No. 159,Fair Value Option for Financial Assets and Financial Liabilities, which permits entities to choose to measure many financial instruments and certain other items at fair value. This statement expands the use of fair value measurement and applies to entities that elect the fair value option. The Company adopted this statement as of January 1, 2008; however, we did not elect the fair value option for any eligible financial instruments or other items.

In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations, (“SFAS No. 141R”) which replaces FASB Statement No. 141,Business Combinations. This statement requires an acquirer to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions specified in the statement. This includes the measurement of the acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for pre-acquisition gain and loss contingencies, the recognition of capitalized in-process research and development, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs, and the recognition of changes in the acquirer’s income tax valuation allowance and deferred taxes. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.

In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities. This statement is intended to improve financial reporting about derivative instruments and hedging activities by requiring companies to enhance disclosure about how these instruments and activities affect their financial position, performance and cash flows. SFAS No. 161 achieves these improvements by requiring disclosure of the fair values of derivative instruments and their gains and

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losses in a tabular format. It also improves the transparency about the location and amounts of derivative instruments in a company’s financial statements and how they are accounted for under SFAS No. 133. This statement will be effective for the Company beginning January 1, 2009. The adoption of SFAS No. 161 is not expected to have a material impact on our financial statements.

3. Earnings Per Share

Basic net income per common share is calculated by dividing net income attributable to common stock by the weighted average of common shares outstanding during each period. Diluted net income attributable to common stockholders is calculated by dividing net income attributable to common stockholders by the weighted average of common shares outstanding and other dilutive securities. Net income attributable to common stock is calculated by reducing net income by dividends earned on preferred securities. Potentially dilutive securities for the diluted earnings per share calculations consist of unvested equity shares of common stock, in-the-money outstanding stock options to purchase the Company’s common stock and shares into which the 5% Convertible Senior Notes (“Convertible Notes”) due 2028 are convertible.

The Company’s Convertible Notes have a net-share settlement right. The Company currently intends to cash settle the Convertible Notes at or near the initial redemption date of March 26, 2012; therefore, the treasury stock method was used to measure the potentially dilutive impact of shares associated with that conversion feature. The Convertible Notes issued March 12, 2008 have not been dilutive for the entire time they have been outstanding and, therefore, do not impact the diluted earnings per share calculation for the period ended March 31, 2008.

The following table sets forth the calculation of basic and diluted earnings per share (in thousands, except per share amounts):

	For three months ended March 31,
	2008		2007
Net income	$	30,708	$	14,184
Adjustments to net income for dilution		—		—
Net income adjusted for the effect of dilution	$	30,708	$	14,184
Basic weighted-average common shares outstanding in period		44,279		43,932
Add dilutive effects of stock options and nonvested equity shares of common stock		946		269
Diluted weighted-average common shares outstanding in period		45,225		44,201
Basic income per common share	$	0.69	$	0.32
Diluted income per common share	$	0.68	$	0.32

4. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows (in thousands):

	For three months ended March 31,
	2008			2007
Cash paid for interest (net of amount capitalized)	$	3,597		$	2,486
Cash paid for income taxes, net of refunds received		253			152
Supplemental disclosures of non-cash investing and financing activities:
Reduction of deferred tax liability – Powder River Basin properties acquisition purchase price allocation		—			1,635
Current liabilities that are reflected in investing activities		58,116			(7,337	)
Current liabilities that are reflected in financing activities		645			—
Net change in asset retirement obligations		(1,013	)		353
Treasury stock acquired from employee stock option exercises and collection of employee payroll taxes on vesting of restricted stock		2,295			3,187
Retirement of treasury stock		(2,295	)		(3,187	)

5. Acquisitions, Dispositions and Property Held for Sale

Property Held for Sale

Assets are classified as held for sale when the Company commits to a plan to sell the assets and completion of the sale is probable and expected to occur within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted and a loss is recognized, if any, based upon the excess of carrying value over fair value less costs to sell. Previous losses may be reversed up to the original carrying value as estimates are revised; however, gains are recognized only upon disposition.

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During the quarter ended September 30, 2007, the Company began actively marketing its Hingeline Prospect in the Uinta Basin. In accordance with SFAS No. 144, these properties are carried at the lower of historical cost or fair value less costs to sell and were reclassified to oil and gas properties held for sale on the Unaudited Condensed Consolidated Balance Sheets. The entire net book value of the Hingeline Prospect of $1.1 million is classified as unevaluated leasehold and is not subject to depletion.

Dispositions

In January 2008, the Company completed the sale of substantially all remaining properties in the DJ Basin. The Company received approximately $1.2 million in cash proceeds and recognized a $0.2 million pre-tax gain, which is included in other operating revenues in the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2008.

6. Long-Term Debt

Revolving Credit Facility

On March 17, 2006, the Company amended its credit facility (the “Amended Credit Facility”). The Amended Credit Facility had commitments of $400.0 million, which were expanded to $545.0 million as of November 6, 2007, and had an initial borrowing base of $280.0 million. Based on year-end 2007 reserves and hedge position, the borrowing base was increased to $510.0 million on March 12, 2008. The borrowing base was reduced by $43.0 million to $467.0 million after the Company issued the Convertible Notes. Future borrowing bases will be computed based on proved natural gas and oil reserves and hedge position. The Amended Credit Facility matures on March 17, 2011 and bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 1.0% to 1.75% or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 0.25%. The average annual interest rate incurred on this debt was 6.2% and 6.0% for the three months ended March 31, 2007 and 2008, respectively. The Company pays annual commitment fees ranging from 0.25% to 0.375% of the unused borrowing base. The Amended Credit Facility is secured by natural gas and oil properties representing at least 80% of the value of the Company’s proved reserves and the pledge of all of the stock of our subsidiaries.

As of March 31, 2008, borrowings outstanding under the Amended Credit Facility totaled $134.0 million.

5% Convertible Senior Notes Due 2028

On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed, or purchased by the Company. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our future subordinated indebtedness; and effectively subordinated to all of our secured indebtedness, with respect to the collateral securing such indebtedness. The Convertible Notes will be structurally subordinated to all present and future secured and unsecured debt and other obligations of our subsidiaries that do not guarantee the Convertible Notes. As of March 31, 2008 the Convertible Notes are not guaranteed by any of our subsidiaries.

The conversion price is approximately $66.33 per share of our common stock, equal to the applicable conversion rate of 15.0761 shares of our common stock, subject to adjustment, for each $1,000 face amount of Convertible Note. Upon conversion of the Convertible Notes, holders will receive, at our election, cash, shares of common stock, or a combination of cash and shares of common stock.

The Convertible Notes will bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year, beginning September 15, 2008.

On or after March 26, 2012, the Company may redeem for cash all or a portion of the Convertible Notes at a redemption price equal to 100% of the principal amount of the Convertible Notes to be redeemed plus accrued and unpaid interest, if any, up to, but excluding, the applicable redemption date. Currently, it is the Company’s intention to net cash settle the Convertible Notes. However, the Company has not made a formal legal irrevocable election to net share settle and reserves the right to settle the Convertible Notes in any manner allowed under the indenture for the Convertible Notes as business conditions warrant.

Holders of the Convertible Notes may require the Company to purchase all or a portion of their Convertible Notes on each of March 20, 2012, March 20, 2015, March 20, 2018, and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. The Company may pay the purchase price in cash, in shares of common stock, or in any combination of cash and common stock. Based on the market price of the Convertible Notes, the estimated fair value was approximately $184.4 million as of March 31, 2008.

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Holders may convert their Convertible Notes into cash, shares of our common stock, or a combination of cash and shares of our common stock, as elected by us, at any time prior to the close of business on September 20, 2027 if any of the following conditions are satisfied: (1) if the closing price of the Company’s common stock reaches specified thresholds or the trading price of the Convertible Notes falls below specified thresholds; (2) if the Convertible Notes have been called for redemption; (3) if we make certain significant distributions to holders of our common stock, or (4) we enter into specified corporate transactions. After September 20, 2027, holders may surrender their Convertible Notes for conversion at any time prior to the close of business on the business day immediately preceding the maturity date regardless of whether any of the foregoing conditions have been satisfied.

