Bill Barrett (BBG) 10-Q 2010 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, 2010

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	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

There were 45,930,835 shares of $0.001 par value common stock outstanding on April 23, 2010.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	35
Item 4.	Controls and Procedures	36
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3.	Defaults Upon Senior Securities	37
Item 5.	Other Information	37
Item 6.	Exhibits	38
SIGNATURES		41

2

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31, 2010			December 31, 2009
	(in thousands, except share and per share data)
Assets:
Current Assets:
Cash and cash equivalents	$	51,254		$	54,405
Accounts receivable, net of allowance for doubtful accounts of $771 at March 31, 2010 and $886 at December 31, 2009		63,900			62,573
Prepayments and other current assets		7,028			4,600
Derivative assets		118,151			58,461
Total current assets		240,333			180,039
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		2,427,094			2,360,200
Unevaluated oil and gas properties, excluded from amortization		277,010			274,819
Oil and gas properties held for sale		—			5,604
Furniture, equipment and other		25,519			24,727
		2,729,623			2,665,350
Accumulated depreciation, depletion, amortization and impairment		(1,030,687	)		(1,006,090	)
Total property and equipment, net		1,698,936			1,659,260
Derivative Assets		26,887			17,181
Deferred Financing Costs and Other Noncurrent Assets		20,193			9,643
Total	$	1,986,349		$	1,866,123
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	67,672		$	71,992
Amounts payable to oil and gas property owners		20,893			20,155
Production taxes payable		37,507			34,584
Derivative and other current liabilities		7,582			9,354
Deferred income taxes		40,204			17,207
Total current liabilities		173,858			153,292
Note Payable to Bank		15,000			5,000
Senior Notes		238,790			238,478
Convertible Senior Notes		160,139			158,772
Asset Retirement Obligations		48,030			46,785
Liabilities Associated with Assets Held for Sale		—			1,579
Deferred Income Taxes		236,788			218,307
Derivatives and Other Noncurrent Liabilities		9,543			15,355
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 45,924,120 and 45,475,585 shares issued and outstanding at March 31, 2010 and December 31, 2009, respectively, with 860,513 and 686,421 shares subject to restrictions, respectively		45			45
Additional paid-in capital		794,911			792,418
Retained earnings		205,659			181,682
Treasury stock, at cost: zero shares at March 31, 2010 and December 31, 2009		—			—
Accumulated other comprehensive income		103,586			54,410
Total stockholders’ equity		1,104,201			1,028,555
Total	$	1,986,349		$	1,866,123

See notes to unaudited condensed consolidated financial statements.

3

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended March 31,
	2010			2009
	(in thousands, except share and per share amounts)
Operating and Other Revenues:
Oil and gas production	$	163,649		$	170,176
Commodity derivative loss		(5,664	)		(25,956	)
Other		(175	)		520
Total operating and other revenues		157,810			144,740
Operating Expenses:
Lease operating expense		12,441			11,680
Gathering, transportation and processing expense		15,970			11,024
Production tax expense		8,289			926
Exploration expense		301			760
Impairment, dry hole costs and abandonment expense		2,879			185
Depreciation, depletion and amortization		56,534			58,757
General and administrative expense		13,776			13,380
Total operating expenses		110,190			96,712
Operating Income		47,620			48,028
Other Income and Expense:
Interest and other income		20			198
Interest expense		(10,123	)		(5,129	)
Total other income and expense		(10,103	)		(4,931	)
Income before Income Taxes		37,517			43,097
Provision for Income Taxes		13,540			16,684
Net Income	$	23,977		$	26,413
Net Income Per Common Share, Basic	$	0.53		$	0.59
Net Income Per Common Share, Diluted	$	0.53		$	0.59
Weighted Average Common Shares Outstanding, Basic		44,909,655			44,618,161
Weighted Average Common Shares Outstanding, Diluted		45,408,146			44,739,504

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 (Loss)
	(in thousands)
Balance — December 31, 2008	$	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		—		880			—		(2,065	)		—			(1,185	)	$	—
Excess tax benefit from option exercises		—		52			—		—			—			52			—
Stock-based compensation		—		17,899			—		—			—			17,899			—
Retirement of treasury stock		—		(2,065	)		—		2,065			—			—			—
Comprehensive income (loss):
Net income		—		—			50,218		—			—			50,218			50,218
Effect of derivative financial instruments, net of $80,468 of taxes		—		—			—		—			(137,662	)		(137,662	)		(137,662	)
Total comprehensive income (loss)																	$	(87,444	)
Balance — December 31, 2009	$	45	$	792,418		$	181,682	$	—		$	54,410		$	1,028,555
Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding		—		1,529			—		(3,383	)		—			(1,854	)	$	—
Stock-based compensation		—		4,347			—		—			—			4,347			—
Retirement of treasury stock		—		(3,383	)		—		3,383			—			—			—
Comprehensive income:																		—
Net income		—		—			23,977		—			—			23,977			23,977
Effect of derivative financial instruments, net of $29,290 of taxes		—		—			—		—			49,176			49,176			49,176
Total comprehensive income																	$	73,153
Balance — March 31, 2010	$	45	$	794,911		$	205,659	$	—		$	103,586		$	1,104,201

See notes to unaudited condensed consolidated financial statements.

5

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March  31,
	2010			2009
	(in thousands)
Operating Activities:
Net Income	$	23,977		$	26,413
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		56,534			58,757
Deferred income taxes		12,191			16,628
Impairment, dry hole costs and abandonment expense		2,879			185
Unrealized derivative loss		901			25,956
Stock compensation and other non-cash charges		4,255			4,314
Amortization of debt discounts and deferred financing costs		2,608			1,751
Loss on sale of properties		935			1
Change in operating assets and liabilities:
Accounts receivable		(1,327	)		12,909
Prepayments and other assets		(2,446	)		(2,504	)
Accounts payable, accrued and other liabilities		(15,192	)		6,668
Amounts payable to oil and gas property owners		738			(5,337	)
Production taxes payable		2,923			(3,205	)
Net cash provided by operating activities		88,976			142,536
Investing Activities:
Additions to oil and gas properties, including acquisitions		(91,145	)		(134,901	)
Additions of furniture, equipment and other		(709	)		(1,226	)
Proceeds from sale of properties		3,105			—
Net cash used in investing activities		(88,749	)		(136,127	)
Financing Activities:
Proceeds from credit facility		20,000			42,000
Principal payments on credit facility		(10,000	)		(20,000	)
Proceeds from sale of common stock		1,494			—
Deferred financing costs and other		(14,872	)		(2	)
Net cash provided by (used in) financing activities		(3,378	)		21,998
Increase (Decrease) in Cash and Cash Equivalents		(3,151	)		28,407
Beginning Cash and Cash Equivalents		54,405			43,063
Ending Cash and Cash Equivalents	$	51,254		$	71,470

See notes to unaudited condensed consolidated financial statements.

