Bill Barrett (BBG) 10-Q 2009 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, 2009

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    ¨  Yes    ¨  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller 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  ¨	Smaller reporting company  ¨
		(Do not check if a 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 45,446,067 shares of $0.001 par value common stock outstanding on April 24, 2009.

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	20
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32
Item 4.	Controls and Procedures	33
PART II. OTHER INFORMATION		34
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Defaults Upon Senior Securities	34
Item 4.	Submission of Matters to a Vote of Security Holders	34
Item 5.	Other Information	35
Item 6.	Exhibits	36
SIGNATURES		39

2

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

		March 31, 2009			December 31, 2008
	��				(As Adjusted)
		(in thousands, except share and per share data)
Assets:
Current Assets:
Cash and cash equivalents		$	71,470		$	43,063
Accounts receivable, net of allowance for doubtful accounts of $790 for March 31, 2009 and $840 for December 31, 2008			53,518			66,427
Prepayments and other current assets			6,339			3,924
Derivative assets			213,793			199,960
Total current assets			345,120			313,374
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties			2,123,277			1,977,535
Unevaluated oil and gas properties, excluded from amortization			278,545			315,239
Furniture, equipment and other			22,131			20,971
			2,423,953			2,313,745
Accumulated depreciation, depletion, amortization and impairment			(809,770	)		(751,926	)
Total property and equipment, net			1,614,183			1,561,819
Derivative Assets			88,195			113,815
Deferred Financing Costs and Other Noncurrent Assets			4,998			5,485
Total		$	2,052,496		$	1,994,493
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities		$	82,666		$	100,552
Amounts payable to oil and gas property owners			11,730			17,067
Production taxes payable			33,031			36,236
Derivative liability and other current liabilities			1,269			511
Deferred income taxes			79,892			71,428
Total current liabilities			208,588			225,794
Note Payable to Bank			276,000			254,000
Convertible Senior Notes			154,660			153,411
Asset Retirement Obligations			47,694			46,687
Deferred Income Taxes			226,499			214,481
Derivatives and Other Noncurrent Liabilities			4,317			887
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 45,445,245 and 45,128,431 shares issued and outstanding at March 31, 2009 and December 31, 2008, respectively, with 731,709 and 590,098 shares subject to restrictions, respectively			45			45
Additional paid-in capital			778,093			775,652
Retained earnings			157,877			131,464
Treasury stock, at cost: zero shares at March 31, 2009 and December 31, 2008			—			—
Accumulated other comprehensive income			198,723			192,072
Total stockholders’ equity			1,134,738			1,099,233
Total		$	2,052,496		$	1,994,493

See notes to unaudited condensed consolidated financial statements.

3

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended March 31,
	2009			2008
				(As Adjusted)
	(in thousands, except share and per share amounts)
Operating and Other Revenues:
Oil and gas production	$	170,176		$	149,045
Commodity derivative loss		(25,956	)		(1,530	)
Other		520			1,687
Total operating and other revenues		144,740			149,202
Operating Expenses:
Lease operating expense		11,680			9,301
Gathering and transportation expense		11,024			9,399
Production tax expense		926			10,259
Exploration expense		760			641
Impairment, dry hole costs and abandonment expense		185			1,552
Depreciation, depletion and amortization		58,757			50,957
General and administrative expense		13,380			14,215
Total operating expenses		96,712			96,324
Operating Income		48,028			52,878
Other Income and Expense:
Interest and other income		198			472
Interest expense		(5,129	)		(3,879	)
Total other income and expense		(4,931	)		(3,407	)
Income before Income Taxes		43,097			49,471
Provision for Income Taxes		16,684			18,917
Net Income	$	26,413		$	30,554
Net Income Per Common Share, Basic	$	0.59		$	0.69
Net Income Per Common Share, Diluted	$	0.59		$	0.68
Weighted Average Common Shares Outstanding, Basic		44,618,161			44,279,033
Weighted Average Common Shares Outstanding, Diluted		44,739,504			45,225,160

See notes to unaudited condensed consolidated financial statements.

4

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(UNAUDITED)

	Common Stock		Additional Paid-In Capital			Retained Earnings		Treasury Stock			Accumulated Other Comprehensive Income		Total Stockholders’ Equity			Comprehensive Income
	(in thousands)
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		4,615			—		(3,051	)		—		1,565		$	—
Stock-based compensation		—		17,773			—		—			—		17,773			—
Retirement of treasury stock		—		(3,051	)		—		3,051			—		—			—
Conversion option of the Convertible Senior Notes (net of $8,578 of taxes) (See Note 5)		—		13,823			—		—			—		13,823			—
Comprehensive income:
Net income (as adjusted)		—		—			105,259		—			—		105,259		$	105,259
Effect of derivative financial instruments, net of $110,505 of taxes		—		—			—		—			187,302		187,302			187,302
Total comprehensive income																$	292,561
Balance — December 31, 2008 (As Adjusted)	$	45	$	775,652		$	131,464	$	—		$	192,072	$	1,099,233
Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding		—		—			—		(1,874	)		—		(1,874	)
Stock-based compensation		—		4,315			—		—			—		4,315
Retirement of treasury stock		—		(1,874	)		—		1,874			—		—
Comprehensive income:
Net income		—		—			26,413		—			—		26,413		$	26,413
Effect of derivative financial instruments, net of $3,923 of taxes		—		—			—		—			6,651		6,651			6,651
Total comprehensive income																$	33,064
Balance — March 31, 2009	$	45	$	778,093		$	157,877	$	—		$	198,723	$	1,134,738

See notes to unaudited condensed consolidated financial statements.

5

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March 31,
	2009			2008
				(As Adjusted)
	(in thousands)
Operating Activities:
Net Income	$	26,413		$	30,554
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		58,757			50,957
Deferred income taxes		16,628			18,807
Impairment, dry hole costs and abandonment expense		185			1,552
Unrealized derivative loss		25,956			1,530
Stock compensation and other non-cash charges		4,314			3,974
Amortization of deferred financing costs		1,751			501
Gain (loss) on sale of properties		1			(172	)
Change in operating assets and liabilities:
Accounts receivable		12,909			(19,532	)
Prepayments and other assets		(2,504	)		(3,114	)
Accounts payable, accrued and other liabilities		6,668			(3,082	)
Amounts payable to oil and gas property owners		(5,337	)		(1,145	)
Production taxes payable		(3,205	)		4,366
Net cash provided by operating activities		142,536			85,196
Investing Activities:
Additions to oil and gas properties, including acquisitions		(134,901	)		(114,992	)
Additions of furniture, equipment and other		(1,226	)		(605	)
Proceeds from sale of properties		—			1,212
Net cash used in investing activities		(136,127	)		(114,385	)
Financing Activities:
Proceeds from debt		42,000			199,800
Principal payments on debt		(20,000	)		(167,014	)
Proceeds from sale of common stock		—			1,629
Deferred financing costs and other		(2	)		(4,588	)
Net cash provided by financing activities		21,998			29,827
Increase in Cash and Cash Equivalents		28,407			638
Beginning Cash and Cash Equivalents		43,063			60,285
Ending Cash and Cash Equivalents	$	71,470		$	60,923

See notes to unaudited condensed consolidated financial statements.

6

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

March 31, 2009

1. Organization

Bill Barrett Corporation (the “Company”), 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 (“GAAP”) for interim financial information. Pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), they do not include all of the information and footnotes required by 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 the Company’s financial position as of March 31, 2009, the Company’s results of operations for the three months ended March 31, 2009 and 2008 and cash flows for the three months ended March 31, 2009 and 2008. Operating results for the three months ended March 31, 2009 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, the Unaudited Condensed Consolidated Financial Statements and the notes thereto should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 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 the intended cash settlement of our Convertible Senior Notes in computing dilutive earnings per share, 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 rates used to capitalize interest for the three months ended March 31, 2009 and 2008 were 5.6% and 6.0%, respectively, which include interest on both the Company’s 5% Convertible Senior Notes due 2028 (“Convertible Notes”) and its credit facility, amortization of the Convertible Note discount, commitment fees paid on the unused portion of its credit facility, amortization of deferred financing and debt issuance costs and the effects of interest rate hedges. The Company capitalized interest costs of $0.8 million and $0.4 million for the three months ended March 31, 2009 and 2008, respectively.

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.

7

Unevaluated oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. 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. Unevaluated oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage. During the three months ended March 31, 2009 and 2008, the Company did not recognize any non-cash impairment charges.

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 value, on a first-in, first-out basis.

The following table sets forth the net capitalized costs and associated accumulated depreciation, depletion and amortization, and non-cash impairments relating to the Company’s natural gas and oil producing activities:

	As of March 31, 2009			As of December 31, 2008
	(in thousands)
Proved properties	$	418,387		$	415,641
Wells and related equipment and facilities		1,512,505			1,381,861
Support equipment and facilities		180,948			170,058
Materials and supplies		11,437			9,975
Total proved oil and gas properties		2,123,277			1,977,535
Accumulated depreciation, depletion, amortization and impairment		(801,410	)		(744,139	)
Total proved oil and gas properties, net	$	1,321,867		$	1,233,396
Unevaluated properties	$	104,605		$	105,665
Wells and facilities in progress		173,940			209,574
Total unevaluated oil and gas properties, excluded from amortization	$	278,545		$	315,239

Net changes in capitalized exploratory well costs for the three months ended March 31, 2009 are reflected in the following table (in thousands):

Beginning of period	$	120,091
Additions to capitalized exploratory well costs pending the determination of proved reserves		114,152
Reclassifications of wells, facilities and equipment based on the determination of proved reserves		(125,528	)
Exploratory well costs charged to dry hole costs and abandonment expense (1)		(92	)
End of period	$	108,623

(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, 2009
	(in thousands)
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	77,705
Capitalized exploratory well costs that have been capitalized for a period greater than one year		30,918
End of period balance	$	108,623
Number of exploratory wells that have costs capitalized for a period greater than one year		119

As of March 31, 2009, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling were $30.9 million, of which $15.8 million was related to exploratory wells 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.