In addition, following certain corporate transactions that constitute a qualifying fundamental change, we are required to increase the applicable conversion rate for a holder who elects to convert its Convertible Notes.

In August 2007, the FASB proposed FASB Staff Position (“FSP”) APB 14-a,Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (including Partial Cash Settlement). FSP APB 14-a proposes that the accounting treatment for certain convertible debt instruments that may be settled in cash, shares of common stock, or any portion thereof at the election of the issuing company be accounted for utilizing a bifurcation model under which the value of the debt instrument would be determined without regard to the conversion feature. The difference between this issuance amount of the debt instrument and the value determined pursuant to FSP APB 14-a will be recorded as an equity contribution. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. FSP APB 14-a is a proposed FASB staff position. If FSP APB 14-a is adopted, the Company would be required to retrospectively re-value the Convertible Notes.

7. Asset Retirement Obligations

The Company accounts for its asset retirement obligations in accordance with SFAS No. 143. This statement generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset.

A reconciliation of our asset retirement obligations for the three months ended March 31, 2008 is as follows (in thousands):

Beginning of period	$	35,849
Liabilities incurred		816
Liabilities settled		(634	)
Accretion expense		794
Revisions to estimate		243
End of period	$	37,068
Less: current asset retirement obligations		967
Long-term asset retirement obligations	$	36,101

8. Fair Value of Derivatives and Other Financial Instruments

The Company’s financial instruments, including cash and cash equivalents, accounts and notes receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Amended Credit Facility, as discussed in Note 6, approximates the fair value due to its floating rate structure. The Convertible Notes are recorded at cost, and the estimated fair value is disclosed in Note 6.

Effective January 1, 2008, the Company partially adopted SFAS No. 157 pursuant to FASB Staff Position No. FAS 157-2, which delayed the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008. Therefore, the Company applied SFAS No. 157 to recurring fair value measurements of its financial derivatives as of January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and expands disclosure requirements regarding fair value measurement.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) for valuation as a practical expedient for assigning fair value. The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. These inputs can be readily observable, market corroborated, or generally unobservable. The Company primarily applies the market and income approaches for recurring fair value measurements and utilizes the best available information. Given the Company’s historical market transactions, its markets and instruments are fairly liquid. Therefore, the Company has been able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements).

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Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.

Level 3 –Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance sheet date, the Company performs an analysis of all instruments subject to SFAS 157 and includes in level 3 all of those whose fair value is based on significant unobservable inputs. As of March 31, 2008, the Company had no level 3 measurements.

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and financial liabilities that were accounted for at fair value on a recurring basis as of March 31, 2008. As required by SFAS No. 157, financial assets and financial liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of assets and liabilities and their placement within the fair value hierarchy levels.

	Level 1		Level 2			Level 3		Total
	(in thousands)
Assets
Commodity Derivatives	$	—	$	3,819		$	—	$	3,819
Liabilities
Commodity Derivatives	$	—	$	(89,479	)	$	—	$	(89,479	)
Interest Rate Derivatives		—		(727	)		—		(727	)

As required under SFAS No. 157, all fair values reflected in the table above and on the Unaudited Condensed Consolidated Balance Sheets have been adjusted for non-performance risk. For applicable financial assets carried at fair value, the credit standing of the counterparties is analyzed and factored into the fair value measurement of those assets. SFAS No. 157 also states that the fair value measurement of a liability must reflect the nonperformance risk of the entity. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Level 1 Fair Value Measurements

As of March 31, 2008, the Company did not have assets or liabilities measured under a Level 1 fair value hierarchy.

Level 2 Fair Value Measurements

Crude Oil Forwards and Options — The fair value of the crude oil forwards and options are estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

Natural Gas Forwards and Options — The fair value of the natural gas forwards and options are estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

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Interest rate Forwards and Options — The fair value of the interest rate forwards and options are estimated using a combined income and market valuation methodology based upon forward interest-rate yield curves and credit. The curves are obtained from independent pricing services reflecting broker market quotes.

Level 3 Fair Value Measurements

As of March 31, 2008, the Company did not have assets or liabilities measured under a Level 3 fair value hierarchy.

Oil and Gas Commodity Hedges

The Company periodically uses financial derivative instruments to achieve a more predictable cash flow from its natural gas and oil production by reducing its exposure to price fluctuations. The Company has entered into financial commodity swap and collar contracts to fix the floor and ceiling prices we receive for a portion of our natural gas and oil production. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s natural gas and oil derivative financial instruments are accounted for in accordance with SFAS No. 133.As of March 31, 2008, the Company has hedges in place for anticipated production through 2010 for a total of 494,125 Bbls of crude oil and 100,855,000 MMBtu of natural gas.

In addition to financial transactions, the Company is a party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and sales exceptions as mentioned above, are recorded at fair market value in accordance with SFAS No. 157 and included in the Unaudited Condensed Consolidated Balance Sheets as assets or liabilities. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Realized gains and losses on cash flow hedges are transferred from comprehensive income and recognized in earnings and included within oil and gas production revenues in the Unaudited Condensed Consolidated Statements of Operations as the associated production occurs. Unrealized gains and losses from the change in the fair value and realized gains and losses of derivative instruments that do not qualify as cash flow hedges, as well as the ineffective portion of hedge derivatives are reported in earnings in the Unaudited Condensed Consolidated Statements of Operations.

At March 31, 2008, the estimated fair value of all of our commodity derivative instruments was a net liability of $85.7 million comprised of current and noncurrent assets and liabilities. The Company will reclassify the appropriate amounts from other comprehensive income to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected market prices as of March 31, 2008, the amount to be reclassified from other comprehensive income to net income in the next 12 months would be a net, after-tax reduction of approximately $53.2 million for our cash flow hedges. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. The Company anticipates that all originally forecasted transactions related to our cash flow hedges will occur by the end of the originally specified time periods.

The company utilizes hedging instruments that are designed to mitigate the Company’s exposure to volatile oil and gas prices and are deemed to be effective under SFAS No. 133. The hedge instruments are at highly liquid trading locations but may contain slight differences compared to the delivery location of the forecasted sale, which may result in ineffectiveness. Ineffectiveness related to our derivative instruments was $1.5 million for the three months ended March 31, 2008, which was reported in the Unaudited Condensed Consolidated Statements of Operations. Ineffectiveness for the prior year period was de minimus.

The Company was a party to various swap and collar contracts for natural gas based on the Colorado Interstate Gas Rocky Mountains (“CIGRM”) index that settled during the three months ended March 31, 2007 and based on the CIGRM and Panhandle Eastern Pipe Line Co. (“PEPL”) indices that settled during the three months ended March 31, 2008. As a result, the Company recognized an increase of natural gas production revenues related to these contracts of $7.2 million and $0.3 million in the three months ended March 31, 2007 and 2008, respectively. The Company also was a party to various swap and collar contracts for oil based on a West Texas Intermediate (“WTI”) index, recognizing an increase of $0.2 million and a reduction of $2.1 million to oil production revenues related to these contracts in the three months ended March 31, 2007 and 2008, respectively.

Interest Rate Derivative Contracts

In December 2006, the Company entered into two interest rate derivative contracts to manage the Company’s exposure to changes in interest rates. The first contract was a floating-to-fixed interest rate swap for a notional amount of $10.0 million and the second was a floating-to-fixed interest rate collar for a notional amount of $10.0 million, both to terminate on December 12, 2009. The Company’s interest rate derivative instruments have been designated as cash flow hedges in accordance with SFAS No. 133. Changes in fair value of the interest rate swaps or collars are reported in other comprehensive income, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. Ineffectiveness related to the Company’s interest rate derivative instruments was de minimus for both the three months ended March 31, 2007 and 2008.

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Under the swap, the Company will make payments to or receive payments from the contract counterparty when the variable rate of one-month LIBOR falls below, or exceeds, the fixed rate of 4.70%. Under the collar, the Company will make payments to, or receive payments from, the contract counterparty when the variable LIBOR rate falls below the floor rate of 4.50% or exceeds the ceiling rate of 4.95%. The payment dates of both the swap and the collar match exactly with the interest payment dates of the corresponding portion of our Amended Credit Facility.