6

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

March 31, 2010

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, 2010, the Company’s results of operations for the three months ended March 31, 2010 and 2009 and cash flows for the three months ended March 31, 2010 and 2009. Operating results for the three months ended March 31, 2010 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, 2009 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 the Company’s 5% Convertible Senior Notes due 2028 (“Convertible Notes”) in computing dilutive earnings per share, volumes of natural gas and oil reserves used in calculating depreciation, depletion and amortization (“DD&A”), 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 and stock based payment awards.

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. 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, 2010 and 2009 were 11.4% and 5.6%, respectively, which include interest and amortization of discounts and deferred financing fees on the Company’s Convertible Notes, its 9.875% Senior Notes due 2016 (“Senior Notes”) and its credit facility. The Company capitalized interest costs of $1.3 million and $0.8 million for the three months ended March 31, 2010 and 2009, 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, 2010 and 2009, 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, including net capitalized costs associated with properties that were held for sale at December 31, 2009 of $5.6 million in total proved properties, which is net of accumulated depreciation, depletion and amortization and non-cash impairments (see Note 5 for further information on properties held for sale):

	As of March 31, 2010			As of December 31, 2009
	(in thousands)
Proved properties	$	433,160		$	432,286
Wells and related equipment and facilities		1,781,108			1,724,269
Support equipment and facilities		203,533			199,952
Materials and supplies		9,293			9,297
Total proved oil and gas properties		2,427,094			2,365,804
Accumulated depreciation, depletion, amortization and impairment		(1,019,759	)		(995,807	)
Total proved oil and gas properties, net	$	1,407,335		$	1,369,997
Unevaluated properties	$	153,100		$	154,837
Wells and equipment in progress		123,910			119,982
Total unevaluated oil and gas properties, excluded from amortization	$	277,010		$	274,819

Net changes in capitalized exploratory well costs for the three months ended March 31, 2010 are reflected in the following table (in thousands):

Beginning of period	$	51,494
Additions to capitalized exploratory well costs pending the determination of proved reserves		21,818
Reclassifications of wells, facilities and equipment based on the determination of proved reserves		(27,958	)
Exploratory well costs charged to dry hole costs and abandonment expense (1)		(2,105	)
End of period	$	43,249

(1) Excludes expired leasehold abandonment expense of $0.8 million for the three months ended March 31, 2010.

The following table presents costs of exploratory wells for which drilling has been completed for a period of greater than one year and which are included in unevaluated oil and gas properties as of March 31, 2010 pending determination of whether the wells will be assigned proved reserves:

	Time Elapsed Since Drilling Completed
	1-2 Years		3-5 Years		Total
	(in thousands, except number of wells amounts)
Costs of wells for which drilling has been completed	$	17,446	$	13,033	$	30,479
Number of wells for which drilling has been completed		53		31		84

As of March 31, 2010, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling were $30.5 million, of which $12.3 million 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 two years, 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 wells in the Powder River Basin, the Company has seven exploratory wells for a total of $18.2 million that have been capitalized for greater than one year. Five wells are located in the Paradox Basin, one well in the Big Horn Basin and one well in the Blacktail Ridge area of the Uinta Basin. The exploratory wells are suspended pending the completion of an economic evaluation including, but not limited to, results of additional appraisal drilling, facilities, infrastructure, well test analysis, additional geological and geophysical data and approval of a development plan. Management believes these projects with suspended exploratory drilling costs have sufficient quantities of hydrocarbons to justify their potential development and is actively pursuing efforts to assess whether reserves can be attributed to their respective areas. If additional information becomes available that raises substantial doubt regarding the economic or operational viability of any of these projects, the associated costs will be expensed.

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 estimated 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, 2010 and 2009, the Company did not recognize any non-cash impairment charges.

The provision for 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.

New Accounting Pronouncements.In January 2010, the FASB issued Accounting Standards Update 2010-06,Improving Disclosures about Fair Value Measurements, which amends Accounting Standards Codification 820,Fair Value Measurements and Disclosures.The intent of this update is to improve disclosure requirements related to fair value measurements and disclosures. New disclosures are required regarding transfers in and out of Levels 1 and 2 and activity within Level 3 fair value measurements, as well as clarification of existing disclosures regarding the level of disaggregation of derivative contracts and disclosures about fair value measurement inputs and valuation techniques. With the exception of disclosures regarding purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements, the new disclosures and clarifications of existing disclosures were effective for this filing and all new disclosure requirements have been incorporated. The disclosures regarding the roll forward of activity in Level 3 fair value measurements are effective for the Company beginning January 1, 2011. The adoption of these disclosure requirements 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 stock is calculated by dividing net income attributable to common stock 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, 2010 and 2009. The dilutive earnings per share for the three months ended March 31, 2010 and 2009 excludes the effect of 338,320 shares and 350,039 shares, respectively, of restricted stock and stock options because their effect was anti-dilutive.

9

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,
	2010		2009
Net income	$	23,977	$	26,413
Adjustments to net income for dilution		—		—
Net income adjusted for the effect of dilution	$	23,977	$	26,413
Basic weighted-average common shares outstanding in period		44,910		44,618
Add dilutive effects of stock options and nonvested equity shares of common stock		498		122
Diluted weighted-average common shares outstanding in period		45,408		44,740
Basic income per common share	$	0.53	$	0.59
Diluted income per common share	$	0.53	$	0.59

4. Supplemental Disclosures of Cash Flow Information

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

	Three Months Ended March  31,
	2010			2009
Cash paid for interest, net of amount capitalized	$	16,856		$	6,736
Cash paid for income taxes, net of refunds received		1,764			56
Supplemental disclosures of non-cash investing and financing activities:
Current liabilities that are reflected in investing activities		45,422			59,288
Current liabilities that are reflected in financing activities		—			38
Net increase (decrease) in asset retirement obligations		(1,058	)		239
Treasury stock acquired from employee stock option exercises		35			1,874
Retirement of treasury stock		(3,383	)		(1,874	)

5. Dispositions and Property Held for Sale

At December 31, 2009, the Company had properties held for sale in its North Hill Creek field located in the Uinta Basin. In March 2010, the Company completed the sale of these properties. The Company received $3.1 million in cash proceeds and recognized a $0.9 million pre-tax loss, which is included in other operating revenues in the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2010.