8

In addition to its wells in the Powder River Basin, the Company has six exploratory wells for a total of $15.1 million that have been capitalized for greater than one year located in the Montana Overthrust area and in the Paradox, Big Horn and Uinta Basins. The two wells located in the Montana Overthrust area are under economic evaluation for possible development as the Company is assessing and conducting appraisal operations to determine whether economic reserves can be attributed to this area. In the Paradox Basin, the Company has one well that will be re-entered and converted to a horizontal well, and completion work is planned for the second well during the second quarter of 2009. The well located in the Big Horn Basin is pending upgrades of production, gathering and processing facilities. The well located in the Uinta Basin is pending the development of a gas gathering infrastructure.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that 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, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. During the three months ended March 31, 2009 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. Estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values, are taken into consideration.

Stock-Based Compensation.The Company accounts for stock-based compensation in accordance with SFAS No. 123 (revised 2004),Share-Based Payment(“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 (the “2004 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 subsequent 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 Compensation 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 of up to four years, depending on the level at which the performance goals are achieved. Each year for four years, it is possible for up to 50% of the shares to vest based on the achievement of the performance goals. Twenty-five percent of the total grant will vest for metrics met at the target level, and an additional 25% 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. If the target level metrics are not met, no shares will vest. In any event, the total number of common shares that could vest 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 Incentive Plan were set aside for this program.

Based upon Company performance in 2007, 30% of the performance shares vested in February 2008, and the Company recognized $0.5 million of compensation costs related to these awards for the quarter ended March 31, 2008. Based upon the Company’s performance in 2008, 50% of the performance shares vested in February 2009, and the Company recognized $0.4 million of compensation costs related to these awards for the quarter ended March 31, 2009. After the February 2009 vesting, 20% of the initial grant remained available for future performance vesting. On February 26, 2009, the Compensation Committee approved a supplemental grant to each participant remaining in the performance share program equal to 30% of the initial grant received by that participant (a total of 72,479 shares) in order to provide sufficient shares so that up to 50% of the performance shares initially granted to each participant are available for vesting if all stretch goals for 2009 are met. These supplemental grants expire on February 16, 2010 if they have not vested by that time.

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.

In February 2009, the Compensation Committee approved the performance metrics for vesting of the performance shares based on 2009 performance. For the year ending December 31, 2009, the performance goals consist of finding and development costs per Mcfe (weighted at 40%), adjusted debt per Mcfe of proved reserves (weighted at 30%), lease operating expenses per Mcfe (weighted at 15%), and general and administrative expenses (weighted at 15%). In February 2009, a total of 124,339 performance-based nonvested equity shares of common stock (including the supplemental grant) were subject to the new grant date, and the fair value was remeasured at a weighted-average price of $19.58 per share. Based upon the number of shares expected to vest through February 2010, the Company recognized $0.1 million of non-cash stock-based compensation cost associated with these shares for the three months ended March 31, 2009.

9

During the three months ended March 31, 2009, the Company granted 756,190 options to purchase shares of common stock with a weighted average exercise price of $23.27 per share, 339,560 nonvested equity shares of common stock and 73,679 performance-based nonvested equity shares of common stock. The Company recorded non-cash stock-based compensation cost of $4.0 million and $3.5 million for the three months ended March 31, 2009 and 2008, respectively, including $0.1 million and $0.8 million associated with the performance-based nonvested equity shares, respectively. As of March 31, 2009, there were $35.4 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 $0.5 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 2009 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 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 of the Company’s common stock for payment of the director’s fees. For the three months ended March 31, 2009, the Company issued 3,036 shares of common stock for payment of directors’ fees and recognized $0.1 million of non-cash stock-based compensation cost associated with the issuance of those shares.

New Accounting Pronouncements.In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157,Fair Value Measurements(“SFAS No. 157”). 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. With partial adoption, the Company applied SFAS No. 157 to recurring fair value measurements of financial and nonfinancial instruments, which affected the fair value disclosures of the Company’s financial derivatives within the scope of SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. See Note 7 for fair value disclosures.

As of January 1, 2009, the Company fully adopted SFAS No. 157, requiring 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 full adoption of SFAS No. 157 related to nonfinancial assets and liabilities did not have a material impact on the Company’s financial statements.

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’s 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 and was effective for the Company beginning January 1, 2009. SFAS No. 141R will only impact the Company if and when the Company becomes party to a business combination.

In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities(“SFAS No. 161”). 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 seeks to achieve these improvements by requiring disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It also seeks to improve the transparency of 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 was effective for the Company beginning January 1, 2009. See Note 8 for the applicable disclosures.

In May 2008, the FASB adopted FSP APB 14-1,Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (including Partial Cash Settlement). FSP APB 14-1 states 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 is determined without regard to the conversion feature. The difference between the issuance amount of the debt instrument and the value determined pursuant to FSP APB 14-1 is recorded as an equity contribution. The resulting debt discount is amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. FSP APB 14-1 was effective for financial statements issued for fiscal years

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beginning after December 15, 2008. The Company adopted FSP APB 14-1 effective January 1, 2009 as early adoption was not permitted. FSP APB 14-1 changed the accounting treatment for the Company’s Convertible Notes that were issued in March 2008. See Note 5 for additional disclosures associated with adoption of this standard.

FSP APB 14-1 was required to be applied retrospectively for any instrument within the scope of FSP APB 14-1 that was outstanding during any of the periods presented. As a result of the retrospective application, certain amounts in the Company’s consolidated financial statements for the year ended December 31, 2008 have been adjusted. A summary of the changes are presented below (amounts in thousands):

	As of December 31, 2008
	As previously reported			After adoption of FSP APB 14-1
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Deferred Financing Costs and Other Noncurrent Assets	$	6,055		$	5,485
Convertible Senior Notes		172,500			153,411
Deferred Income Taxes		207,397			214,481
Additional paid-in capital		761,829			775,652
Retained earnings		133,852			131,464
	For the Three Months Ended March 31, 2008
	As previously reported			After adoption of FSP APB 14-1
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
Interest expense	$	(3,626	)	$	(3,879	)
Provision for Income Taxes		19,016			18,917
Net Income		30,708			30,554
	For the Three Months Ended March 31, 2008
	As previously reported			After adoption of FSP APB 14-1
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Net Income	$	30,708		$	30,554
Deferred income taxes		18,906			18,807
Amortization of deferred financing costs		248			501

On December 31, 2008, the SEC adopted the final rules and interpretations updating its oil and gas reserve reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which is a widely accepted set of evaluation guidelines that are designed to support assessment processes throughout the resource asset lifecycle. These guidelines were prepared by the Society of Petroleum Engineers (“SPE”) Oil and Gas Reserves Committee with cooperation from many industry organizations. One of the key changes to the previous SEC rules relates to using a 12-month average commodity price to calculate the value of proved reserves versus the current method of using year-end prices. Other key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, the opportunity to establish proved undeveloped reserves without the requirement of an adjacent producing well and permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on the Company’s disclosures and financial statements.

In April 2009, the FASB issued staff positions intended to provide additional application guidance and enhance disclosures regarding fair value measurements. FSP SFAS No. 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, intends to provide guidelines for

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making fair value measurements more consistent with the principles presented in SFAS No. 157. FSP SFAS No. 107-1 and APB 28-1,Interim Disclosures about Fair Value of Financial Instruments, attempts to enhance consistency in financial reporting by increasing the frequency of fair value disclosures. These FSPs are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The adoption of these FSPs is not expected to have a material impact on the Company’s financial statements.

3. Earnings Per Share

Basic net income per share of common stock 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. Potentially dilutive securities for the diluted earnings per share calculations consist of nonvested equity shares of common stock, in-the-money outstanding stock options to purchase the Company’s common stock and shares into which the Convertible Notes are convertible.

In satisfaction of its obligation upon conversion of the Convertible Notes, the Company may elect to deliver, at its option, cash, shares of its common stock or a combination of cash and shares of its common stock. The Company currently intends to settle the Convertible Notes in cash 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 have not been dilutive since their issuance in March 2008, and therefore, do not impact the diluted earnings per share calculation for the three months ended March 31, 2009.