During the three months ended March 31, 2008, net settlement payments, which were included in interest expense, were insignificant. The Company anticipates that all originally forecasted transactions will occur by the end of the originally specified time periods and as of March 31, 2008, based on current projected interest rates, the amount to be reclassified from other comprehensive income to earnings in the next 12 months would be a net reduction of approximately $0.3 million. At March 31, 2008, the estimated fair value of the interest rate derivatives was a net liability of $0.7 million.

9. Income Taxes

The Company adopted the provisions of FASB Interpretation (“FIN”) No. 48,Accounting for Uncertainty in Income Taxes, on January 1, 2007. The adoption did not result in a material adjustment to our tax liability for unrecognized income tax benefits. During the first quarter of 2008, there was no change to our FIN No. 48 liability.

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. As of March 31, 2008, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the three months ended March 31, 2008.

The change in the liability for unrecognized tax benefit will not affect the annual effective tax rate and will reduce the Company’s net operating loss carry forward. The Company does not expect a significant change to the liability for unrecognized tax benefits within the next 12 months.

At March 31, 2008, the Company’s Unaudited Condensed Consolidated Balance Sheets reflected a net deferred tax liability of $89.1 million, of which $31.6 million pertains to a net deferred tax asset for derivative instruments reflected in other comprehensive income.

Income tax expense for the three months ended March 31, 2007 and 2008 differs from the amounts that would be provided by applying the U.S. federal income tax rate to income before income taxes principally due to state income taxes, stock-based compensation not deductible for income tax purposes, and other permanent differences.

10. Stockholders’ Equity

The Company’s authorized capital structure consists of 75,000,000 shares of $0.001 per share par value preferred stock and 150,000,000 shares of $0.001 per share par value common stock. In October 2004, 150,000 shares of $0.001 per share par value preferred stock were designated as Series A Junior Participating Preferred Stock, none of which are outstanding. At March 31, 2008, the Series A Junior Participating Preferred Stock was the Company’s only designated preferred stock, and the remainder of the authorized preferred stock is undesignated. There are no issued and outstanding shares of Preferred Stock.

Holders of all classes of stock are entitled to vote on matters submitted to stockholders, except that, when issued, each share of Series A Junior Participating Preferred Stock will entitle the holder thereof to 1,000 votes on all matters submitted to a vote of the Company’s stockholders.

The Series A Junior Participating Preferred Stock will be issued pursuant to the Company’s shareholder rights plan if a stockholder acquires shares in excess of the thresholds set forth in the plan. The Series A Junior Participating Preferred Stock ranks junior to all series of preferred stock with respect to dividends and specified liquidation events. Dividends on this series are cumulative and do not bear interest; however, no dividend payment, or payment-in-kind, may be made to holders of common stock without declaring a dividend on this series equal to 1,000 times the aggregate per share amount declared on common stock. Upon the occurrence of specified liquidation events, the holders of this series will be entitled to receive an aggregate amount per share equal to 1,000 times the aggregate amount to be distributed per share to holders of shares of common stock plus an amount equal to any accrued and unpaid dividends. Upon consolidation, merger, or combination in which shares of common stock are exchanged for or changed into other securities or other assets, each share of this series will be similarly exchanged into an amount per share equal to 1,000 times that into which each share of common stock is exchanged. The number of Series A Junior Participating Preferred Stock will be proportionately changed in the event the Company declares or pays a common stock dividend or effects a stock split of common stock.

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The Company may occasionally acquire treasury stock, which is recorded at cost, in connection with the vesting and exercise of stock-based awards or for other reasons. As of March 31, 2008, all treasury stock held by the Company was retired.

11. Accumulated Other Comprehensive Income

The components of accumulated other comprehensive income and related tax effects for the three months ended March 31, 2008 were as follows:

	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated other comprehensive income—December 31, 2007	$	7,602		$	(2,832	)	$	4,770
Unrealized change in fair value of hedges		(94,233	)		35,075			(59,158	)
Reclassification adjustment for realized gains on hedges included in net income		1,774			(659	)		1,115
Accumulated other comprehensive loss—March 31, 2008	$	(84,857	)	$	31,584		$	(53,273	)

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

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs, and expected performance. The forward-looking statements are dependent upon events, risks, and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, changes in estimates of proved reserves, potential failure to achieve production from exploration or development projects, capital expenditures and other uncertainties, as well as those factors discussed below and in our Annual Report on Form 10-K for the year ended December 31, 2007 under the “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” sections, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. The Company does not undertake any obligation to publicly update any forward-looking statements.

Overview

Bill Barrett Corporation (the “Company”, “we” or “us”) was formed in January 2002 and is incorporated in the State of Delaware. We explore for and develop natural gas and oil in the Rocky Mountain region of the United States. We began active natural gas and oil operations in March 2002 upon the acquisition of properties in the Wind River Basin of Wyoming. Also in 2002, we completed two additional acquisitions of properties in the Uinta (Utah), Wind River (Wyoming), Powder River (Wyoming) and Williston (North Dakota, South Dakota and Montana) Basins. In early 2003, we completed an acquisition of largely undeveloped coalbed methane properties located in the Powder River Basin. In September 2004, we acquired properties in and around the Gibson Gulch field in the Piceance Basin of Colorado. In December 2004, we completed our Initial Public Offering (“IPO”) of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. We received net proceeds of $347.3 million after deducting underwriting fees and other offering costs. We completed an acquisition in May 2006 in which we acquired additional coalbed methane properties located in the Powder River Basin. In June 2007, we completed the sale of our Williston Basin properties.

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Results of Operations

The financial information for the three months ended March 31, 2007 and 2008 that is discussed below is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

	Three months Ended March 31,					Increase (Decrease)
	2008			2007		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil and gas production	$	149,045		$	96,882	$	52,163		54	%
Unrealized derivative loss		(1,530	)		—		(1,530	)	(100	)%
Other		1,687			1,498		189		13	%
Operating Expenses
Lease operating expense		9,301			8,840		461		5	%
Gathering and transportation expense		9,399			5,126		4,273		83	%
Production tax expense		10,259			5,557		4,702		85	%
Exploration expense		641			1,606		(965	)	(60	)%
Impairment, dry hole costs and abandonment expense		1,552			3,598		(2,046	)	(57	)%
Depreciation, depletion and amortization expense		50,957			39,073		11,884		30	%
General and administrative expense		10,632			7,278		3,354		46	%
Non-cash stock-based compensation (1)		3,583			1,890		1,693		90	%
Total operating expenses	$	96,324		$	72,968	$	23,356		32	%
Production Data:
Natural gas (MMcf)		17,332			13,031		4,301		33	%
Oil (MBbls)		144			190		(46	)	(24	)%
Combined volumes (MMcfe)		18,196			14,171		4,025		28	%
Daily combined volumes (MMcfe/d)		200			157		43		27	%
Average Prices (2):
Natural gas (per Mcf)	$	8.02		$	6.68	$	1.34		20	%
Oil (per Bbl)		69.83			51.72		18.11		35	%
Combined (per Mcfe)		8.19			6.84		1.35		20	%
Average Costs (per Mcfe):
Lease operating expense	$	0.51		$	0.62	$	(0.11	)	(18	)%
Gathering and transportation expense		0.52			0.36		0.16		44	%
Production tax expense		0.56			0.39		0.17		44	%
Depreciation, depletion and amortization (3)		2.80			2.89		(0.09	)	(3	)%
General and administrative (4)		0.58			0.51		0.07		14	%

(1) Non-cash stock-based compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $9.2 million and $14.2 million for the three months ended March 31, 2007 and 2008, respectively, in the Unaudited Condensed Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower costs associated with stock-based grants.

(2) Average prices shown in the table are net of the effects of our realized hedging transactions. As a result of our realized hedging transactions, natural gas production revenues were increased by $7.2 million and $0.3 million for the three months ended March 31, 2007 and 2008, respectively, and oil production revenues were increased by $0.2 million for the three months ended March 31, 2007 and reduced by $2.1 million for the three months ended March 31, 2008. Before the effect of hedging contracts, the average price we received for natural gas for the three months ended March 31, 2007 was $6.13 per Mcf compared to $8.00 per Mcf for the three months ended March 31, 2008 and the average price we received for oil for the three months ended March 31, 2007 was $50.61 per Bbl compared to $84.18 per Bbl for the three months ended March 31, 2008.