6. Long-Term Debt

Revolving Credit Facility

On March 16, 2010, the Company amended its credit facility (the “Amended Credit Facility”) and extended the maturity date to April 1, 2014. 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 2.0% to 3.0% or an alternate base rate (“ABR”), 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 1.0% to 2.0%. The average annual interest rates incurred on the Amended Credit Facility were 2.1% and 2.3% for the three months ended March 31, 2010 and 2009, respectively. Based on our year-end 2009 proved reserves and hedge positions, the borrowing base was increased to $800.0 million with commitments from 19 lenders of $700.0 million. Future borrowing bases will be computed based on proved natural gas and oil reserves, estimated future cash flows from those reserves and hedge positions, as well as any other outstanding debt or letters of credit of the Company. The borrowing base is required to be redetermined twice per year. The Company pays annual commitment fees of 0.5% of the unused amount of the commitments. 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 currently is in compliance with all financial covenants and has complied with all financial covenants for all prior periods.

As of March 31, 2010, the Company’s borrowings outstanding under the Amended Credit Facility totaled $15.0 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 currently is outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by the Company. 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. 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, including the Senior Notes. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility.

10

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 per note, the Company also will 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.

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.

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 that elects to convert its Convertible Notes.

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 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, 2010, 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		(12,361	)
Carrying amount of the Convertible Notes	$	160,139

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% per annum. The amount of the cash interest expense recognized with respect to the 5% contractual interest coupon for both the three months ended March 31, 2010 and 2009 was $2.2 million. The amount of non-cash interest expense related to the amortization of the debt discount and amortization of the transaction costs for the three month periods ended March 31, 2010 and 2009 was $1.7 million and $1.5 million, respectively.

There is no active, public market for the Convertible Notes. Based on market-based parameters of the various components of the Convertible Notes and over-the-counter trades, the aggregate estimated fair value of the Convertible Notes was approximately $169.5 million as of March 31, 2010 based on quoted market trades of these instruments.

9.875% Senior Notes Due 2016

On July 8, 2009, the Company issued $250.0 million in aggregate principal amount of Senior Notes due 2016 at 95.172% of par, resulting in a discount of $12.1 million. The Senior Notes mature on July 15, 2016. Interest is payable in arrears semi-annually on January 15 and July 15 beginning January 15, 2010. The Company received net proceeds of $232.3 million (net of related offering costs), which were used to repay a portion of the borrowings under the Amended Credit Facility. The Senior Notes are senior unsecured obligations of the Company and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness, including the Company’s Convertible Notes. The Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility. The Senior Notes include certain covenants that limit the Company’s ability to incur additional indebtedness, pay dividends, make restricted payments, create liens and sell assets. The Company currently is in compliance with all financial covenants and has complied with all financial covenants for all prior periods.

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The debt discount is amortized as additional non-cash interest expense over the term of the Senior Notes. As of March 31, 2010, the net carrying amount of the Senior Notes was as follows (amounts in thousands):

Principal amount of the Senior Notes	$	250,000
Unamortized debt discount		(11,210	)
Carrying amount of the Senior Notes	$	238,790

As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the Company’s Senior Notes is 11.3% per annum. The amount of the cash interest expense recognized with respect to the 9.875% contractual interest coupon for the three months ended March 31, 2010 was $6.2 million. The amount of non-cash interest expense related to the amortization of the debt discount and amortization of the transaction costs for the three month period ended March 31, 2010 was $0.6 million. The aggregate estimated fair value of the Senior Notes was approximately $270.0 million as of March 31, 2010.

7. Asset Retirement Obligations

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the Unaudited Condensed Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the Unaudited Condensed Consolidated Statements of Operations.

A reconciliation of the Company’s asset retirement obligations for the three months ended March 31, 2010 is as follows (in thousands):

Beginning of period	$	49,067
Liabilities incurred		592
Liabilities settled		(1,650	)
Accretion expense		864
Revisions to estimate		—
End of period	$	48,873
Less: current asset retirement obligations		843
Long-term asset retirement obligations	$	48,030

8. Fair Value Measurements

Assets and Liabilities Measured on a Recurring Basis

The Company’s financial instruments, including cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Amended Credit Facility, as discussed in Note 6, approximates its fair value due to its floating rate structure. The Company’s financial and non-financial assets and liabilities that are measured on a recurring basis are measured and reported at fair value.

Fair value is defined as 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. The market the Company transacts in and the Company’s instruments are fairly liquid. Therefore, the Company has been able to classify fair value balances based on the observability of those inputs. A fair value hierarchy was established 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 applicable instruments 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 as of March 31, 2010 that were measured at fair value on a recurring basis. Assets and 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	$	—	$	145,038		$	—	$	145,038
Liabilities
Commodity Derivatives	$	—	$	(15,993	)	$	—	$	(15,993	)

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. In addition, the fair value measurement of a liability has been adjusted to 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, 2010, and for the three months ended March 31, 2010, the Company did not have assets or liabilities measured under a Level 1 fair value hierarchy.

Level 2 Fair Value Measurements – 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. The Company did not make any adjustments to the obtained curves. The pricing services publish observable market information from multiple brokers and exchanges. No proprietary models are used by the pricing services for the inputs. The Company utilizes the counterparties’ valuations to assess the reasonableness of its valuations.

Level 3 Fair Value Measurements –As of March 31, 2010, and for the three months ended March 31, 2010, the Company did not have assets or liabilities measured under a Level 3 fair value hierarchy.

Assets and Liabilities Measured on a Non-recurring Basis

The Company utilizes fair value on a non-recurring basis to perform impairment tests as required on our property and equipment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3. Additionally, the Company uses fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition and would generally be classified within Level 3.

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9. Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues 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 the sale of a portion of the Company’s production. The Company does not enter into derivative instruments for speculative or trading purposes. As of March 31, 2010, the Company had hedges in place for a total of 33,750,000 gallons of natural gas liquids (“NGL”) through 2010, 458,000 Bbls of crude oil through 2011 and 85,456,000 MMBtu of natural gas through 2012, excluding basis only swaps described below.

In addition to financial contracts, 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. 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.