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

	Three Months Ended March 31,
	2009		2008
Net income	$	26,413	$	30,554
Basic weighted-average common shares outstanding in period		44,618		44,279
Add dilutive effects of stock options and nonvested equity shares of common stock		122		946
Diluted weighted-average common shares outstanding in period		44,740		45,225
Basic net income per common share	$	0.59	$	0.69
Diluted net income per common share	$	0.59	$	0.68

4. Supplemental Disclosures of Cash Flow Information

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

	For Three Months Ended March 31,
	2009			2008
Cash paid for interest, net of amount capitalized	$	6,736		$	3,597
Cash paid for income taxes, net of refunds received		56			253
Supplemental disclosures of non-cash investing and financing activities:
Current liabilities that are reflected in investing activities		59,288			58,116
Current liabilities that are reflected in financing activities		38			645
Net change in asset retirement obligations		(239	)		(1,013	)
Treasury stock acquired from employee stock option exercises and collection of employee payroll taxes on vesting of restricted stock		1,874			2,295
Retirement of treasury stock		(1,874	)		(2,295	)
Equity from issuance of Convertible Notes under FSP APB 14-1 (net of deferred taxes of $8.6 million)		—			14,539

5. Long-Term Debt

Revolving Credit Facility

On April 15, 2009, the Company amended its credit facility (the “Amended Credit Facility”). The Amended Credit Facility, which matures on March 17, 2011, has commitments of $592.8 million and, based on year-end 2008 reserves and hedge positions, a borrowing base of $600.0 million (after a reduction related to the Company’s Convertible Notes outstanding). Future borrowing bases will be computed based on proved natural gas and oil reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company. The borrowing base is required to be redetermined twice per year.

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The Amended Credit Facility bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 1.75% to 2.50% (an increase from 1.25% to 2.00% previously) or an alternate base rate, based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus 1.00%, plus applicable margins ranging from 0.75% to 1.50% (an increase from 0.25% to 1.00% previously). The average annual interest rates incurred on the Amended Credit Facility were 2.3% and 6.0% for the three months ended March 31, 2009 and 2008, respectively. The Company pays annual commitment fees ranging from 0.35% to 0.50% 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 the Company’s subsidiaries. The Amended Credit Facility also contains certain financial covenants. The Company is currently in compliance with all financial covenants and has complied with all financial covenants for all prior periods.

As of March 31, 2009, borrowings outstanding under the Amended Credit Facility totaled $276.0 million.

5% Convertible Senior Notes Due 2028

On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. The full $172.5 million principal amount of the Convertible Notes is currently outstanding. 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 the Company’s existing and future senior indebtedness; senior in right of payment to all of the Company’s future subordinated indebtedness; and effectively subordinated to all of the Company’s 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 the Company’s subsidiaries that do not guarantee the Convertible Notes. As of March 31, 2009, the Convertible Notes are not guaranteed by any of the Company’s subsidiaries.

The conversion price is approximately $66.33 per share of the Company’s common stock, equal to the applicable conversion rate of 15.0761 shares of common stock, subject to adjustment, for each $1,000 of the principal amount of the Convertible Notes. Upon conversion of the Convertible Notes, holders will receive, at the Company’s election, cash, shares of common stock or a combination of cash and shares of common stock. If the conversion value exceeds $1,000, the Company will also deliver, at its election, cash, shares of common stock or a combination of cash and shares of common stock with respect to the remaining value deliverable upon conversion. 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 cash 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.

The Convertible Notes 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.

Holders of the Convertible Notes may require the Company to purchase all or a portion of their Convertible Notes for cash 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.

Holders may convert their Convertible Notes into cash, shares of the Company’s common stock or a combination of cash and shares of common stock, as elected by the Company, 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 the Company makes certain significant distributions to holders of the Company’s common stock; or (4) the Company enters into specified corporate transactions, none of which occurred during the three months ended March 31, 2009. 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, the Company is required to increase the applicable conversion rate for a holder who elects to convert its Convertible Notes.

As a result of the adoption of FSP APB 14-1 and its retrospective application (previously discussed in Note 2), the Company recorded a debt discount of $23.1 million, which represented the fair value of the equity conversion feature as of the date of the issuance of the Convertible Notes. The value of the equity conversion feature was also recorded as additional paid-in capital, net of $8.6 million of deferred taxes. In addition, the transaction costs incurred directly related to the issuance of the Convertible Notes were allocated proportionately to the equity conversion feature and recorded as additional paid-in capital. The equity component is not subsequently re-valued as long as it continues to qualify for equity treatment.

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The debt discount is amortized as additional non-cash interest expense over the expected term of the Convertible Notes through March 2012. As of March 31, 2009, the net carrying amount of the Convertible Notes is as follows (amounts in thousands):

Principal amount of the Convertible Notes	$	172,500
Unamortized debt discount		(17,840	)
Carrying amount of the Convertible Notes	$	154,660

As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the Company’s Convertible Notes is 9.7%. The amount of the cash interest expense recognized for the three months ended March 31, 2009 and 2008 related to the 5% contractual interest coupon was $2.2 million and $0.4 million, respectively. The amount of non-cash interest expense for the three month period ended March 31, 2009 and 2008 related to the amortization of the debt discount and amortization of the transaction costs was $1.5 million and $0.4 million, respectively.

There is no active, public market for the Convertible Notes. Therefore, based on market-based parameters of the various components of the Convertible Notes, the aggregate estimated fair value of the Convertible Notes was approximately $136.2 million as of March 31, 2009.

6. Asset Retirement Obligations

The Company accounts for its asset retirement obligations in accordance with SFAS No. 143 and estimates the initial fair value measurement of the asset retirement obligations in accordance with SFAS No. 157. 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 the Company’s asset retirement obligations for the three months ended March 31, 2009 is as follows (in thousands):

Beginning of period	$	47,193
Liabilities incurred		239
Liabilities settled		(112	)
Accretion expense		798
Revisions to estimate		—
End of period	$	48,118
Less: current asset retirement obligations		424
Long-term asset retirement obligations	$	47,694

7. Fair Value Measurements

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 5, approximates its fair value due to its floating rate structure.

The Company adopted SFAS No. 157,Fair Value Measurements, effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and liabilities that are being measured and reported on a fair value basis. Beginning January 1, 2009, the Company also applied SFAS No. 157 to non-financial assets and liabilities.

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 securities 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 than 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 No. 157 and includes in level 3 all of those whose fair value is based on significant unobservable inputs.

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, 2009. 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	$	—	$	301,988		$	—	$	301,988
Liabilities
Commodity Derivatives	$	—	$	(3,510	)	$	—	$	(3,510	)
Interest Rate Derivatives		—		(593	)		—		(593	)

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 Company. 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, 2009, and for the three months ended March 31, 2009, the Company did not have assets or liabilities measured under a level 1 fair value hierarchy.

Level 2 Fair Value Measurements

Natural Gas and Crude Oil Forwards and Options — The fair value of the natural gas and 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.

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.

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Level 3 Fair Value Measurements

As of March 31, 2009, and for the three months ended March 31, 2009, the Company did not have assets or liabilities measured under a level 3 fair value hierarchy.

8. Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable, economic 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 received for a portion of the Company’s natural gas and oil production. The Company does not enter into derivative instruments for speculative 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, 2009, the Company had hedges in place for a portion of its anticipated production through 2011 for a total of 363,875 Bbls of crude oil and 105,471,000 MMBtu of natural gas.

In addition to financial transactions, the Company may at times be 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 sale 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 production revenues at the time of settlement.

The Company also has two interest rate derivative contracts to manage the Company’s exposure to changes in interest rates. The first contract is a floating-to-fixed interest rate swap for a notional amount of $10.0 million, and the second is 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. 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 the Company’s Amended Credit Facility.

All derivative instruments, other than those that meet the normal purchase and normal sale exception 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. The following table summarizes the location and fair value of all derivative instruments in the Unaudited Consolidated Balance Sheets as of March 31, 2009:

	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(in thousands)
Derivatives Designated as Cash Flow Hedges Under SFAS No. 133
Current
Interest Rate Contracts	N/A	$	—	Derivative Liability and Other Current Liabilities	$	593
Commodity Contracts	Derivative Assets		218,204	N/A		—
Long Term
Commodity Contracts	Derivative Assets		100,481	Derivative Assets (2)		536
Commodity Contracts	Derivatives and Other Noncurrent Liabilities (1)		645	N/A		—
Total derivatives designated as hedging instruments under SFAS No. 133		$	319,330		$	1,129
Derivatives Not Designated as Cash Flow Hedges Under SFAS No. 133
Current
Commodity Contracts	N/A	$	—	Derivative Assets (2)	$	4,412
Long Term
Commodity Contracts	Derivative Assets		2,243	Derivative Assets (2)		13,992
Commodity Contracts	N/A		—	Derivatives and Other Noncurrent Liabilities		4,155
Total derivates not designated as hedging instruments under SFAS No. 133		$	2,243		$	22,559
Total Derivatives		$	321,573		$	23,688

(1) Amounts are netted against derivative liability balances from the same counterparty, and, therefore, are presented as a net liability on the Company’s Unaudited Condensed Consolidated Balance Sheets.

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(2) Amounts are netted against derivative asset balances from the same counterparty, and, therefore, are presented as a net asset on the Company’s Unaudited Condensed Consolidated Balance Sheets.

For derivative instruments that qualify and are designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income (“OCI”) until the forecasted transaction occurs. The Company will reclassify the appropriate cash flow hedge amounts from OCI to gains or losses in the Unaudited Consolidated Statements of Operations as the hedged production quantity is produced or the interest rate derivative is settled. Based on projected market prices as of March 31, 2009, the amount to be reclassified from OCI to net income in the next 12 months would be an after-tax net gain of approximately $136.0 million. 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 the Company’s derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified time periods.