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(3) The calculated depreciation, depletion and amortization (“DD&A”) per Mcfe based on the DD&A expense and MMcfe production data presented in the table for the three months ended March 31, 2007 is $ 2.76. The DD&A rate per Mcfe for the three months ended March 31, 2007 of $2.89, as presented in the table above, excludes production of 654 MMcfe, associated with our properties that were classified as held for sale in the Williston and DJ Basins, as these were not depleted.

(4) Excludes non-cash stock-based compensation as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation, as presented in the Unaudited Condensed Consolidated Statements of Operations, were $0.65 and $0.78 for the three months ended March 31, 2007 and 2008, respectively.

Production Revenues.Production revenues increased from $96.9 million for the three months ended March 31, 2007 to $149.0 million for the three months ended March 31, 2008, primarily due to a 28% increase in production along with a 20% increase in natural gas and oil prices after the effect of realized hedges on a per Mcfe basis. The net increase in production added approximately $33.0 million of production revenues, and the increase in prices on a per Mcfe basis increased production revenues by approximately $19.1 million.

Total production volumes for the three months ended March 31, 2008 of 18.2 Bcfe increased 28% from the three months ended March 31, 2007, with increases in production from the Piceance, Uinta and Powder River Basins, which increased 78%, 26% and 8%, respectively. The increase in production was partially offset by decreases in the Wind River Basin of 12% and a reduction due to the sale of Williston Basin properties in June 2007. Additional information concerning production is in the following table:

	Three Months Ended March 31, 2008			Three Months Ended March 31, 2007			% Increase (Decrease)
	Oil	Natural Gas	Total	Oil	Natural Gas	Total	Oil	Natural Gas	Total
	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MMcf)	(MMcfe)
Piceance Basin	101	6,917	7,523	64	3,847	4,231	58%	80%	78%
Uinta Basin	31	7,094	7,280	9	5,742	5,796	244%	24%	26%
Powder River Basin	—	1,554	1,554	—	1,434	1,434	—	8%	8%
Wind River Basin	5	1,758	1,788	9	1,968	2,022	(44)%	(11)%	(12)%
Williston Basin (1)	—	—	—	103	34	652	(100)%	(100)%	(100)%
Other	7	9	51	5	6	36	40%	50%	42%
Total	144	17,332	18,196	190	13,031	14,171	(24)%	33%	28%

(1) The sale of the Williston Basin properties was completed on June 22, 2007.

The production increase in the Piceance Basin is the result of our continued development activities, with initial sales on 83 new gross wells from April 1, 2007 to March 31, 2008. The production increase in the Uinta Basin reflects our continued exploration and development activities in the West Tavaputs, Black Tail Ridge and Lake Canyon fields. As a result, we had initial sales on 37 new gross wells from April 1, 2007 to March 31, 2008 in the Uinta Basin. The production increase in the Powder River Basin is due to the result of our continued development activities, with initial sales on 90 new gross wells from April 1, 2007 to March 31, 2008. The increase is offset by natural production declines in our existing mature fields and the lag time between drilling of coal bed methane wells and production of natural gas while dewatering occurs. As of March 31, 2008, we had 131 net operated coal bed methane wells in the dewatering stage. The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields. This decrease was partially offset with the recompletion of the Bullfrog 14-18 well, which came online in late February 2008 at an initial production rate of 12 MMcfe/d and which is currently producing at a rate of 9.5 MMcfe/d.

Hedging Activities.During the three months ended March 31, 2008, approximately 75% of our natural gas volumes and 69% of our oil volumes were hedged, resulting in an increase in gas revenues of $0.3 million, offset by a reduction in oil revenues of $2.1 million. During the three months ended March 31, 2007, we hedged approximately 57% of our natural gas volumes and 38% of our oil volumes, resulting in and increase in gas revenues of $7.2 million, and an increase in oil revenues of $0.2 million.

Other Operating Revenues.Other operating revenues increased from $1.5 million for the three months ended March 31, 2007 to $1.7 million for the three months ended March 31, 2008. Other operating revenues for the first three months of 2008 consisted of gains realized from the gains realized from the sale of properties in the DJ Basin of $0.2 million, gathering fees of $0.5 million and the sale of seismic data of $1.0 million. Other operating revenues for the first three months of 2007 primarily consisted of a gain realized on a joint exploration agreement entered into in the Paradox Basin.

Lease Operating Expense.The decrease in lease operating expense from $0.62 per Mcfe for the three months ended March 31, 2007 compared to $0.51 per Mcfe for the three months ended March 31, 2008 is primarily the result of decreased expenses in the Powder River, Piceance and Wind River Basins, offset by an increase in the Uinta Basin. The increase in the Uinta Basin from $0.36

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per Mcfe for the three months ended March 31, 2007 to $0.52 per Mcfe for the three months ended March 31, 2008 is the result of repair and maintenance to a compressor at the Company’s Dry Canyon Compressor Station, along with an increase in water disposal costs due to increased water production from 37 new gross wells that have been placed on production from April 1, 2007 to March 31, 2008. Lease operating expense decreased in the Powder River Basin from $1.43 per Mcfe for the three months ended March 31, 2007 to $1.01 per Mcfe for the three months ended March 31, 2008 primarily as a result of lower well servicing and location maintenance costs. Lease operating expense decreased in the Piceance Basin from $0.38 per Mcfe for the three months ended March 31, 2007 to $0.30 per Mcfe for the three months ended March 31, 2008 as a result of new water pipelines, which have substantially reduced water trucking expense. Lease operating expense decreased in the Wind River Basin from $0.97 per Mcfe for the three months ended March 31, 2007 to $.87 per Mcfe for the three months ended March 31, 2008 as a result of lower well servicing and workover costs. The following table displays the lease operating expense by basin:

	Three months Ended March31, 2008			Three months Ended March 31, 2007			%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)	($ in thousands)		($ per Mcfe)	(% per Mcfe)
Uinta Basin	$	3,795	$0.52	$	2,076	$0.36	44%
Piceance Basin		2,224	0.30		1,622	0.38	(21)%
Wind River Basin		1,564	0.87		1,965	0.97	(10)%
Powder River Basin		1,571	1.01		2,044	1.43	(29)%
Williston Basin		—	—		922	1.42	(100)%
Other		147	2.88		211	5.86	(51)%
Total	$	9,301	0.51	$	8,840	0.62	(18)%

Gathering and Transportation Expense.Gathering and transportation expense increased from $0.36 per Mcfe for the three months ended March 31, 2007 to $0.52 per Mcfe for the three months ended March 31, 2008 due to additional long-term firm transportation and firm processing contracts entered into throughout 2007. We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to avoid possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production from the Piceance, Uinta and Powder River Basins where we expect to spend a significant portion of our capital expenditure program in future years. In addition, we have entered into long-term firm processing contracts on a portion of our production in the Uinta and Piceance Basins to avoid possible production curtailments that may arise due to limited processing capacity. Included in the above gathering and transportation expense is $0.06 and $0.14 per Mcfe of transportation expense for the three months ended March 31, 2007 and 2008, respectively, along with $0.05 per Mcfe of processing expense from long-term contracts for the three months ended March 31, 2007 and 2008.