All derivative instruments, other than those that meet the normal purchase and normal sale exception as mentioned above, are recorded at fair market value and included in the Unaudited Condensed Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative instruments in the Unaudited Condensed Consolidated Balance Sheets as of March 31, 2010:

	Derivative Assets			Derivative Liabilities
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(in thousands)
Derivatives Designated as Cash Flow Hedges
Current
Commodity Contracts	Derivative Assets	$	137,703	Derivative Assets(2)	$	409
Commodity Contracts	Derivative and Other Current Liabilities(1)(3)		849	Derivative and Other Current Liabilities(3)		605
Long Term
Commodity Contracts	Derivative Assets		26,887	Derivative Asset (2)		—
Commodity Contracts	Derivatives and Other Noncurrent Liabilities(1)(4)		4,286	Derivatives and Other Noncurrent Liabilities(4)		55
Total derivatives designated as hedging instruments		$	169,725		$	1,069
Derivatives Not Designated as Cash Flow Hedges
Current
Commodity Contracts	Derivative Assets	$	3,899	Derivative Assets(2)	$	23,042
Commodity Contracts	Derivative and Other Current Liabilities(1)(3)		5	Derivative and Other Current Liabilities(3)		7,153
Long Term
Commodity Contracts	Derivative and Other Noncurrent Liabilities(1)(4)		—	Derivatives and Other Noncurrent Liabilities(4)		13,320
Total derivates not designated as hedging instruments		$	3,904		$	43,515
Total Derivatives		$	173,629		$	44,584

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

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

(3) This line item on the Unaudited Condensed Consolidated Balance Sheets also includes $678 of other current liabilities.

(4) This line item on the Unaudited Condensed Consolidated Balance Sheets also includes $454 of other noncurrent liabilities.

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For derivative instruments that qualify and are designated as cash flow hedges, changes in fair value, to the extent the hedges are effective, are recognized in accumulated other comprehensive income (“AOCI”) until the forecasted transaction occurs. The Company will reclassify the appropriate cash flow hedge amounts from AOCI to gains or losses in the Unaudited Condensed Consolidated Statements of Operations as the hedged production quantity is sold. Based on projected market prices as of March 31, 2010, the amount to be reclassified from AOCI to net income in the next 12 months would be an after-tax net gain of approximately $84.4 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. 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 loss in the Unaudited Condensed Consolidated Statements of Operations. The following table summarizes the cash flow hedge gains and losses and their locations on the Unaudited Condensed Consolidated Balance Sheet as of March 31, 2010 and Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2010:

Derivatives in Cash Flow Hedging Relationships	Amount of Gain Recognized in OCI (net of tax)		Location of Gain Reclassified from AOCI into Income	Amount of Gain Reclassified from AOCI into Income (before tax)		Location of Gain on Ineffective Hedges	Amount of Gain Recognized in Income on Ineffective Hedges (before tax)
	(in thousands)
Commodity Contracts	$	49,176	Oil and Gas Production	$	21,008	Commodity Derivative Loss	$	393

If, during the derivative’s term, the Company determines that the hedge is no longer effective or necessary, hedge accounting is prospectively discontinued. All subsequent changes in the derivative’s fair value are recorded in earnings, and all accumulated gains or losses, based on the effective portion of the derivative at that date, recorded in AOCI will remain in AOCI and are reclassified to earnings when the underlying transaction 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 and all subsequent mark-to-market gains and losses are recorded in earnings and all accumulated gains or losses recorded in AOCI related to the hedging instrument are also reclassified to earnings.

Some of the Company’s commodity derivatives do not qualify or are not designated as cash flow hedges but are, to a degree, an economic offset to the Company’s commodity price exposure. If a commodity derivative instrument does not qualify or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in commodity derivative 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. 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 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, the Company has entered into basis only swaps. Basis only swaps hedge the difference between the New York Mercantile Exchange (“NYMEX”) gas 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 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 loss in the Unaudited Condensed Consolidated Statements of Operations. As of March 31, 2010, the Company had basis only swaps in place for a portion of the Company’s anticipated natural gas production in 2010, 2011 and 2012 for a total of 24,860,000 MMbtu. The Company recognized $0.8 million in unrealized net losses and $4.7 million in realized losses within commodity derivative loss in the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2010 attributable to these basis swaps.

        The Company has also entered into swap contracts to hedge the amount received related to NGL resulting from the processing of our natural gas. The NGL hedges were not designated as cash flow hedges, and the fair value of these derivative instruments were recorded in earnings. As of March 31, 2010, the Company had NGL hedges in place for a total of 33,750,000 gallons. The Company recognized $0.5 million in unrealized loss within commodity derivative loss in the Consolidated Statements of Operations for the three months ended March 31, 2010 attributable to these NGL swaps.

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The following table summarizes the location in the Unaudited Condensed Consolidated Statements of Operations and amounts of realized and unrealized gains and losses on derivative instruments that do not qualify for hedge accounting for the three months ended March 31, 2010:

Derivatives Not Designated as Hedging Instruments	Location of Loss Recognized in Income on Derivatives	Amount of Loss Recognized  in Income on Derivatives for the Three Months Ended March 31, 2010
		(in thousands)
Commodity Contracts	Commodity Derivative Loss	$	(6,057	)

The Company was a party to various swap and collar contracts for natural gas that settled during the three months ended March 31, 2010. As a result, the Company recognized an increase of natural gas production revenues related to these contracts of $15.9 million and $83.9 million for the three months ended March 31, 2010 and 2009, respectively. The Company was also a party to various swap and collar contracts for oil, recognizing an increase to oil production revenues related to these contracts of $0.3 million and $3.2 million for the three months ended March 31, 2010 and 2009, 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,
	2010			2009
Realized gains on derivatives designated as cash flow hedges (1)	$	21,008		$	87,119
Realized losses on derivatives not designated as cash flow hedges	$	(4,763	)	$	—
Unrealized ineffectiveness gains (losses) recognized on derivatives designated as cash flow hedges		393			(5,863	)
Unrealized losses on derivatives not designated as cash flow hedges		(1,294	)		(20,093	)
Total commodity derivative loss (2)	$	(5,664	)	$	(25,956	)

(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 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 11 different counterparties. 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 creditworthiness of counterparties is subject to continual review by management, 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 that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility, or potential lenders in the Amended Credit Facility. The Company’s derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”) or other contracts. Typical terms for these contracts 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.

10. Income Taxes

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits. During the three months ended March 31, 2010, there was no change to the Company’s liability for uncertain tax positions.

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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, 2010, 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, 2010.

Income tax expense for the three months ended March 31, 2010 and 2009 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 the effect of state income taxes, stock-based compensation and other operating expenses not deductible for income tax purposes.