The commodity hedge instruments designated as cash flow hedges 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 in accordance with SFAS No. 133. Although those derivatives may not achieve 100% effectiveness for accounting purposes, the Company believes that its derivative instruments continue to be highly effective in achieving its risk management objectives. The ineffective portion of commodity hedge derivatives is reported in commodity derivative gain or loss in the Unaudited Consolidated Statements of Operations. Ineffectiveness on interest rate derivatives was de minimis for the three months ended March 31, 2009. The following table summarizes the cash flow hedge gains and losses and their locations on the Unaudited Consolidated Balance Sheets and Unaudited Consolidated Statements of Operations for the three months ended March 31, 2009:

Derivatives in SFAS No. 133 Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in OCI (net of tax)			Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (before tax)			Location of Loss on Ineffective Hedges	Amount of Loss Recognized in Income on Ineffective Hedges (before tax)
	(in thousands)
Interest Rate Contracts	$	(52	)	Interest and Other Income	$	(195	)	N/A		N/A
Commodity Contracts		6,703		Oil and Gas Production		87,119		Commodity Derivative Loss		(5,863	)
Total	$	6,651			$	86,924			$	(5,863	)

If the forecasted transaction to which the hedging instrument had been designated is no longer probable of occurring within the specified time period, the hedging instrument loses cash flow hedge accounting treatment in accordance with SFAS No. 133. All current mark-to-market gains and losses are recorded in earnings and all accumulated gains or losses recorded in OCI related to the hedging instrument are also reclassified to earnings.

Some of the Company’s commodity derivatives do not qualify for hedge accounting under SFAS No. 133 but are, to a degree, an economic offset to the Company’s commodity price exposure. If a commodity derivative instrument does not qualify as a cash flow hedge or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in commodity derivative gain or loss in the Unaudited Consolidated Statements of Operations. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. The Company’s cash flow is only impacted when the underlying physical sales transaction takes place in the future and when the associated derivative instrument contract is settled by making or receiving a payment to or from the counterparty. Realized gains and losses of commodity derivative instruments that do not qualify as cash flow hedges are recognized in commodity derivative gain or loss in the Unaudited Consolidated Statements of Operations and are reflected in cash flows from operations on the Unaudited Consolidated Statements of Cash Flows.

In addition to the swaps and collars discussed above, the Company has entered into basis only swaps. Basis only swaps hedge the difference between the New York Mercantile Exchange (“NYMEX”) price and the price received for the Company’s natural gas production at a specific delivery location. Although the Company believes that this represents a sound risk mitigation strategy, the basis only swaps do not qualify for hedge accounting under SFAS No. 133 because the total future cash flow has not been fixed. As a result, the changes in fair value of these derivative instruments are recorded in earnings and recognized in commodity derivative gain or loss in the Unaudited Consolidated Statements of Operations. As of March 31, 2009, the Company had basis only swaps in place for a portion of the Company’s anticipated natural gas production in 2009, 2010, 2011 and 2012 for a total of 30,920,000 MMbtu.

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The following table summarizes the location and amounts of gains and losses on derivative instruments that do not qualify for hedge accounting under SFAS No. 133 for the three months ended March 31, 2009:

Derivatives Not Designated as Hedging Instruments under SFAS No. 133	Location of Loss Recognized in Income on Derivatives	Amount of Loss Recognized in Income on Derivatives
		(in thousands)
Commodity Contracts	Commodity Derivative Loss	$	(20,093	)
Total		$	(20,093	)

The Company was a party to various swap and collar contracts for natural gas based on the Colorado Interstate Gas Rocky Mountains (“CIGRM”), Panhandle Eastern Pipe Line Co. (“PEPL”) and Northwest Pipeline Corporation (“NWPL”) indices that settled during the three months ended March 31, 2009 and based on the CIGRM and 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 $83.9 million and $0.3 million in the three months ended March 31, 2009 and 2008, respectively. The Company was also a party to various swap and collar contracts for oil based on a West Texas Intermediate (“WTI”) index, recognizing an increase to oil production revenues related to these contracts of $3.2 million and a reduction of $2.1 million in the three months ended March 31, 2009 and 2008, respectively.

The table below summarizes the realized and unrealized gains and losses the Company recognized related to its oil and natural gas derivative instruments for the periods indicated:

	Three Months Ended March 31,
	2009			2008
Realized gains (losses) on derivatives designated as cash flow hedges (1)	$	87,119		$	(1,732	)
Realized losses on derivatives not designated as cash flow hedges	$	—		$	—
Unrealized ineffectiveness recognized on derivatives designated as cash flow hedges (2)		(5,863	)		(1,530	)
Unrealized losses on derivatives not designated as cash flow hedges (2)		(20,093	)		—
Total commodity derivative loss	$	(25,956	)	$	(1,530	)

(1) Included in “Oil and gas production” revenues in the Unaudited Condensed Consolidated Statements of Operations.

(2) Included in “Commodity derivative loss” in the Unaudited Condensed Consolidated Statements of Operations.

Derivative financial instruments that hedge the price of oil and gas and interest rate levels are generally executed with major financial or commodities trading institutions that expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company has hedges in place with eight different counterparties, of which all but one are lenders in the Amended Credit Facility. As of March 31, 2009, JP Morgan Chase & Company, J. Aron & Company (a subsidiary of Goldman, Sachs & Company) and Bank of Montreal accounted for 43.8%, 26.8% and 18.6%, respectively, of the net fair market value of the Company’s net derivative asset. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. The credit worthiness of counterparties is subject to continual review, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.

It is the Company’s policy to enter into derivative contracts with counterparties who are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility, or potential lenders in the Amended Credit Facility. With the exception of one counterparty, the Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). The counterparty with whom the Company currently does not have an ISDA in place represents 1.4% of the fair value of the net derivative asset balance. Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events, and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions with its lenders (or affiliates of lenders) that, in the event of counterparty default, allow the Company to set-off amounts owed under the Amended Credit Facility or other general obligations against monies owed for derivative contracts. Accordingly, the maximum amount of loss in the event of all counterparties defaulting is $224.8 million as of March 31, 2009, after netting any amounts owed by the Company to its counterparties.

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9. Income Taxes

The Company accounts for its uncertain tax positions in accordance with the provisions of FASB Interpretation (“FIN”) No. 48,Accounting for Uncertainty in Income Taxes. As of March 31, 2009, there has been no change to the Company’s 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, 2009, 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, 2009.

At March 31, 2009, the Company’s Unaudited Condensed Consolidated Balance Sheets reflected a net deferred tax liability of $306.4 million, of which $117.3 million pertains to the tax effects of derivative instruments reflected in OCI.

Income tax expense for the three months ended March 31, 2009 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 and other operating expenses not deductible for income tax purposes.

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. 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 Company may occasionally acquire treasury stock, which is recorded at cost, in connection with the vesting and exercise of share-based awards or for other reasons. As of March 31, 2009, all treasury stock held by the Company was retired.

11. Accumulated Other Comprehensive Income

The Company follows the provisions of SFAS No. 130,Reporting Comprehensive Income, which establishes standards for reporting comprehensive income. The components of accumulated other comprehensive income and related tax effects for the three months ended March 31, 2009 were as follows:

	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated other comprehensive income—December 31, 2008	$	305,410		$	(113,338	)	$	192,072
Unrealized change in fair value of cash flow hedges		97,498			(36,181	)		61,317
Reclassification adjustment for realized gains on hedges included in net income		(86,924	)		32,258			(54,666	)
Accumulated other comprehensive income—March 31, 2009	$	315,984		$	(117,261	)	$	198,723

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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, debt and equity market 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, 2008 under the “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” sections and in Item 1A, “Risk Factors” of this Quarterly Report on Form 10-Q, 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 (“we,” “our” 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 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 of 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, 2009 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, 2009 Compared to Three Months Ended March 31, 2008

	Three Months Ended March 31,						Increase (Decrease)
	2009			2008			Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil and gas production	$	170,176		$	149,045		$	21,131		14	%
Commodity derivative loss		(25,956	)		(1,530	)		(24,426	)	nm	*
Other		520			1,687			(1,167	)	(69	)%
Operating Expenses
Lease operating expense		11,680			9,301			2,379		26	%
Gathering and transportation expense		11,024			9,399			1,625		17	%
Production tax expense		926			10,259			(9,333	)	(91	)%
Exploration expense		760			641			119		19	%
Impairment, dry hole costs and abandonment expense		185			1,552			(1,367	)	(88	)%
Depreciation, depletion and amortization expense		58,757			50,957			7,800		15	%
General and administrative expense (1)		9,586			10,632			(1,046	)	(10	)%
Non-cash stock-based compensation expense (1)		3,794			3,583			211		6	%
Total operating expenses	$	96,712		$	96,324		$	388		0	%
Production Data:
Natural gas (MMcf)		21,073			17,332			3,741		22	%
Oil (MBbls)		169			144			25		17	%
Combined volumes (MMcfe)		22,087			18,196			3,891		21	%
Daily combined volumes (MMcfe/d)		245			200			45		23	%
Average Prices (2):
Natural gas (per Mcf)	$	7.72		$	8.02		$	(0.30	)	(4	)%
Oil (per Bbl)		43.95			69.83			(25.88	)	(37	)%
Combined (per Mcfe)		7.70			8.19			(0.49	)	(6	)%
Average Costs (per Mcfe):
Lease operating expense	$	0.53		$	0.51		$	0.02		4	%
Gathering and transportation expense		0.50			0.52			(0.02	)	(4	)%
Production tax expense		0.04			0.56			(0.52	)	(93	)%
Depreciation, depletion and amortization		2.66			2.80			(0.14	)	(5	)%
General and administrative expense (3)		0.43			0.58			(0.15	)	(26	)%

* Not meaningful.

(1) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense for a total of $13.4 million and $14.2 million for the three months ended March 31, 2009 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 expenses associated with stock-based grants.