The increase in firm transportation expense from $0.06 per Mcfe for the three months ended March 31, 2007 to $0.14 per Mcfe for the three months ended March 31, 2008 is the result of additional long-term contracts with Rockies Express Pipeline and Questar Pipeline to deliver 25,000 gross MMBtu/d to each of their pipelines. The following table displays the gathering and transportation expense by basin:

	Three months Ended March 31, 2008			Three months Ended March 31, 2007			%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)	($ in thousands)		($ per Mcfe)	(% per Mcfe)
Piceance Basin	$	4,641	$0.62	$	2,224	$0.53	17%
Uinta Basin		2,967	0.41		1,153	0.20	105%
Powder River Basin		1,739	1.12		1,688	1.18	(5)%
Wind River Basin		47	0.03		56	0.03	0%
Other		5	0.10		5	0.01	900%
Total	$	9,399	0.52	$	5,126	0.36	44%

Production Tax Expense.Total production taxes increased from $5.6 million for the three months ended March 31, 2007 to $10.3 million for the three months ended March 31, 2008. The increase in production tax expense is primarily related to the increase in natural gas and oil revenues from $96.9 million for the three months ended March 31, 2007 to $149.0 million for the three months ended March 31, 2008. In addition, production taxes as a percentage of natural gas and oil sales before hedging adjustments were 6.2% for the three months ended March 31, 2007 and 6.8% for the three months ended March 31, 2008. Production taxes are primarily based on the wellhead values of production and the tax rates that vary across the different areas in which we operate. As the proportion of our production changes from area to area, our production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect.

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Exploration Expense.Exploration costs decreased from $1.6 million for the three months ended March 31, 2007 to $0.6 million for the three months ended March 31, 2008. Exploration costs for the three months ended March 31, 2007 consisted of $1.4 million for seismic programs, principally in the Montana Overthrust, Uinta and Paradox Basins, and $0.2 million for delay rentals and other costs. Exploration costs for the three months ended March 31, 2008 consisted of $0.4 million for seismic programs, principally in the Uinta, Paradox, Big Horn and Deseret Basins, along with $0.2 million for delay rentals and other exploration costs.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense decreased from $3.6 million during the three months ended March 31, 2007 to $1.6 million during the three months ended March 31, 2008. For the three months ended March 31, 2007, abandonment expense was $0.6 million and dry hole costs were $3.0 million for a well drilled in the Wind River Basin. For the three months ended March 31, 2008, abandonment expense was $0.2 million and dry hole costs in the Wind River Basin (non-operated) and the Montana Overthrust area were $1.4 million. All of the $1.4 million of dry hole expense was related to additional costs on wells that were deemed to be uneconomic in the prior year.

We evaluate the impairment of our oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. If the carrying amount exceeds the properties’ estimated fair value, we will adjust the carrying amount of the properties to fair value through a charge to impairment expense. For the three months ended March 31, 2007 and 2008, we did not incur any impairment charges.

We account for oil and gas exploration and production activities using the successful efforts method under which we capitalize exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense. Otherwise, the costs remain capitalized and are depleted as production occurs. The following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and gas properties as of March 31, 2008 pending determination of whether the wells will be assigned proved reserves. The following table does not include $15.4 million related to exploratory wells in progress for which drilling had not been completed at March 31, 2008:

	Time Elapsed Since Drilling Completed
	0-3 Months		4-6 Months		7-12 Months		> 12 Months		Total
	(in thousands)
Wells for which drilling has been completed	$	13,571	$	23,887	$	18,901	$	18,897	$	75,256

The majority of the $18.9 million of exploratory well costs that have been capitalized for a period greater than one year are located in the Powder River Basin. In this basin, we drill wells into various coal seams. In order to produce gas from the coal seams, a period of dewatering lasting from a few to 24 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.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense (“DD&A”) was $39.1 million for the three months ended March 31, 2007 compared to $51.0 million for the three months ended March 31, 2008. Of the increase, $13.5 million is due to an increase in production offset by an overall decrease in the DD&A rate for the three months ended March 31, 2008, which reduced DD&A by $1.6 million. During the three months ended March 31, 2007, the weighted average depletion rate was $2.89 per Mcfe. For the three months ended March 31, 2008, the weighted average depletion rate was $2.80 per Mcfe. The DD&A rate for the three months ended March 31, 2007 excludes production of 654 MMcfe associated with our properties held for sale in the Williston and DJ Basins. Under successful efforts accounting, depletion expense is separately computed for each producing area based on geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average depletion rate for current production. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased from $7.3 million in the three months ended March 31, 2007 to $10.6 million in the three months ended March 31, 2008. On a per Mcfe basis, general and administrative expense, excluding non-cash stock based compensation, increased from $0.51 per Mcfe for the three months ended March 31, 2007 to $0.58 per Mcfe for the three months ended March 31, 2008. This increase was primarily due to increased costs related to our employees’ compensation and benefit plans and additional personnel required for our capital program and production levels. As of March 31, 2008, we had 154 full time employees in our corporate office compared to 142 as of March 31, 2007. In addition, due to a change in the terms of our proposed debt offering from a high-yield debt offering to a convertible debt offering, costs of $0.4 million related to the initially proposed high-yield debt offering that would not have been incurred with the convertible debt offering were expensed.

Non-cash charges for stock-based compensation were $1.9 million for the three months ended March 31, 2007 compared to $3.6 million for the three months ended March 31, 2008. Non-cash stock-based compensation for the three months ended March 31, 2007 and 2008 is related to vesting of our stock option plans and nonvested shares of common stock issued to employees. The increase in charges for non-cash stock-based compensation is primarily due to the additional equity awards, including nonvested performance awards, that were granted during 2007 and during the three months ended March 31, 2008.

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Interest Expense.Interest expense increased to $3.6 million in the three months ended March 31, 2008 from $2.9 million in the prior year period. The increase is due to higher average outstanding balances under our Amended Credit Facility in the three months ended March 31, 2008 to fund exploration and development activities. Our weighted average outstanding debt balance, including our Amended Credit Facility and Convertible Notes issued in March 2008, was $277.8 million for the three months ended March 31, 2008 compared to $189.4 million in the prior year period.

Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use and, as a result, we had not capitalized any interest expense until the third quarter of 2006. The weighted average interest rates, including interest and commitment fees paid on the unused portion of our Amended Credit Facility, amortization of deferred financing and debt issuance costs and the effects of interest rate hedges, used to capitalize interest for the three months ended March 31, 2007 and 2008 were 7.1% and 5.7%, respectively. We capitalized interest costs of $0.4 million for both the three months ended March 31, 2007 and 2008.

Income Tax Expense. Our effective tax rates were 38.5% and 38.2% in the three months ended March 31, 2007 and 2008, respectively. For both the 2007 and 2008 periods, our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense under SFAS No. 123 (revised 2004),Share-Based Payment(“SFAS No. 123R”), that is not deductible for income tax purposes. Due to the tax deductions being created by our drilling activities, we expect that we will incur cash income tax liabilities relating only to the alternative minimum tax (“AMT”) in the next year. We have a significant deferred tax asset associated with net operating loss carryforwards (“NOLs”). It is more likely than not that we will use these NOLs to offset and reduce current tax liabilities, including AMT, in future years.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been sales and other issuances of equity securities, net cash provided by operating activities, bank credit facilities, convertible senior notes, proceeds from joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the exploration, development, and acquisition of natural gas and oil properties. As we pursue profitable reserve and production growth, we continually monitor the capital resources, including issuance of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash, we may need to obtain additional equity or debt financing.

At March 31, 2008, our balance sheet reflected a cash and cash equivalents balance of $60.9 million with a balance of $134.0 million outstanding under our Amended Credit Facility. The borrowing base under our Amended Credit Facility was increased on March 12, 2008 to $510.0 million based on our year-end 2007 reserves and was subsequently reduced to $467.0 million after issuing $172.5 million of Convertible Notes.

Cash Flow from Operating Activities

Net cash provided by operating activities was $58.9 million and $85.2 million for the three months ended March 31, 2007 and 2008, respectively. The increase in net cash provided by operating activities was primarily due to an increase in oil and gas revenues and increased non-cash expenses, as discussed above in “—Results of Operations.” Changes in current assets and liabilities decreased cash flow from operations by $8.1 million and $22.5 million for the three months ended March 31, 2007 and 2008, respectively.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of sales prices for natural gas and oil. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “—Quantitative and Qualitative Disclosure about Market Risk” below.

To mitigate some of the potential negative impact on cash flow caused by changes in natural gas and oil prices, we have entered into financial commodity swap and collar contracts to receive fixed prices for a portion of our natural gas and oil production. We typically hedge a fixed price for natural gas at our sales points (NYMEX less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. At March 31, 2008, we had in place natural gas and crude oil financial collars and swaps covering portions of our 2008, 2009 and 2010 production. Our natural gas and oil derivative financial instruments are accounted for in accordance with SFAS No. 133.