11. 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.

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, 2010, all treasury stock held by the Company was retired.

12. Accumulated Other Comprehensive Income

The components of accumulated other comprehensive income and related tax effects for the three months ended March 31, 2010 were as follows:

	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated other comprehensive income—December 31, 2009	$	87,280		$	(32,870	)	$	54,410
Unrealized change in fair value of cash flow hedges		99,474			(37,169	)		62,305
Reclassification adjustment for realized gains on hedges included in net income		(21,008	)		7,879			(13,129	)
Accumulated other comprehensive income—March 31, 2010	$	165,746		$	(62,160	)	$	103,586

13. Equity Incentive Compensation Plans and Other Employee Benefits

The Company maintains various stock-based compensation plans as discussed below. Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period).

Performance Share Program. On May 9, 2007, the Compensation Committee of the Board of Directors of the Company approved a performance share program (the “2007 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.

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As new goals are established each year for the performance-based awards, 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 an estimate of the extent to which 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.

Based upon Company performance in 2007, 30% of the performance shares vested in February 2008. Based upon the Company’s performance in 2008, 50% of the performance shares vested in February 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 were available for vesting if all stretch goals for 2009 were met. Based upon the Company’s performance in 2009, 50% of the total performance shares (including the supplemental grant) vested in February 2010.

In February 2010, the Compensation Committee approved a new performance share program (the “2010 Program”) pursuant to the Company’s 2008 Stock Incentive Plan (the “2008 Incentive Plan”). A total of 325,000 shares under the 2008 Incentive Plan were set aside for this program. The 2010 Program has the same four-year term and vesting provisions as the 2007 Program. For the year ending December 31, 2010, the performance goals consist of finding and development costs per Mcfe (weighted at 37.5%), combined lease operating expenses and general and administrative expenses (weighted at 25%) and production growth (weighted at 37.5%). In February 2010, a total of 226,465 performance-based nonvested equity shares of common stock were granted under the 2010 Program, and the grant date fair value was $30.94 per share. However, based upon the number of shares expected to vest through February 2011, the Company did not recognize any non-cash stock-based compensation cost associated with these shares for the three months ended March 31, 2010.

During the three months ended March 31, 2010, the Company also issued 56,611 of nonvested equity awards that are subject to a market performance-based vesting condition, which is based on the Company’s total stockholder return (“TSR”) ranking relative to a defined peer group’s individual TSRs. The aggregate grant date fair value of the market-based awards was $1.4 million based on a per-unit fair value of $29.31, which was determined using the Monte Carlo simulation method. The fair value of the market-based awards is amortized ratably over the four year requisite service period. All compensation expense related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. The Company recognized $0.1 million of compensation expense attributable to these awards for the three months ended March 31, 2010.

Stock Options and Nonvested Equity Shares. During the three months ended March 31, 2010, the Company granted 524,806 options to purchase shares of common stock with a weighted average exercise price of $30.96 per share, 206,486 nonvested equity shares of common stock and 283,076 performance-based nonvested equity shares of common stock (including the market-based awards as mentioned above). The Company recognized non-cash stock-based compensation cost related to the stock options and nonvested equity shares of $4.0 million for both the three months ended March 31, 2010 and 2009, including $0.3 million and $0.5 million associated with the performance-based nonvested equity shares for the three months ended March 31, 2010 and 2009, respectively. As of March 31, 2010, there were $34.7 million of total compensation costs related to grants of nonvested stock options and nonvested equity shares of common stock that are expected to be recognized over a weighted-average period of 2.8 years. This amount includes $1.4 million related to the market-based nonvested equity shares that is expected to be recognized ratably through February 2014.

Director Fees. The Company’s non-employee, or outside, 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 fees. For the three months ended March 31, 2010, the Company issued 2,303 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.

        Deferred Compensation Plan. In February 2010, the Compensation Committee approved a non-qualified deferred compensation plan for certain employees and executive officers whose eligibility to participate in the plan is determined by the Compensation Committee of the Company’s Board of Directors. The plan became effective on April 3, 2010. The Company will make matching contributions on behalf of eligible employees up to 6% of the employee’s cash compensation. All amounts deferred and matched under the plan vest immediately. All contributions and any earnings will be held in an irrevocable trust known as a “rabbi trust” administered by an independent trustee. Any assets placed in trust by the Company to fund future obligations of the Company’s non-qualified deferred compensation plan are subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their deferred compensation in the plan. The deferred amounts are payable to the participants at a time pre-selected by the participants, which can include separation from employment, death or disability, a change in control of the Company, or a set in-service date.

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14. Guarantor Subsidiaries

The Senior Notes and Convertible Notes are jointly and severally guaranteed on a full and unconditional basis by the Company’s (“Parent Issuer”) wholly-owned subsidiaries (“Guarantor Subsidiaries”). Presented below are the Company’s unaudited condensed consolidating balance sheets, unaudited statements of income and unaudited statements of cash flows, as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.

The following unaudited condensed consolidating financial statements have been prepared from the Company’s financial information on the same basis of accounting as the unaudited consolidated financial statements. Investments in the subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent Issuer and the Guarantor Subsidiaries are reflected in the Intercompany Eliminations column.

Condensed Consolidating Balance Sheets (Unaudited)

	March 31, 2010 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Assets:
Current assets	$	239,980		$	353		$	—	$	240,333
Property and equipment, net		1,610,754			88,182			—		1,698,936
Intercompany receivable (payable)		66,669			(66,669	)		—		—
Investment in subsidiaries		(5,075	)		—			5,075		—
Noncurrent assets		47,080			—			—		47,080
Total assets	$	1,959,408		$	21,866		$	5,075	$	1,986,349
Liabilities and Stockholders’ Equity:
Current liabilities	$	173,170		$	688		$	—	$	173,858
Long-term debt		413,929			—			—		413,929
Deferred income taxes		211,166			25,622			—		236,788
Other noncurrent liabilities		56,942			631			—		57,573
Stockholders’ equity		1,104,201			(5,075	)		5,075		1,104,201
Total liabilities and stockholders’ equity	$	1,959,408		$	21,866		$	5,075	$	1,986,349
	December 31, 2009 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Assets:
Current assets	$	179,718		$	321		$	—	$	180,039
Property and equipment, net		1,570,183			89,077			—		1,659,260
Intercompany receivable (payable)		67,202			(67,202	)		—		—
Investment in subsidiaries		(4,673	)		—			4,673		—
Noncurrent assets		26,824			—			—		26,824
Total assets	$	1,839,254		$	22,196		$	4,673	$	1,866,123
Liabilities and Stockholders’ Equity:
Current liabilities	$	152,655		$	637		$	—	$	153,292
Long-term debt		402,250			—			—		402,250
Deferred income taxes		192,685			25,622			—		218,307
Other noncurrent liabilities		63,109			610			—		63,719
Stockholders’ equity		1,028,555			(4,673	)		4,673		1,028,555
Total liabilities and stockholders’ equity	$	1,839,254		$	22,196		$	4,673	$	1,866,123