(2) Average prices shown in the table are net of the effects of all of our realized commodity hedging transactions. Our average realized price calculation includes all cash settlements for commodity derivatives, whether or not they qualify for hedge accounting under SFAS No. 133. As a result of our realized hedging transactions, natural gas production revenues were increased by $83.9 million for the three months ended March 31, 2009 and increased by $0.3 million for the three months ended

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March 31, 2008. Oil production revenues were increased by $3.2 million for the three months ended March 31, 2009, and reduced by $2.1 million for the three months ended March 31, 2008. Before the effects of hedging, the average prices we received for natural gas and oil were as follows:

	Three Months Ended March 31,
	2009		2008
Natural gas (per Mcf)	$	3.74	$	8.00
Oil (per Bbl)	$	25.00	$	84.18

(3) Excludes non-cash stock-based compensation expense as described in footnote (1) above. This presentation is a non-GAAP measure. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Unaudited Condensed Consolidated Statements of Operations, were $0.61 and $0.78 for the three months ended March 31, 2009 and 2008, respectively.

Production Revenues.Production revenues increased to $170.2 million for the three months ended March 31, 2009 from $149.0 million for the three months ended March 31, 2008, primarily due to a 21% increase in production partially offset by a 6% decrease in natural gas and oil prices after the effects of realized hedges on a per Mcfe basis. The net increase in production added approximately $30.0 million of production revenues, while the decrease in prices on a per Mcfe basis reduced production revenues by approximately $8.8 million. Additional information concerning production is in the following table:

	Three Months Ended March 31, 2009			Three Months Ended March 31, 2008			% 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	103	7,979	8,597	101	6,917	7,523	2	%	15	%	14	%
Uinta Basin	55	8,087	8,417	31	7,094	7,280	77	%	14	%	16	%
Wind River Basin	5	2,408	2,438	5	1,758	1,788	—		37	%	36	%
Powder River Basin	—	2,452	2,452	—	1,554	1,554	—		58	%	58	%
Paradox Basin	—	88	88	—	—	—	—		nm	*	nm	*
Other	6	59	95	7	9	51	(14	)%	556	%	86	%
Total	169	21,073	22,087	144	17,332	18,196	17	%	22	%	21	%

* Not meaningful

Total production volumes for the three months ended March 31, 2009 of 22.1 Bcfe increased from 18.2 Bcfe for the three months ended March 31, 2008 due to increased production across all basins along with first sales in December 2008 from our Yellow Jacket prospect in the Paradox Basin. The production increase in the Piceance Basin was the result of our continued development activities with initial sales from 112 new gross wells from April 1, 2008 to March 31, 2009. The production increase in the Uinta Basin was the result of our continued development activities with initial sales from 60 new gross wells from April 1, 2008 to March 31, 2009. The production increase in the Powder River Basin was the result of our continued development activities with initial sales from 208 new gross wells from April 1, 2008 to March 31, 2009. The production increase in the Wind River Basin was due to the recompletion of an existing well to a third zone in the Frontier formation in May 2008, along with initial production from a well completed in February 2009 in the Cave Gulch field.

Hedging Activities.During the three months ended March 31, 2009, approximately 79% of our natural gas volumes and 49% of our oil volumes were hedged, which resulted in an increase in gas revenues of $83.9 million and an increase in oil revenues of $3.2 million after settlements for all commodity derivatives. During the three months ended March 31, 2008, approximately 75% of our natural gas volumes and 69% of our oil volumes were hedged, which resulted in an increase in gas revenues of $0.3 million, offset by a reduction in oil revenues of $2.1 million after settlements for all commodity derivatives.

Commodity Derivative Loss. Ineffectiveness on cash flow hedges, as defined under SFAS No. 133, related to slight differences between the contracted location and the actual delivery location is recognized in the line item titled “commodity derivative loss” in the Unaudited Condensed Consolidated Statements of Operations. We also have basis only swaps for natural gas in the Rocky Mountain region, which do not qualify for cash flow hedge accounting. The change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting is also recognized in the line item titled “commodity derivative loss” in the Unaudited Condensed Consolidated Statements of Operations.

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The table below summarizes the realized and unrealized gains and losses we recognized in commodity derivative loss for the periods indicated:

	Three Months Ended March 31,
	2009			2008
Realized losses on derivatives not designated as cash flow hedges	$	—		$	—
Unrealized ineffectiveness recognized on derivatives designated as cash flow hedges		(5,863	)		(1,530	)
Unrealized losses on derivatives not designated as cash flow hedges		(20,093	)		—
Total commodity derivative loss	$	(25,956	)	$	(1,530	)

Other Operating Revenues.Other operating revenues decreased to $0.5 million for the three months ended March 31, 2009 from $1.7 million for the three months ended March 31, 2008. Other operating revenues for the three months ended March 31, 2009 consisted of gathering fees of $0.5 million. Other operating revenues for the three months ended March 31, 2008 consisted of 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.

Lease Operating Expense.Lease operating expense increased slightly to $0.53 per Mcfe for the three months ended March 31, 2009 from $0.51 per Mcfe for the three months ended March 31, 2008. The following table displays the lease operating expense by basin:

	Three Months Ended March 31, 2009				Three Months Ended March 31, 2008				% Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		($ per Mcfe)
Piceance Basin	$	3,681	$	0.43	$	2,224	$	0.30	43	%
Uinta Basin		3,000		0.36		3,795		0.52	(31	)%
Wind River Basin		1,425		0.58		1,564		0.87	(33	)%
Powder River Basin		3,349		1.37		1,571		1.01	36	%
Paradox Basin		93		1.06		—		—	nm	*
Other		132		1.39		147		2.88	(52	)%
Total	$	11,680	$	0.53	$	9,301	$	0.51	4	%

* Not meaningful

Lease operating expense increased in the Piceance Basin to $0.43 per Mcfe for the three months ended March 31, 2009 from $0.30 per Mcfe for the three months ended March 31, 2008 primarily due to increased compression costs related to overhauls, higher company labor and increased property taxes associated with the recently constructed and equipped Bailey Compressor Station. The decrease in lease operating expense in the Uinta Basin to $0.36 per Mcfe for the three months ended March 31, 2009 from $0.52 per Mcfe for the three months ended March 31, 2008 was the result of decreased water disposal costs due to the utilization of a salt water disposal well. Shutting in a majority of the Lake Canyon and Blacktail Ridge fields, due to low oil prices and limited take away capacity, also contributed to lower lease operating expense in the Uinta Basin. Lease operating expense increased in the Powder River Basin to $1.37 per Mcfe for the three months ended March 31, 2009 from $1.01 per Mcfe for the three months ended March 31, 2008 primarily as a result of increased workover activity as well as increased rental and maintenance expenses. Lease operating expense decreased in the Wind River Basin to $0.58 per Mcfe for the three months ended March 31, 2009 from $0.87 per Mcfe for the three months ended March 31, 2008 as a result of increased production, decreased workover activity and reduced water handling costs.

Gathering and Transportation Expense.Gathering and transportation expense decreased to $0.50 per Mcfe for the three months ended March 31, 2009 from $0.52 per Mcfe for the three months ended March 31, 2008. The following table displays the gathering and transportation expense by basin:

	Three Months Ended March 31, 2009				Three Months Ended March 31, 2008				% Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		($ per Mcfe)
Piceance Basin	$	3,485	$	0.41	$	4,641	$	0.62	(34	)%
Uinta Basin		4,703		0.56		2,967		0.41	37	%
Wind River Basin		14		0.01		47		0.03	(67	)%
Powder River Basin		2,720		1.11		1,739		1.12	(1	)%
Other		102		0.56		5		0.10	460	%
Total	$	11,024	$	0.50	$	9,399	$	0.52	(4	)%

Gathering and transportation expense decreased in the Piceance Basin to $0.41 per Mcfe for the three months ended March 31, 2009 from $0.62 per Mcfe for the three months ended March 31, 2008 and increased in the Uinta Basin to $0.56 per Mcfe for the three months ended March 31, 2009 from $0.41 per Mcfe for the three months ended March 31, 2008. The decrease to the Piceance Basin and the increase to the Uinta Basin are related to the utilization of firm transportation on the Rockies Express Pipeline (“REX”). For

23

the three months ended March 31, 2009, the majority of production that we transported on REX was supplied from the Uinta Basin and for the three months ended March 31, 2008, the majority of production that we transported on REX was supplied from the Piceance Basin.

We have long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to reduce the risk and impact related to production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production in the Piceance, Uinta and Powder River Basins where we expect to allocate 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 Piceance and Uinta Basins. Included in the above gathering and transportation expense is $0.15 and $0.14 per Mcfe of transportation expense for the three months ended March 31, 2009 and 2008, respectively, along with $0.05 per Mcfe of processing expense from long-term contracts for both the three months ended March 31, 2009 and 2008.

The increase in firm transportation expense to $0.15 per Mcfe for the three months ended March 31, 2009 from $0.14 per Mcfe for the three months ended March 31, 2008 was the result of additional long-term contracts to gather, process and transport our West Tavaputs gas. In addition, fees on REX increased due to completion of an additional segment of the pipeline that gave us access to midcontinent delivery points farther east.