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In addition to financial transactions, we are a party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas revenues at the time of settlement, which in turn affects average realized natural gas prices.

All derivative instruments, other than those that meet the normal purchase and sales exceptions as mentioned above, are recorded at fair market value in accordance with SFAS No. 157 and are included in the Unaudited Condensed Consolidated Balance Sheets as assets or liabilities. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Realized gains and losses on cash flow hedges are transferred from comprehensive income and recognized in earnings and included within oil and gas production revenues in the Unaudited Condensed Consolidated Statements of Operations as the associated production occurs. Unrealized gains and losses from the change in the fair value and realized gains and losses of derivative instruments that do not qualify as cash flow hedges, as well as the ineffective portion of cash flow hedge derivatives are reported in earnings in the Unaudited Condensed Consolidated Statements of Operations.

At March 31, 2008, the estimated fair value of all of our commodity derivative instruments was a net liability of $85.7 million comprised of current and noncurrent assets and liabilities. We will reclassify the appropriate amounts to gains or losses included in natural gas and oil production operating revenues as the hedged production quantities are produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of March 31, 2008 to be reclassified from other comprehensive income to earnings in the next 12 months would be a net reduction of approximately $53.2 million. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. We anticipate that all originally forecasted transactions related to our cash flow hedges will occur by the end of the originally specified time periods.

The Company utilizes hedging instruments that are designed to mitigate the Company’s exposure to volatile oil and gas prices and are deemed to be effective under SFAS No. 133. The hedge instruments are at highly liquid trading locations but may contain slight differences compared to the delivery location of the forecasted sale, which may result in ineffectiveness. Ineffectiveness related to our cash flow derivative instruments for the three months ended March 31, 2008 was $1.5 million, which was reported in the Unaudited Condensed Consolidated Statements of Operations. Ineffectiveness for the prior year period was de minimus.

The Company has in place the following swap contracts and cashless collars (purchased put options and written call options) as of March 31, 2008 in order to hedge a portion of our natural gas and oil production for the remaining three quarters of 2008 and years 2009 and 2010. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production.

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Pricing		Weighted Average Ceiling Pricing		Weighted Average Fixed Price		Index Price (1)	Fair Market Value, in thousands
Cashless Collars:
2008
Natural gas	9,625,000	MMBtu	$	6.50	$	10.00		N/A	CIGRM	$	(1,770	)
Oil	144,375	Bbls	$	70.48	$	81.62		N/A	WTI	$	(2,747	)
2009
Oil	54,750	Bbls	$	81.67	$	114.67		N/A	WTI	$	(35	)
2010
Natural gas	2,140,000	MMBtu	$	7.00	$	11.00		N/A	TCO	$	(330	)
Swap Contracts:
2008
Natural gas	25,820,000	MMBtu		N/A		N/A	$	6.76	CIGRM	$	(42,000	)
Natural gas	6,509,000	MMBtu		N/A		N/A	$	6.80	PEPL	$	(13,686	)
Oil	158,125	Bbls		N/A		N/A	$	73.84	WTI	$	(3,975	)
2009
Natural gas	38,580,000	MMBtu		N/A		N/A	$	7.16	CIGRM	$	(18,732	)
Natural gas	3,285,000	MMBtu		N/A		N/A	$	7.56	PEPL	$	(3,108	)
Oil	136,875	Bbls		N/A		N/A	$	74.41	WTI	$	(2,749	)
2010
Natural gas	12,160,000	MMBtu		N/A		N/A	$	6.93	CIGRM	$	4,187
Natural gas	2,736,000	MMBtu		N/A		N/A	$	7.63	PEPL	$	(715	)

(1) CIGRM refers to Colorado Interstate Gas Rocky Mountains, TCO refers to Columbia Gas Transmission Corporation for Appalachia, and PEPL refers to Panhandle Eastern Pipe Line Company price as quoted in Platt’s Inside FERC on the first business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

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The following table includes all hedges entered into subsequent to March 31, 2008 through May 1, 2008.

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Pricing		Weighted Average Ceiling Pricing		Weighted Average Fixed Price		Index Price (1)
Cashless Collars:
2009
Oil	73,000	Bbls	$	85.00	$	128.65		N/A	WTI
2010
Oil	36,500	Bbls	$	85.00	$	128.00		N/A	WTI
Swap Contracts:
2009
Natural gas	900,000	MMBtu		N/A		N/A	$	9.57	CIGRM
2010
Natural gas	2,140,000	MMBtu		N/A		N/A	$	9.43	DA

(1) WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. DA refers to Dominion Transmission Inc. for Appalachia price as quoted in Platt’s Inside FERC on the first business day of each month.

By removing the price volatility from a portion of our natural gas and oil production for 2008, 2009 and 2010, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers.

Capital Expenditures

Our capital expenditures are summarized in the following tables:

	Three Months Ended March 31,
	(in millions)
Basin/Area	2008		2007
Uinta	$	37.8	$	29.4
Piceance		49.9		27.5
Powder River		8.1		9.4
Wind River		7.4		1.6
Other		5.8		13.1
Total	$	109.0	$	81.0

	Three Months Ended March 31,
	(in millions)
	2008		2007
Acquisitions of proved and unevaluated properties and other real estate	$	4.7	$	11.7
Drilling, development, exploration and exploitation of natural gas and oil properties		101.7		62.8
Geologic and geophysical costs and exploratory dry holes and abandonment costs		2.2		5.2
Furniture, fixtures and equipment		0.4		1.3
Total	$	109.0	$	81.0

Unevaluated properties increased $13.4 million to $246.9 million at March 31, 2008, including $1.1 million related to unevaluated properties in the Hingeline Prospect that are currently classified as held for sale at March 31, 2008, from $233.5 million at December 31, 2007, including $2.0 million related to unevaluated properties in the DJ Basin and Hingeline Prospect that were classified as held for sale. The increase is principally from an increase in wells in progress resulting from increased development and exploratory drilling activity during the three months ended March 31, 2008.

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Excluding material acquisitions, our current capital budget for 2008 is $550-$600 million, of which we plan to spend approximately $440-$485 million for development drilling and facilities, and up to $110 million on exploration drilling, leasehold acquisitions, geologic and geophysical costs, equipment and other costs. While we may reallocate capital among our areas of activity, our approved budget provides that we plan to spend $230-$240 million in the Piceance, $220-$240 million in the Uinta, $35-$40 million in the Wind River, $35-$40 million in the Powder River and up to $75 million in other areas. Based upon our current natural gas and oil price expectations and our hedge position for 2008, we anticipate that our operating cash flow and available borrowing capacity under our Amended Credit Facility will be sufficient to fund our capital expenditures at current levels for the next twelve months. Also, future cash flows are subject to a number of variables, including our level of natural gas and oil production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts to maintain planned levels of capital expenditures.

The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If natural gas and oil prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in prices, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow, availability of financing and other factors both within and outside our control.

Financing Activities

Credit Facility. On March 17, 2006, we amended our credit facility (the “Amended Credit Facility”). The Amended Credit Facility, which matures on March 17, 2011, had commitments of $400.0 million, which were expanded to $545.0 million as of November 6, 2007 with the addition of new lenders, and had an initial borrowing base of $280.0 million. Based on year-end 2007 reserves and our hedge position, the borrowing base was increased to $510.0 million on March 12, 2008. The borrowing base was reduced by $43.0 million to $467.0 million after we issued the Convertible Notes in March 2008. Future borrowing bases will be computed based on proved natural gas and oil reserves, hedge position, and estimated future cash flows from those reserves as well as any other outstanding debt. We expect that the borrowing base will continue to increase based on our future proved reserve additions and hedge position. The Amended Credit Facility matures on March 17, 2011 and bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 1.0% to 1.75% or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 0.25%. We pay commitment fees ranging from 0.25% to 0.375% of the unused borrowing base. The Amended Credit Facility is secured by natural gas and oil properties representing at least 80% of the value of our proved reserves and the pledge of all of the stock of our subsidiaries. For information concerning the effect of changes in interest rates on interest payments under this facility, see “—Quantitative and Qualitative Disclosure about Market Risk — Interest Rate Risks” below.