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Condensed Consolidating Statements of Income (Unaudited)

	Three Months Ended March 31, 2010 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Operating and other revenues	$	154,313		$	3,497		$	—	$	157,810
Operating costs and expenses		96,489			3,899			—		100,388
General and administrative		9,802			—			—		9,802
Interest and other income (expense)		(10,103	)		—			—		(10,103	)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		37,919			(402	)		—		37,517
Income tax expense		13,540			—			—		13,540
Equity in earnings (loss) of subsidiaries		(402	)		—			402		—
Net income (loss)	$	23,977		$	(402	)	$	402	$	23,977
	Three Months Ended March 31, 2009 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Operating and other revenues	$	143,077		$	1,663		$	—	$	144,740
Operating costs and expenses		80,980			2,352			—		83,332
General and administrative		13,380			—			—		13,380
Interest and other income (expense)		(4,931	)		—			—		(4,931	)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		43,786			(689	)		—		43,097
Income tax expense		16,684			—			—		16,684
Equity in earnings (loss) of subsidiaries		(689	)		—			689		—
Net income (loss)	$	26,413		$	(689	)	$	689	$	26,413
Condensed Consolidating Statements of Cash Flows (Unaudited)
	Three Months Ended March 31, 2010 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Cash flows from operating activities	$	87,693		$	1,283		$	—	$	88,976
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions		(90,684	)		(461	)		—		(91,145	)
Additions to furniture, fixtures and other		(420	)		(289	)		—		(709	)
Proceeds from sale of properties		3,105			—			—		3,105
Cash flows from financing activities:
Proceeds from debt		20,000			—			—		20,000
Principal payments on debt		(10,000	)		—			—		(10,000	)
Intercompany transfers		533			(533	)		—		—
Other financing activities		(13,378	)		—			—		(13,378	)
Change in cash and cash equivalents		(3,151	)		—			—		(3,151	)
Beginning cash and cash equivalents		54,405			—			—		54,405
Ending cash and cash equivalents	$	51,254		$	—		$	—	$	51,254

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	Three Months Ended March 31, 2009 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Cash flows from operating activities	$	141,879		$	657		$	—	$	142,536
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions		(133,650	)		(1,251	)		—		(134,901	)
Additions to furniture, fixtures and other		(1,024	)		(202	)		—		(1,226	)
Proceeds from sale of properties		—			—			—		—
Cash flows from financing activities:
Proceeds from debt		42,000			—			—		42,000
Principal payments on debt		(20,000	)		—			—		(20,000	)
Intercompany transfers		(796	)		796			—		—
Other financing activities		(2	)		—			—		(2	)
Change in cash and cash equivalents		28,407			—			—		28,407
Beginning cash and cash equivalents		43,063			—			—		43,063
Ending cash and cash equivalents	$	71,470		$	—		$	—	$	71,470

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

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory approval, regulatory changes, debt and equity market conditions, 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, 2009 under the “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” sections, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. The Company does not undertake any obligation to publicly update any forward-looking statements.

Overview

We explore for and develop oil and natural gas in the Rocky Mountain region of the United States. We intend to increase stockholder value by profitably growing reserves and production, primarily through drilling our development properties. We seek high quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of natural gas and oil production at market prices and the settlement of commodity hedges.

Bill Barrett Corporation (“we,” “our” or “us”) was formed in January 2002 and is incorporated in the State of Delaware. 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. In June 2009, we completed an acquisition of unproved undeveloped acreage in the Cottonwood Gulch area of the Piceance Basin.

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Results of Operations

The financial information for the three months ended March 31, 2010 and 2009 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, 2010 Compared to Three Months Ended March 31, 2009

	Three Months Ended March 31,						Increase (Decrease)
	2010			2009			Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil and gas production	$	163,649		$	170,176		$	(6,527	)	(4	)%
Commodity derivative loss		(5,664	)		(25,956	)		20,292		(78	)%
Other		(175	)		520			(695	)	(134	)%
Operating Expenses
Lease operating expense		12,441			11,680			761		7	%
Gathering, transportation and processing expense		15,970			11,024			4,946		45	%
Production tax expense		8,289			926			7,363		795	%
Exploration expense		301			760			(459	)	(60	)%
Impairment, dry hole costs and abandonment expense		2,879			185			2,694		nm	*
Depreciation, depletion and amortization expense		56,534			58,757			(2,223	)	(4	)%
General and administrative expense (1)		9,802			9,586			216		2	%
Non-cash stock-based compensation expense (1)		3,974			3,794			180		5	%
Total operating expenses	$	110,190		$	96,712		$	13,478		14	%
Production Data:
Natural gas (MMcf)		20,629			21,073			(447	)	(2	)%
Oil (MBbls)		184			169			15		9	%
Combined volumes (MMcfe)		21,733			22,087			(354	)	(2	)%
Daily combined volumes (MMcfe/d)		241			245			(4	)	(2	)%
Average Prices (2):
Natural gas (per Mcf)	$	7.08		$	7.72		$	(0.64	)	(8	)%
Oil (per Bbl)		70.04			43.95			26.09		59	%
Combined (per Mcfe)		7.31			7.70			(0.39	)	(5	)%
Average Costs (per Mcfe):
Lease operating expense	$	0.57		$	0.53		$	0.04		8	%
Gathering, transportation and processing expense		0.73			0.50			0.23		46	%
Production tax expense		0.38			0.04			0.34		850	%
Depreciation, depletion and amortization		2.60			2.66			(0.06	)	(2	)%
General and administrative expense (3)		0.45			0.43			0.02		5	%

 * 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 $13.8 million and $13.4 million for the three months ended March 31, 2010 and 2009, 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. As a result of our realized hedging transactions, natural gas production revenues were increased by $15.9 million and $83.9 million for the three months ended March 31, 2010 and 2009, respectively. As a result of our realized hedging transactions, oil production revenues were increased by $0.3 million and $3.2 million for the three months ended March 31, 2010 and 2009, respectively. Before the effects of hedging, the average prices we received for natural gas and oil were as follows:

	Three Months Ended March  31,
	2010		2009
Natural gas (per Mcf)	$	6.31	$	3.74
Oil (per Bbl)	$	68.23	$	25.00

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(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 $0.63 and $0.61 for the three months ended March 31, 2010 and 2009, respectively.