Production Tax Expense.Total production taxes decreased to $0.9 million for the three months ended March 31, 2009 from $10.3 million for the three months ended March 31, 2008. The decrease in production taxes is primarily related to decreased natural gas and oil prices because production taxes are calculated using wellhead values of production, which excludes gains from hedging activities. In addition to the decrease in natural gas and oil prices, on March 23, 2009, we entered into a settlement agreement with the State of Colorado that allowed additional deductions against the gross taxable value of our production related to our 2004 through 2006 severance tax returns. As a result, severance tax expense was reduced by $0.8 million related to the 2004 through 2006 tax years. Based on this settlement, we revised our estimates of 2007 and 2008 Colorado severance tax, which reduced our production tax expense by an additional $3.6 million. Excluding the reduction associated with the Colorado severance tax, production taxes as a percentage of natural gas and oil sales before hedging adjustments were 6.4% for the three months ended March 31, 2009 and 6.8% for the three months 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 for those areas.

Exploration Expense.Exploration expense increased to $0.8 million for the three months ended March 31, 2009 from $0.6 million for the three months ended March 31, 2008. Exploration expense for the three months ended March 31, 2009 consisted of $0.5 million for seismic programs, principally in the Uinta and Paradox Basins, and $0.3 million for delay rentals and other costs across all basins. The expense 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 to $0.2 million during the three months ended March 31, 2009 from $1.6 million during the three months ended March 31, 2008. For the three months ended March 31, 2009, abandonment expense was $0.1 million and dry hole costs were $0.1 million. For the three months ended March 31, 2008, abandonment expense was $0.2 million and dry hole costs were $1.4 million. For the three months ended March 31, 2009 and 2008, we did not incur any impairment charges.

Depreciation, Depletion and Amortization.DD&A was $58.8 million for the three months ended March 31, 2009 compared to $51.0 million for the three months ended March 31, 2008. The increase of $7.8 million was a result of increased production for the three months ended March 31, 2009 compared to the three months ended March 31, 2008, partially offset by a decrease in the DD&A rate. The increase in production accounted for $10.9 million of additional DD&A expense, offset by $3.1 million related to an overall decrease in the DD&A rate.

During the three months ended March 31, 2009, the weighted average DD&A rate was $2.66 per Mcfe. For the three months ended March 31, 2008, the weighted average DD&A rate was $2.80 per Mcfe. Under successful efforts accounting, DD&A 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 DD&A rate for current production. Future DD&A 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, decreased to $9.6 million in the three months ended March 31, 2009 from $10.6 million in the three months ended March 31, 2008. This decrease was primarily due to non-recurring expenses that were incurred in the three months ended March 31, 2008, including $0.4 million of penalty expense on a tax audit and $0.4 million related to the expensing of high-yield debt offering expenses costs that did not apply to our Convertible Notes offering. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, decreased to $0.43 per Mcfe for the three months ended March 31, 2009 from $0.58 per Mcfe for the three months ended March 31, 2008.

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Non-cash charges for stock-based compensation were $3.8 million for the three months ended March 31, 2009 compared to $3.6 million for the three months ended March 31, 2008. Non-cash stock-based compensation expense for each of the three months ended March 31, 2009 and 2008 related to vesting of our stock option awards and nonvested shares of common stock issued to employees. The increase in charges for non-cash stock-based compensation was primarily due to the additional equity awards that were granted in 2008 and during the three months ended March 31, 2009.

Interest Expense.Interest expense increased to $5.1 million for the three months ended March 31, 2009 from $3.9 million in the prior year period. Interest expense includes $1.5 million and $0.4 million of non-cash interest expense for the three months ended March 31, 2009 and 2008, respectively, associated with the implementation of FSP APB 14-1. The increase for the three months ended March 31, 2009 was due to higher average outstanding debt balances in order to fund exploration and development activities. Our weighted average outstanding debt balance, including our Amended Credit Facility and our Convertible Notes issued in March 2008, was $433.2 million for the three months ended March 31, 2009 compared to $273.1 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. The weighted average interest rates used to capitalize interest for the three months ended March 31, 2009 and 2008 were 5.6% and 6.0%, respectively, which included interest on both our Convertible Notes and Amended Credit Facility, amortization of the Convertible Note discount, 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. We capitalized interest costs of $0.8 million and $0.4 million for the three months ended March 31, 2009 and 2008, respectively.

Income Tax Expense. Our effective tax rate was 38.7% and 38.2% in the three months ended March 31, 2009 and 2008, respectively. For both the 2009 and 2008 periods, our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense under SFAS No. 123R and other operating expenses that are not deductible for income tax purposes.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been sales and other issuances of equity and debt 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. Currently, the debt and equity markets are under considerable stress and dislocation making financing transactions difficult and expensive to complete, if they can be completed at all. However, we believe that we have significant liquidity available to us from cash flows from operations and under our Amended Credit Facility for our planned uses of capital. In addition, our strong hedge positions provides relative certainty on a significant portion of our cash flows from operations through 2011 even upon a decline in the price of natural gas and oil resulting from current oversupply and decreased demand. 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, which, under current market conditions, we may not be able to obtain on terms acceptable to us or at all. We filed an automatically effective shelf registration statement with the SEC on April 24, 2009 that may be used for future securities offerings.

At March 31, 2009, we had cash and cash equivalents of $71.5 million with a balance of $276.0 million of borrowings outstanding under our Amended Credit Facility. At March 31, 2009, the borrowing base under our Amended Credit Facility (after a reduction for our Convertible Notes outstanding) was the maximum under the facility of $600.0 million, with commitments from 17 lenders for a total of $592.8 million.

Cash Flow from Operating Activities

Net cash provided by operating activities was $142.5 million and $85.2 million for the three months ended March 31, 2009 and 2008, respectively. The increase in net cash provided by operating activities was primarily due to an increase in oil and gas revenues, along with the change in current assets and liabilities, which were offset by increased expenses, as discussed above in “—Results of Operations.” Changes in current assets and liabilities resulted in an increase in cash flow from operations of $8.5 million for the three months ended March 31, 2009 compared to 2008 and a decrease in cash flow from operations of $22.5 million for the three months ended March 31, 2008 compared to 2007.

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Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas and oil production. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets, supply levels 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, 2009, we had in place natural gas and crude oil financial collars and swaps covering portions of our 2009, 2010 and 2011 production.

In addition to financial transactions, we may at times enter into 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 production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sales exception 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. As required under SFAS No. 157, all fair values are adjusted for non-performance risk. For derivative instruments that qualify and are designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in OCI until the forecasted transaction occurs. The ineffective portion of hedge derivatives is reported in commodity derivative gain or loss in the Unaudited Condensed Consolidated Statements of Operations. Realized gains and losses on cash flow hedges are transferred from OCI 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.

If the forecasted transaction to which the hedging instrument had been designated is no longer probable of occurring within the specified time period, the hedging instrument loses cash flow hedge accounting treatment in accordance with SFAS No. 133. All current mark-to-market gains and losses are recorded in earnings, and all accumulated gains or losses recorded in OCI related to the hedging instrument are also reclassified to earnings.

Some of our derivatives do not qualify for hedge accounting under SFAS No. 133 but are, to a degree, an economic offset to our commodity price exposure. If a derivative instrument does not qualify as a cash flow hedge or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in commodity derivative gain or loss in the Unaudited Condensed Consolidated Statements of Operations. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the underlying physical sales transaction takes place in the future and when the associated derivative instrument contract is settled by making or receiving a payment to or from the counterparty. Realized gains and losses of derivative instruments that do not qualify as cash flow hedges are recognized in commodity derivative gain or loss in the Unaudited Condensed Consolidated Statements of Operations and are reflected in cash flows from operations on the Unaudited Condensed Consolidated Statements of Cash Flows.

In addition to the swaps and collars discussed above, we have entered into basis only swaps to hedge the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. Although we believe this is a sound risk mitigation strategy, the basis only swaps do not qualify for hedge accounting under SFAS No. 133 because the total future cash flow has not been fixed. As a result, the changes in fair value of these derivative instruments are recorded in earnings. As of March 31, 2009, we had basis only hedges in place for a portion of our anticipated natural gas production in 2009, 2010, 2011 and 2012 for a total of 30,920,000 MMbtu. We recognized $20.1 million in unrealized net loss within commodity derivative loss in the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2009 attributable to these basis only swaps.

At March 31, 2009, the estimated fair value of all of our commodity derivative instruments was a net asset of $298.5 million comprised of current and noncurrent assets and noncurrent liabilities, including a fair value net liability of $20.1 million for basis only swaps. We will reclassify the appropriate cash flow hedge 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, 2009 to be reclassified from OCI to earnings in the next 12 months would be a gain of approximately $136.4 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 derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified time periods.

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The hedge instruments designated as cash flow hedges are at liquid trading locations but may contain slight differences compared to the delivery location of the forecasted sale, which may result in ineffectiveness in accordance with SFAS No. 133. Ineffectiveness related to our cash flow derivative instruments for the three months ended March 31, 2009 and 2008 was $5.9 million and $1.5 million, respectively, which was reported in commodity derivative loss in the Unaudited Condensed Consolidated Statements of Operations. Although those derivatives may not achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving our risk management objectives.

The table below summarizes the realized and unrealized gains and losses we incurred related to our oil and natural gas derivative instruments for the periods indicated:

	Three Months Ended March 31,
	2009			2008
Realized gains (losses) on derivatives designated as cash flow hedges (1)	$	87,119		$	(1,732	)
Realized losses on derivatives not designated as cash flow hedges	$	—		$	—
Unrealized ineffectiveness recognized on derivatives designated as cash flow hedges (2)		(5,863	)		(1,530	)
Unrealized losses on derivatives not designated as cash flow hedges (2)		(20,093	)		—
Total commodity derivative loss	$	(25,956	)	$	(1,530	)

(1) Included in “Oil and gas production” revenues in the Unaudited Condensed Consolidated Statements of Operations.