As of December 31, 2007 and March 31, 2008, borrowings outstanding under the Amended Credit Facility totaled $274.0 and $134.0 million, respectively. The Amended Credit Facility contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants for all prior periods. In addition to the $134.0 million outstanding with our Amended Credit Facility, we issued Convertible Notes totaling $172.5 million in March 2008. See Note 6 “—Long Term Debt.”

In December 2006, we entered into two interest rate derivative contracts to manage our exposure to changes in interest rates. The first contract was a floating-to-fixed interest rate swap for a notional amount of $10.0 million and the second was a floating-to-fixed interest rate collar for a notional amount of $10.0 million, both to terminate on December 12, 2009. Under the swap, we will make payments to (or receive payments from) the contract counterparty when the variable rate of one-month LIBOR falls below (or exceeds) the fixed rate of 4.70%. Under the collar, we will make payments to (or receive payments from) the contract counterparty when the variable rate falls below the floor rate of 4.50% or exceeds the ceiling rate of 4.95%. Our interest rate derivative instruments have been designated as cash flow hedges in accordance with SFAS No. 133. Changes in fair value of the interest rate swaps or collars are reported in other comprehensive income, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. Ineffectiveness related to such derivative instruments was de minimis for both the three months ended March 31, 2007 and 2008.

During the three months ended March 31, 2008, net settlement payments, which were included in interest expense, were insignificant. We anticipate that all originally forecasted transactions will occur by the end of the originally specified time periods and as of March 31, 2008, based on current projected interest rates, the net amount to be reclassified from accumulated other comprehensive income to net income during 2008 would be a net reduction of approximately $0.3 million. At March 31, 2008, the estimated fair value of the interest rate derivatives was a net liability of $0.7 million.

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Convertible Senior Notes. On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed, or purchased by the Company. The conversion price is approximately $66.33 per share of our common stock, equal to the applicable conversion rate of 15.0761 shares of our common stock, subject to adjustment. Upon conversion of the Convertible Notes, holders will receive, at our election, cash, shares of common stock, or a combination of cash and shares of common stock. The Convertible Notes will bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year, beginning September 15, 2008. Based on the market price of the Convertible Notes, the estimated fair value was approximately $184.4 million as of March 31, 2008.

On or after March 26, 2012, the Company may redeem for cash all or a portion of the Convertible Notes at a redemption price equal to 100% of the principal amount of the Convertible Notes to be redeemed plus accrued and unpaid interest, if any, up to, but excluding, the applicable redemption date. Currently, it is the Company’s intention to net cash settle the Convertible Notes. However, the Company has not made a formal legal irrevocable election to net share settle and reserves the right to settle the Convertible Notes in any manner allowed under the indenture for the Convertible Notes as business conditions warrant.

Holders of the Convertible Notes may require the Company to purchase all or a portion of their Convertible Notes on each of March 20, 2012, March 20, 2015, March 20, 2018, and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. The Company may pay the purchase price in cash, in shares of common stock, or in any combination of cash and common stock.

Holders may convert their Convertible Notes into cash, shares of our common stock, or a combination of cash and shares of our common stock, as elected by us, at any time prior to the close of business on September 20, 2027 if any of the following conditions are satisfied: (1) if the closing price of the Company’s common stock reaches specified thresholds or the trading price of the Convertible Notes falls below specified thresholds; (2) if the Convertible Notes have been called for redemption; (3) if we make certain significant distributions to holders of our common stock, or (4) we enter into specified corporate transactions. After September 20, 2027, holders may surrender their Convertible Notes for conversion at any time prior to the close of business on the business day immediately preceding the maturity date regardless of whether any of the foregoing conditions have been satisfied.

In addition, following certain corporate transactions that constitute a qualifying fundamental change, we are required to increase the applicable conversion rate for a holder who elects to convert its Convertible Notes in connection with such corporate transactions in certain circumstances.

Contractual Obligations.A summary of our contractual obligations as of and subsequent to March 31, 2008 is provided in the following table (in thousands).

	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		There After		Total
	(in thousands)
Notes Payable (1)	$	104	$	113	$	114	$	134,000	$	—	$	—	$	134,331
Convertible Senior Notes (2)		9,074		8,625		8,625		181,007		—		—		207,331
Other commitments for developing oil and gas properties		13,934		2,943		—		—		—		—		16,877
Office and office equipment leases and other		2,196		2,238		1,808		391		—		—		6,633
Firm transportation and processing agreements		24,423		26,182		26,882		27,102		57,328		110,625		272,542
Asset retirement obligations (3)		967		5,071		1,505		1,780		1,087		26,658		37,068
Derivative liability (4)		86,698		3,177		330		—		—		—		90,205
Total	$	137,396	$	48,349	$	39,264	$	344,280	$	58,415	$	137,283	$	764,987

(1) Included in Notes Payable is our Amended Credit Facility which does not include future commitment fees, interest expense, or other fees on our Amended Credit Facility, because the Amended Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

(2) On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. For purposes of contractual obligations, we assume that the holders of our Convertible Notes will not exercise the conversion feature and we will therefore have to repay the $172.5 million in cash. We expect to call the Convertible Notes for redemption in 2012. We are also obligated to make annual interest payments equal to $8.6 million.

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(3) Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See “Critical Accounting Policies and Estimates” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2007 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(4) Derivative liabilities represent the fair value of liabilities for oil and gas commodity derivatives and interest rate derivatives as of March 31, 2008. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market risk. See “Critical Accounting Policies and Estimates,” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2007 for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

We have entered into contracts that provide firm processing rights and firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one to 11 years and require us to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by us.

In addition to the commitments above, we have commitments for the purchase of facilities and equipment as of and subsequent to March 31, 2008 for a total of $9.2 million.

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2007 and the notes to the Unaudited Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q for a description of critical accounting policies and estimates.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our price swap and collars contracts in place for the three months ended March 31, 2008, our annual income before income taxes, including hedge settlements, would have decreased by approximately $0.4 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.03 million for each $1.00 per barrel change in crude oil prices.

We periodically enter into and anticipate entering into financial hedging activities with respect to a portion of our projected natural gas and oil production through various financial transactions which hedge the future prices received. These transactions may include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, and cashless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we and the counterparty to the collars would be required to settle the difference. These financial hedging activities are intended to support natural gas and oil prices at targeted levels and to manage our exposure to natural gas and oil price fluctuations. We typically hedge a fixed price for natural gas at our sales points (NYMEX less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. We do not hold or issue derivative instruments for speculative trading purposes.

In addition to financial transactions, we are a party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchases and normal sales exception and therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas revenues at the time of settlement, which in turn affects average realized natural gas prices.

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For the remaining three quarters of 2008, we currently have financial hedges in place for 41,954,000 MMBtu of natural gas production and approximately 302,500 Bbls of oil production. As of May 1, 2008, we also have hedges in place for 42,765,000 MMBtu of natural gas production and 264,625 Bbls of oil production for 2009 and 19,176,000 MMBtu of natural gas production and 36,500 Bbls of oil production for 2010. These hedges are summarized in the tables presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquitidy — Cash Flow from Operating Activities.”

Commodity Hedges

Commodity Swaps

Through a price swap, we have fixed the price we will receive on a portion of our natural gas and oil production for the remaining quarters of 2008 and the years 2009 and 2010. The weighted average price we will receive for the remaining quarters of 2008 for natural gas is $6.76 per MMBtu for a CIGRM price and $6.80 per MMBtu for a PEPL price; $7.22 per MMBtu for a CIGRM price and $7.56 per MMBtu for a PEPL price in 2009; and $6.93 per MMBtu for a CIGRM price, $7.63 per MMBtu for a PEPL price and $9.43 per MMBtu for a DA price in 2010. The weighted average WTI price we will receive for oil is $73.84 per Bbl for the remaining quarters of 2008 and $74.41 per Bbl for 2009. The tables presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Cash Flow from Operating Activities” provides the deliveries associated with these arrangements as of March 31, 2008 and May 1, 2008.

In a swap transaction, the counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price.