Production Revenues and Volumes.Production revenues decreased to $163.6 million for the three months ended March 31, 2010 from $170.2 million for the three months ended March 31, 2009, primarily due to a 2% decrease in production volumes and a 2% decrease in natural gas and oil prices after the effects of realized hedges. The net decrease in production volumes reduced production revenues by approximately $2.7 million, while the decrease in prices reduced production revenues by approximately $3.9 million.

Beginning in January 2009 and going forward, we elected to receive natural gas liquids (“NGL”) values for a portion of our natural gas production in the Piceance Basin. Given the strength of NGL market prices relative to natural gas during the three months ended March 31, 2010, we realized an increase in production revenues of approximately $12.8 million, or $0.59 per Mcfe as compared to an increase of $1.1 million, or $0.05 per Mcfe for the three months ended March 31, 2009. There is no assurance that the amount received related to NGL resulting from the processing of natural gas in the future will exceed the cost of processing.

Total production volumes for the three months ended March 31, 2010 of 21.7 Bcfe decreased from 22.1 Bcfe for the three months ended March 31, 2009 due to decreased production in the Uinta and Wind River Basins. The decrease in production was partially offset by an increase in production in the Piceance and Powder River Basins. Additional information concerning production is in the following table:

	Three Months Ended March  31, 2010			Three Months Ended March 31, 2009			% 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	105	9,169	9,799	103	7,979	8,597	2%	15%	14%
Uinta Basin	66	6,260	6,656	55	8,087	8,417	20%	(23)%	(21)%
Wind River Basin	4	1,821	1,845	5	2,408	2,438	(20)%	(24)%	(24)%
Powder River Basin	—	3,335	3,335	—	2,452	2,452	—	36%	36%
Other	9	44	98	6	147	183	50%	(70)%	(46)%
Total	184	20,629	21,733	169	21,073	22,087	9%	(2)%	(2)%

The production increase in the Piceance Basin was the result of our continued development activities with initial sales from 123 new gross wells from April 1, 2009 to March 31, 2010. The production increase in the Powder River Basin was the result of our continued development activities with initial sales from 95 new gross wells from April 1, 2009 to March 31, 2010. Although we have reduced our current year development activities in the Powder River Basin as the result of lower natural gas prices, our production in the Powder River Basin has benefited from prior year development programs due to the extended dewatering process of the coal bed methane wells. The production decrease in the Unita Basin is due to natural production declines as well as a limited development program compared to prior years in our West Tavaputs field with initial sales from 23 new gross wells from April 1, 2009 to March 31, 2010, partially offset by higher volumes from our Blacktail Ridge development. The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields with no significant drilling or recompletion activities to offset these declines.

Hedging Activities.During the three months ended March 31, 2010, approximately 77% of our natural gas volumes (excluding basis only swaps) and 47% of our oil volumes were hedged, which resulted in an increase in natural gas revenues of $15.9 million and an increase in oil revenues of $0.3 million after settlements for all commodity derivatives, including basis only and NGL swaps. 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 natural gas revenues of $83.9 million and an increase in oil revenues of $3.2 million after settlements for all commodity derivatives.

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Commodity Derivative Loss.The “Commodity derivative loss” line item on the Consolidated Statements of Operations is comprised of ineffectiveness on cash flow hedges and realized and unrealized gains and losses on hedges that do not qualify for cash flow hedge accounting or were not designated as cash flow hedges. Ineffectiveness on cash flow hedges relates to slight differences between the contracted location and the actual delivery location. Unrealized gains and losses represent the change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting, which includes our basis only swaps and NGL swaps. As those instruments settle, their settlement will be presented as realized gains and losses within this same line item.

The overall decrease in commodity derivative loss to $5.7 million for the three months ended March 31, 2010 from $26.0 million for the three months ended March 31, 2009 is primarily due to a reduction in unrealized losses resulting from the change in fair value of our basis only swaps of a loss of $0.8 million from January 1, 2010 to March 31, 2010 compared to the change in fair value of a loss of $20.1 million from January 1, 2009 to March 31, 2009.

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,
	2010			2009
Realized losses on derivatives not designated as cash flow hedges	$	(4,763	)	$	—
Unrealized ineffectiveness gains (losses) recognized on derivatives designated as cash flow hedges		393			(5,863	)
Unrealized losses on derivatives not designated as cash flow hedges		(1,294	)		(20,093	)
Total commodity derivative loss	$	(5,664	)	$	(25,956	)

Other Operating Revenues.Other operating revenues decreased to a loss of $0.2 million for the three months ended March 31, 2010 from a gain of $0.5 million for the three months ended March 31, 2009. Other operating revenues for the three months ended March 31, 2010 consisted of gathering, compression and salt water disposal fees received from third parties of $0.7 million, offset by a loss realized from the sale of the North Hill Creek field, located in the Uinta Basin, of $0.9 million. Other operating revenues for the three months ended March 31, 2009 primarily consisted of gathering and rental fees.

Lease Operating Expense.Lease operating expense increased to $0.57 per Mcfe for the three months ended March 31, 2010 from $0.53 per Mcfe for the three months ended March 31, 2009. The following table displays the lease operating expense by basin:

	Three Months Ended March  31, 2010				Three Months Ended March  31, 2009				%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		($ per Mcfe)
Piceance Basin	$	3,528	$	0.36	$	3,681	$	0.43	(16)%
Uinta Basin		3,895		0.59		3,000		0.36	64%
Wind River Basin		1,305		0.71		1,425		0.58	22%
Powder River Basin		3,370		1.01		3,349		1.37	(26)%
Other		343		3.50		225		1.23	185%
Total	$	12,441	$	0.57	$	11,680	$	0.53	8%

Lease operating expense per Mcfe decreased in the Piceance Basin to $0.36 per Mcfe for the three months ended March 31, 2010 from $0.43 per Mcfe for the three months ended March 31, 2009 primarily due to a 14% increase in production without an increase in costs, along with a decrease in compressor overhaul costs. Lease operating expense per Mcfe increased in the Uinta Basin to $0.59 per Mcfe for the three months ended March 31, 2010 from $0.36 per Mcfe for the three months ended March 31, 2009 primarily due to a 21% decrease in production as the result of a limited development program and natural production declines from existing wells. In addition, for the three months ended March 31, 2009 we shut in a majority of our Lake Canyon and Blacktail Ridge fields due to gas gathering constraints, which reduced our lease operating expense in the Uinta Basin. Both the Lake Canyon and Blacktail Ridge fields were on production for the three months ended March 31, 2010, which increased the lease operating expense compared to the prior year period. Lease operating expense per Mcfe increased in the Wind River Basin to $0.71 per Mcfe for the three months ended March 31, 2010, from $0.58 per Mcfe for the three months ended March 31, 2009 as a result of increased workover activity and natural production declines from existing wells. Lease operating expense per Mcfe decreased in the Powder River Basin to $1.01 per Mcfe for the three months ended March 31, 2010 from $1.37 per Mcfe for the three months ended March 31, 2009 primarily due to a 36% increase in production from wells that were previously in the dewatering stage, without increasing costs.