(2) Included in “Commodity derivative loss” in the Unaudited Condensed Consolidated Statements of Operations.

We have in place the following swap contracts and cashless collars (purchased put options and written call options) as of March 31, 2009 in order to hedge a portion of our natural gas production for the remainder of 2009 and years 2010, 2011 and 2012 and a portion of our oil production for the remainder of 2009 and the year 2010. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production. In addition to the swaps and collars, we also have in place basis only swaps in order to hedge the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location.

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Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Price		Weighted Average Ceiling Price		Weighted Average Fixed Price		Basis Differential			Index Price(1)	Fair Market Value (in thousands)
Cashless Collars:
2009
Natural gas	4,125,000	MMBtu	$	6.75	$	9.57		N/A		N/A		CIGRM	$	15,514
Natural gas	3,360,000	MMBtu	$	6.00	$	10.90		N/A		N/A		NWPL	$	9,871
Oil	151,250	Bbls	$	86.82	$	143.51		N/A		N/A		WTI	$	4,875
2010
Natural gas	6,080,000	MMBtu	$	6.00	$	10.41		N/A		N/A		NWPL	$	10,532
Natural gas	2,140,000	MMBtu	$	7.00	$	11.00		N/A		N/A		TCO	$	3,408
Oil	109,500	Bbls	$	90.00	$	163.00		N/A		N/A		WTI	$	3,210
Swap Contracts:
2009
Natural gas	33,620,000	MMBtu		N/A		N/A	$	6.87		N/A		CIGRM	$	134,464
Natural gas	4,615,000	MMBtu		N/A		N/A	$	7.91		N/A		PEPL	$	21,337
Natural gas	610,000	MMBtu		N/A		N/A	$	6.56		N/A		NWPL	$	1,719
Oil	103,125	Bbls		N/A		N/A	$	74.41		N/A		WTI	$	1,970
2010
Natural gas	32,495,000	MMBtu		N/A		N/A	$	6.95		N/A		CIGRM	$	75,733
Natural gas	3,040,000	MMBtu		N/A		N/A	$	6.52		N/A		NWPL	$	5,844
Natural gas	1,666,000	MMBtu		N/A		N/A	$	7.74		N/A		PEPL	$	4,438
Natural gas	2,140,000	MMBtu		N/A		N/A	$	9.43		N/A		DA	$	7,146
2011
Natural gas	9,440,000	MMBtu		N/A		N/A	$	7.02		N/A		CIGRM	$	13,515
Natural gas	2,140,000	MMBtu		N/A		N/A	$	7.75		N/A		NWPL	$	4,957
Basis Only Swap Contracts(2):
2009
Natural gas	2,750,000	MMBtu		N/A		N/A		N/A	$	(2.14	)	NWPL	$	(2,159	)
Natural gas	610,000	MMBtu		N/A		N/A		N/A	$	(1.75	)	CIGRM	$	(103	)
2010
Natural gas	6,690,000	MMBtu		N/A		N/A		N/A	$	(2.49	)	NWPL	$	(7,777	)
Natural gas	6,250,000	MMBtu		N/A		N/A		N/A	$	(2.34	)	CIGRM	$	(5,861	)
2011
Natural gas	7,300,000	MMBtu		N/A		N/A		N/A	$	(1.72	)	NWPL	$	(3,517	)
2012
Natural gas	3,660,000	MMBtu		N/A		N/A		N/A	$	(1.24	)	NWPL	$	(390	)
Natural gas	3,660,000	MMBtu		N/A		N/A		N/A	$	(1.20	)	CIGRM	$	(247	)

The following table includes all hedges entered into subsequent to March 31, 2009 through April 24, 2009:

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Price		Weighted Average Ceiling Price		Weighted Average Fixed Price		Basis Differential		Index Price(1)
Cashless Collars:
2011
Natural gas	2,140,000	MMBtu	$	4.75	$	6.00		N/A	N/A	��	CIGRM
Swap Contracts:
2009
Natural gas	915,000	MMBtu		N/A		N/A	$	4.24	N/A		CIGRM
2010
Natural gas	1,350,000	MMBtu		N/A		N/A	$	4.24	N/A		CIGRM
2011
Natural gas	2,140,000	MMBtu		N/A		N/A	$	5.25	N/A		CIGRM
Natural gas	2,140,000	MMBtu		N/A		N/A	$	5.33	N/A		NWPL

(1) CIGRM refers to Colorado Interstate Gas Rocky Mountains, TCO refers to Columbia Gas Transmission Corporation for Appalachia, NWPL refers to Northwest Pipeline Corporation, DA refers to Dominion Transmission Inc. 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.

(2) Represents a swap of the basis between the NYMEX price and the spot price of the index listed under Index Price above.

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By removing the price volatility from a portion of our natural gas production for 2009, 2010, 2011 and 2012 and a portion of our oil production for 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.

By using derivative instruments that are not traded or settled on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, 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 and who are lenders in our Amended Credit Facility, affiliates of lenders in our Amended Credit Facility, or potential lenders in our Amended Credit Facility. The creditworthiness of our counterparties is subject to continual review. Furthermore, we have ISDAs in place with all but one counterparty. The ISDAs contain set-off provisions that, in the event of counterparty default, allow us to net our receivables with amounts that we owe the counterparties under our Amended Credit Facility or other general obligations. As of March 31, 2009, JP Morgan Chase & Company, J. Aron & Company (a subsidiary of Goldman, Sachs & Company) and Bank of Montreal accounted for 43.8%, 26.8% and 18.6%, respectively, of the net fair market value of our derivative asset balance. The counterparty with whom we currently do not have an ISDA in place represents 1.4% of the fair value of the net fair market value of our derivative asset balance. We believe all of these institutions currently are acceptable credit risks. We are not required to provide credit support or collateral to any of our counterparties other than cross collateralization with the properties securing our Amended Credit Facility, nor are they required to provide credit support to us. As of April 24, 2009, we do not have any past due receivables from any of our counterparties.

Capital Expenditures

Our capital expenditures are summarized in the following tables:

	Three Months Ended March 31,
Basin/Area	2009		2008
	(in millions)
Piceance	$	47.3	$	37.8
Uinta		43.8		49.9
Paradox		10.1		—
Powder River		5.8		8.1
Wind River		1.6		7.4
Other		2.4		5.8
Total	$	111.0	$	109.0
	Three Months Ended March 31,
	2009		2008
	(in millions)
Acquisitions of proved and unevaluated properties and other real estate	$	1.1	$	4.7
Drilling, development, exploration and exploitation of natural gas and oil properties		108.1		101.7
Geologic and geophysical costs, exploratory dry hole costs and abandonment expense		0.9		2.2
Furniture, fixtures and equipment		0.9		0.4
Total	$	111.0	$	109.0

Total unevaluated properties decreased $36.7 million to $278.5 million at March 31, 2009 from $315.2 million at December 31, 2008. The decrease was principally as a result of a decrease in wells in progress due to decreased development and exploratory drilling activity during the three months ended March 31, 2009, along with existing wells coming online and the associated balances moved from unevaluated oil and gas properties to proved oil and gas properties.

Due to current commodity price forecasts and capital markets constraints, we plan to align capital spending with cash flow from operations. Our current estimate is for a capital expenditure budget of up to $350 million, which may be adjusted throughout the year as business conditions warrant. We expect that we have sufficient available liquidity through 2009 with the Amended Credit Facility, our hedge positions and cash flow from operations. 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 of cash flow to maintain planned levels of capital expenditures.

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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, including acquisitions and divestitures, in response to changes in prices, availability of financing, 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 and other factors both within and outside our control.

Financing Activities

Credit Facility. On April 15, 2009, we amended our credit facility (the “Amended Credit Facility”). The Amended Credit Facility, which matures on March 17, 2011, has commitments of $592.8 million and, based on year-end 2008 reserves and our hedge positions, a borrowing base of $600.0 million (after a reduction related to our Convertible Notes outstanding). Future borrowing bases will be computed based on proved natural gas and oil reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt. The borrowing base is required to be redetermined twice per year based on reserve estimates as of December 31 and June 30. The Amended Credit Facility bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 1.75% to 2.50% (an increase from 1.25% to 2.00% previously) or an alternate base rate, based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus 1.00% plus applicable margins ranging from 0.75% to 1.50% (an increase from 0.25% to 1.00% previously). We pay commitment fees ranging from 0.35% to 0.50% 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 March 31, 2009 and December 31, 2008, borrowings outstanding under the Amended Credit Facility totaled $276.0 and $254.0 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.

We have 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 OCI, 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, 2009 and 2008.

During the three months ended March 31, 2009, settlement payments on the interest rate derivative contracts, which were included in interest expense, were $0.2 million. We anticipate that all originally forecasted transactions will occur by the end of the originally specified time periods. As of March 31, 2009, based on current projected interest rates, the amount to be reclassified from accumulated other comprehensive income to net income in the next 12 months would be a reduction of approximately $0.4 million. At March 31, 2009, the estimated fair value of the interest rate derivatives was a liability of $0.4 million.

Convertible Notes. On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. The full $172.5 million principal amount of the Convertible Notes is currently outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by us. 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 certain events. 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 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. There is no established market for the Convertible Notes. The Convertible Notes are not traded on a public exchange. Therefore, based on market-based parameters of the various components of the Convertible Note, the estimated fair value was approximately $136.2 million as of March 31, 2009.