Commodity Collars

Through price collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas production for the remaining quarters of 2008 and the years 2009 and 2010. The weighted average minimum, or floor, price we will receive for the remaining quarters of 2008 is $6.50 per MMBtu for a CIGRM price. The weighted average maximum, or ceiling, price we will receive for the remaining quarters of 2008 for a CIGRM price is $10.00 per MMBtu. The weighted average minimum, or floor, price we will receive for 2010 is $7.00 per MMBtu for a TCO price. The weighted average maximum we will receive for 2010 is $10.00 per MMBtu for a TCO price. We have also fixed the minimum price we will receive on a portion of our oil production for the remaining quarters of 2008 and the years 2009 and 2010. We will receive a weighted average floor price of $70.48, $83.57, and $85.00 per Bbl for a WTI price in 2008, 2009 and 2010, respectively, and a weighted average ceiling price of $81.62, $122.66 and $128.00 per Bbl, respectively. The price collars also allow us to share in upward price movements up to the ceiling prices referenced in the contracts. The table presented above under “Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Cash Flow from Operating Activities” provides the deliveries and floor and ceiling prices associated with these various arrangements as of March 31, 2008 and May 1, 2008.

In a collar transaction, the counterparty is required to make a payment to us for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. We are required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the fixed ceiling price is below the settlement price. Neither party is required to make a payment if the settlement price falls between the fixed floor and ceiling price.

Interest Rate Risks

At March 31, 2008, we had debt outstanding under our Amended Credit Facility of $134.0 million, which bears interest at floating rates in accordance with our Amended Credit Facility. The average annual interest rate incurred on this debt for the three months ended March 31, 2007 and 2008 was 6.2% and 5.1%, respectively. A one hundred basis point (1.0%) increase in each of the average LIBOR rate and federal funds rate for the three months ended March 31, 2008 would have resulted in an estimated $0.6 million increase in interest expense assuming a similar average debt level to the three months ended March 31, 2008. We also had $172.5 million in principal of Convertible Notes outstanding at March 31, 2008, which have a fixed interest rate of 5.0%.

Interest Rate Hedges

Through interest rate derivative contracts, we have attempted to mitigate exposure to changes in interest rates. We entered into an interest rate swap for a notional amount of $10.0 million for a fixed LIBOR rate of 4.70%. We also entered into an interest rate collar for a notional amount of $10.0 million in which the interest rate has fixed minimum and maximum LIBOR rates of 4.50% and 4.95%, respectively.

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Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Based on an evaluation carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, as of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures, as defined in Securities Exchange Act Rules 13a-15(d) and 15d-15(e), were, as of March 31, 2008, effective.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the first fiscal quarter of 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business and a matter with the Environmental Protection Agency (“EPA”). In September 2006, the EPA alleged that we and an industry partner failed to comply with air quality and emissions standards for equipment used at our North Hill Creek compressor station in the Uinta Basin of Utah. Discussions with the EPA to resolve these issues are continuing. We believe that our monetary sanctions related to this matter will be less than $100,000 based on our discussions with the EPA and our analysis of monetary sanctions in similar actions. However, potential fines of up to $32,500 per day are possible if we are not able to reach a settlement agreement with the EPA and all the allegations were determined to be accurate.

While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.

Item 1A. Risk Factors.

As of the date of this filing, there have been no material changes from the risk factors previously disclosed in our “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2007, referred to as our 2007 Annual Report. An investment in our securities involves various risks. When considering an investment in our Company, you should carefully consider all of the risk factors described in our 2007 Annual Report. These risks and uncertainties are not the only ones facing us, and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our Company.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

The following table contains information about our acquisitions of equity securities during the three months ended March 31, 2008.

Issuer Purchases of Equity Securities

Period	Total Number of Shares (1)	Weighted Average Price Paid Per Share		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
January 1 – 31, 2008	—	$	—	—	—
February 1 – 29, 2008	49,140		46.19	—	—
March 1 – 31, 2008	558		46.33	—	—
Total	49,698	$	46.19	—	—

(1) Represents shares delivered by employees to satisfy the exercise price of stock options and tax withholding obligations in connection with the exercise of stock options and shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of shares of common stock issued pursuant to the Company’s employee incentive plans.

Item 3. Defaults upon Senior Securities.

Not applicable.

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

Not applicable.

Item 5. Other Information.

On February 22, 2008, our board of directors approved the Bill Barrett Corporation 2008 Stock Incentive Plan (the “2008 Plan”) which covers stock options, restricted shares, and other possible grants with respect to up to 3,000,000 shares of common stock and which will become effective upon the receipt of stockholder approval. The Company is seeking stockholder approval at its annual meeting to be held on May 13, 2008. The 2008 Plan is described in our proxy statement dated April 10, 2008 with respect to the May 13, 2008 stockholders meeting.

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Item 6. Exhibits.

Exhibit Number	Description of Exhibits
1.1	Underwriting Agreement, dated March 4, 2008, among Bill Barrett Corporation and Deutche Bank Securities Inc., Banc of America Securities LLC, and J.P. Morgan Securities Inc., as representatives of the several underwriters identified therein. [Incorporated by reference to Exhibit 1.1 of the Company’s Current Report on Form 8-K filed with the Commission on March 10, 2008.]
3.1	Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.4 of the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]
3.2	Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.5 by the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]
4.1(a)	Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.1(b)	Indenture, dated March 12, 2008, between the Company and the Trustee. [Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on March 12, 2008.]
4.2(a)	Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 of Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
4.2(b)	First Supplemental Indenture, dated March 12, 2008, by and between the Company and Trustee (including form of 5% Convertible Senior Notes due 2028). [Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on March 12, 2008.]
4.3	Stockholders’ Agreement, dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
4.4	Form of Rights Agreement concerning Shareholder Rights Plan, which includes as Exhibit A thereto the Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, and as Exhibits B thereto the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.5	Form of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to the Company’s Registration Statement on Form 8-A.]
4.6	Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to the Company’s Registration Statement on Form 8-A.]
10.1(a)	Second Amended and Restated Credit Agreement, dated March 17, 2006, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated March 22, 2006.]
10.1(b)	First Amendment to Second Amended and Restated Credit Agreement dated as of November 6, 2007 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated November 7, 2007.]
10.1(c)	Second Amendment to Second Amended and Restated Credit Agreement dated as of March 4, 2008, among Bill Barrett Corporation, as borrower, the Guarantors, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 10, 2008.]
10.2	Stock Purchase Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 10.2 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.3(a)*	Form of Indemnification Agreement dated April 15, 2004, between Bill Barrett Corporation and each of the directors and certain executive officers. [Incorporated by reference to Exhibit 10.10(a) to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]

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10.3(b)*	Schedule of officers and directors party to Indemnification Agreements dated April 15, 2004 with Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.10(b) to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.4*	Amended and Restated 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.5(a)*	Form of Tranche A Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(a) to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.5(b)*	Form of Tranche B Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(b) to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.6*	2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to Amendment No. 3 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on September 22, 2004.]
10.7*	Form of Stock Option Agreement for 2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.15 to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.8	Form of Management Rights Agreement between Bill Barrett Corporation and certain investors. [Incorporated by reference to Exhibit 10.16 to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.9	Regulatory Sideletter, dated March 28, 2002, between J.P. Morgan Partners (BHCA), L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.17 to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.10*	Form of Change in Control Severance Protection Agreement, revised as of November 16, 2006, for named executive officers. [Incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.]
10.11*	2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.12*	Revised Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.]
10.13*	Severance Plan. [Incorporated by reference to Exhibit 10.23 to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
21.1	Subsidiaries of the Registrant. [Incorporated by reference to Exhibit 21.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.]
31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32.1	Section 1350 Certification of Chief Executive Officer.
32.2	Section 1350 Certification of Chief Financial Officer.

* Indicates a management contract or compensatory plan or arrangement.

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SIGNATURES

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

	BILL BARRETT CORPORATION
Date: May 6, 2008	By:	/s/ Fredrick J. Barrett
		Fredrick J. Barrett
		Chairman of the Board of Directors and Chief Executive Officer
		(Principal Executive Officer)
Date: May 6, 2008	By:	/s/ Robert W. Howard
		Robert W. Howard
		Chief Financial Officer
		(Principal Financial Officer)

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