On or after March 26, 2012, at our option, we 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. In satisfaction of our obligation upon conversion of the Convertible Notes, we may elect to deliver, at our option, cash, shares of our common stock or a combination of cash and shares of our common stock. We currently

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intend to net cash settle the Convertible Notes. However, we have not made a formal legal irrevocable election to net cash settle and reserve 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 us to purchase all or a portion of their Convertible Notes for cash 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.

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 our 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, none of which occurred during the three months ended March 31, 2009 or through the date of the filing of this Form 10-Q. 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.

Effective January 1, 2009, we adopted FSP APB 14-1, which required retrospective application. Upon adoption, we recorded a debt discount of $23.1 million as of the date of the issuance of the Convertible Notes. The debt discount is amortized as additional non-cash interest expense over the expected term of the Convertible Notes through March 2012. Total non-cash interest expense related to the Convertible Notes was $1.5 million and $0.4 million for the three months ended March 31, 2009 and 2008, respectively. The amount of the interest expense recognized for the three months ended March 31, 2009 and 2008 related to the 5% contractual interest coupon that is paid in cash was $2.2 million and $0.4 million, respectively. Including the non-cash interest expense, the effective interest rate on our Convertible Notes is 9.7%.

As of March 31, 2009, the net carrying amount of the Convertible Notes was as follows (amounts in thousands):

Principal amount of the Convertible Notes	$	172,500
Unamortized debt discount		(17,840	)
Carrying amount of the Convertible Notes	$	154,660

Contractual Obligations.A summary of our contractual obligations as of and subsequent to March 31, 2009 is provided in the following table (in thousands):

	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	(in thousands)
Notes payable (1)	$	—	$	276,000	$	—	$	—	$	—	$	—	$	276,000
Convertible Notes (2)		8,625		8,625		180,981		—		—		—		198,231
Purchase commitments (3)(7)		4,422		4,130		2,472		—		—		—		11,024
Drilling rig commitments (4)(7)		21,429		13,236		2,831		—		—		—		37,496
Office and office equipment leases and other		2,588		2,137		586		3		—		—		5,314
Firm transportation and processing agreements (7)(8)		26,891		34,579		51,460		54,138		53,920		312,412		533,400
Asset retirement obligations (5)		424		9,700		2,441		1,507		630		33,416		48,118
Derivative liability (6)		593		2,872		638		—		—		—		4,103
Total	$	64,972	$	351,279	$	241,409	$	55,648	$	54,550	$	345,828	$	1,113,686

(1) Included in notes payable is the outstanding principal amount under our Amended Credit Facility. This table 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.

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(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, repay the $172.5 million in cash in 2012. We currently expect to call the Convertible Notes for redemption in 2012. We are also obligated to make annual interest payments equal to $8.6 million.

(3) We have one take-or-pay carbon dioxide (“CO2”) purchasing agreement that expires in October 2011 whereby we have a minimum volume commitment to purchase CO2 at a contracted price. The contract provides for CO2 used in fracturing operations in our West Tavaputs field. Should we not take delivery of the minimum volume required, we would be obligated to pay for the deficiency. At this time, our planned volumes needed exceed the minimum requirement and we do not anticipate any deficiency payments.

(4) We currently have four drilling rigs under contract. One contract expires in 2009, two contracts expire in 2010, and one contract expires in 2011.

(5) 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, 2008 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(6) Derivative liabilities represent the fair value for oil and gas commodity derivatives and interest rate derivatives presented as liabilities in our Unaudited Condensed Consolidated Balance Sheets as of March 31, 2009. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. 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, 2008 for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

(7) The values in the table represent the gross amounts that we are financially committed to pay. However, we record in our financials our proportionate share based on our working interest and net revenue interest, which will vary from basin to basin.

(8) 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 14 years and require us to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by us.

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, 2008 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 primary market risk exposure is in the price we received for our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional 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 collar contracts in place for the three months ended March 31, 2009, our annual income before income taxes would have decreased by approximately $0.3 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.1 million for each $1.00 per barrel decrease in crude oil prices.

We routinely 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 future prices received. These financial transactions may include 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. In addition to the swaps and collars discussed above, we also entered into basis only swaps. With a basis only swap, we have hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location to protect against the risk of large differences between NYMEX (Henry Hub) and our primary sales point, CIGRM.

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For the remaining three quarters of 2009, we currently have financial hedges in place for 47,245,000 MMBtu of natural gas production and approximately 254,375 Bbls of oil production. As of April 24, 2009, we have hedges in place for 48,911,000 MMBtu of natural gas production and 109,500 Bbls of oil production for 2010 and 18,000,000 MMBtu of natural gas production for 2011. In addition, we have basis only swaps in place for 3,360,000 MMBtu of natural gas for 2009, 12,940,000 MMBtu of natural gas for 2010, 7,300,000 MMBtu of natural gas for 2011 and 7,320,000 MMBtu of natural gas for 2012. These hedges are summarized in the table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Commodity Hedging Activities.”

Commodity Hedges

Through a price swap, we have fixed the price we will receive on a portion of our natural gas and oil production. 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.

Through a basis only swap, we have fixed the price differential on our natural gas production between NYMEX and a specific delivery location. In a basis only swap, the counterparty is required to make a payment to us if the price differential is greater than the fixed price. We are required to make a payment to the counterparty if the price differential is less than the fixed price. We will consider entering into hedge transactions based on a NYMEX price in the future with a volume equal to the volume for our basis only swaps, thereby effectively fixing a price for CIGRM.

Through cashless collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas and oil production. In a cashless 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 prices. These hedges are summarized in the table presented under “Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Cash Flow from Operating Activities— Commodity Hedging Activities.”

Interest Rate Risks

At March 31, 2009, we had debt outstanding under our Amended Credit Facility of $276.0 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, 2009 was 2.3%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the three months ended March 31, 2009 would have resulted in an estimated $5.3 million increase in interest expense assuming a similar average debt level to the three months ended March 31, 2009. We also had $172.5 million principal amount of Convertible Notes outstanding at March 31, 2009, which have a fixed cash interest rate of 5.0% per annum.

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% through December 2009. 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, through December 2009.

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, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures, as defined in Securities Exchange Act Rules 13a-15(e) and 15d-15(e), were effective as of March 31, 2009.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the three months ended March 31, 2009 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. In September 2008, we entered into a consent decree with the EPA pursuant to which we and our industry partner agreed to pay a fine of $240,000, of which we agreed to pay $140,000. The consent decree is subject to the approval of the United States Federal Court for the District of Utah.

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 or updates to the risk factors previously disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2008, referred to as our 2008 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 2008 Annual Report and subsequent reports filed with the SEC. 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.

Unregistered Sales of Securities

There were no sales of unregistered equity securities during the period covered by this report.

Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended March 31, 2009:

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, 2009	—	$	—	—	—
February 1 – 28, 2009	81,780		22.32	—	—
March 1 – 31, 2009	2,292		21.29	—	—
Total	84,072	$	22.29	—	—

(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/or shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of shares of common stock issued pursuant to our 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.

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Item 5. Other Information.

Not applicable.

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Item 6. Exhibits.

Exhibit Number	Description of Exhibits
3.1	Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.4 of our 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 of our 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 our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.1(b)	Indenture, dated March 12, 2008, between Bill Barrett Corporation and Deutsch Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our 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 our 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 Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 5% Convertible Senior Notes due 2028). [Incorporated by reference to Exhibit 4.2 of our 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 Exhibit B thereto the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to our 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 our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.6	Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 24, 2004.]
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 our Current Report on Form 8-K filed with the Commission on 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 our Current Report on Form 8-K filed with the Commission on 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 our Current Report on Form 8-K filed with the Commission on March 10, 2008.]
10.1(d)	Third Amendment to Second Amended and Restated Credit Agreement dated as of October 20, 2008, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on October 21, 2008.]
10.1(e)	Fourth Amendment to Second Amendment and Restated Credit Agreement dated as of April 15, 2009, 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 April 16, 2009.]
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 our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]

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10.3(a)*	Form of Indemnification Agreement dated April 15, 2004, between Bill Barrett Corporation and each of the directors and certain executive officers of the Company. [Incorporated by reference to Exhibit 10.10(a) to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
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 our 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 our 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 our 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 our 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 our 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 our 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 our 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 our 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 our 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 our 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 our Annual Report on Form 10-K for the year ended December 31, 2005.]
10.13*	Form of Restricted Common Stock Award Agreement for 2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10-19 to our Annual Report of Form 10-K for the year ended December 31, 2005.]
10.14(a)*	Form of Performance Vesting Restricted Stock Agreement for 2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10-19 to our Annual Report on Form 10-K for the year ended December 31, 2005.]
10.14(b)*	Form of Performance Vesting Restricted Stock Agreement for 2004 Stock Incentive Plan (2009 Temporary Supplemental Grant).
10.15*	2008 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on May 16, 2008.]
10.16*	Form of Stock Option Agreement for 2008 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.16 to our Annual Report on Form 10-K for the year ended December 31, 2008.]
10.17*	Severance Plan. [Incorporated by reference to Exhibit 10.23 to Amendment No. 4 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]

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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 5, 2009	By:	/s/ Fredrick J. Barrett
		Fredrick J. Barrett
		Chairman of the Board of Directors and Chief Executive Officer
		(Principal Executive Officer)
Date: May 5, 2009	By:	/s/ Robert W. Howard
		Robert W. Howard
		Chief Financial Officer
		(Principal Financial Officer)

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