Gathering, Transportation and Processing Expense.Gathering, transportation and processing expense increased to $0.73 per Mcfe for the three months ended March 31, 2010 from $0.50 per Mcfe for the three months ended March 31, 2009. The following table displays the gathering, transportation and processing expense by basin:

	Three Months Ended March  31, 2010				Three Months Ended March  31, 2009				%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		($ per Mcfe)
Piceance Basin	$	6,760	$	0.69	$	3,485	$	0.41	68%
Uinta Basin		4,928		0.74		4,703		0.56	32%
Wind River Basin		34		0.02		14		0.01	100%
Powder River Basin		4,210		1.26		2,720		1.11	14%
Other		38		0.39		102		0.56	(30)%
Total	$	15,970	$	0.73	$	11,024	$	0.50	46%

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Gathering, transportation and processing expense per Mcfe increased in the Piceance Basin to $0.69 per Mcfe for the three months ended March 31, 2010 from $0.41 per Mcfe for the three months ended March 31, 2009. The increase is primarily attributable to utilization of firm transportation on the Rockies Express Pipeline (“REX”). For the three months ended March 31, 2010, the majority of gas we transported on REX was supplied from the Piceance Basin as compared to the majority of the supply coming from the Uinta Basin for the three months ended March 31, 2009. Gathering, transportation and processing expense per Mcfe in the Uinta Basin increased to $0.74 per Mcfe for the three months ended March 31, 2010 from $0.56 per Mcfe for the three months ended March 31, 2009. This increase is a result of additional contracts to gather, process and transport our West Tavaputs gas from the Uinta Basin, which more than offset the lower REX utilization. The Powder River Basin’s gathering, transportation and processing expense per Mcfe increased to $1.26 per Mcfe for the three months ended March 31, 2010 from $1.11 per Mcfe for the three months ended March 31, 2009 due to additional firm transportation contracts.

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, transportation and processing expense is $0.18 and $0.15 per Mcfe of firm transportation expense for the three months ended March 31, 2010 and 2009, respectively, along with $0.05 per Mcfe of processing expense from long-term contracts for both the three months ended March 31, 2010 and 2009. The increase in firm transportation expense to $0.18 per Mcfe for the three months ended March 31, 2010 from $0.15 per Mcfe for the three months ended March 31, 2009 was the result of additional long-term contracts executed with various pipelines for our natural gas production in the Powder River and Uinta Basins.

Production Tax Expense.Total production taxes increased to $8.3 million for the three months ended March 31, 2010 from $0.9 million for the three months ended March 31, 2009. The increase in production taxes is primarily related to an increase in natural gas and oil prices during the three months ended March 31, 2010. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense for the three months ended March 31, 2010 includes a one-time reduction of $2.2 million related to amended 2004 through 2009 State of Utah annual severance tax calculations. Production tax expense for the three months ended March 31, 2009 includes a one-time reduction of $4.4 million related to amended 2004 through 2008 State of Colorado annual severance tax calculations. Because these items are nonrecurring, if the reductions associated with the Utah and Colorado severance taxes are excluded in order to provide a more accurate comparison to the prior year, production taxes as a percentage of natural gas and oil sales before hedging adjustments were 7.4% for the three months ended March 31, 2010 and 6.4% for the three months ended March 31, 2009.

Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average 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 decreased to $0.3 million for the three months ended March 31, 2010 from $0.8 million for the three months ended March 31, 2009. Exploration expense for the three months ended March 31, 2010 consisted of $0.1 million for seismic programs, principally in the Paradox and Deseret Basins, and $0.2 million for delay rentals and other costs across all basins. 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.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense increased to $2.9 million during the three months ended March 31, 2010 from $0.2 million during the three months ended March 31, 2009. For the three months ended March 31, 2010, abandonment expense associated with exploratory drilling locations was $0.2 million, expired leasehold costs were $0.8 million and dry hole costs were $1.9 million. The $1.9 million in dry hole costs was primarily associated with one exploratory well in the Blacktail Ridge prospect of the Uinta Basin. For the three months ended March 31, 2009, abandonment expense associated with exploratory drilling locations was $0.1 million and dry hole costs were $0.1 million.

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Depreciation, Depletion and Amortization (“DD&A”).DD&A was $56.5 million for the three months ended March 31, 2010 compared to $58.8 million for the three months ended March 31, 2009. The decrease of $2.3 million was a result of a 2% decrease in production for the three months ended March 31, 2010 compared to the three months ended March 31, 2009, coupled with a decrease in the DD&A rate. The decrease in production accounted for $1.4 million of reduced DD&A expense, while the overall decrease in the DD&A rate accounted for $0.9 million of reduced DD&A expense.

During the three months ended March 31, 2010, the weighted average DD&A rate was $2.60 per Mcfe. For the three months ended March 31, 2009, the weighted average DD&A rate was $2.66 per Mcfe. Under the successful efforts method of accounting, DD&A expense is separately computed for each producing area based on proved reserves in each 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, increased to $9.8 million for the three months ended March 31, 2010 from $9.6 million for the three months ended March 31, 2009. This increase was primarily due to an increase in employee compensation and benefit programs for the three months ended March 31, 2010. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, increased to $0.45 per Mcfe for the three months ended March 31, 2010 from $0.43 per Mcfe for the three months ended March 31, 2009 due to decreased production.

Non-cash charges for stock-based compensation increased to $4.0 million for the three months ended March 31, 2010 from $3.8 million for the three months ended March 31, 2009. Non-cash stock-based compensation expense for each of the three months ended March 31, 2010 and 2009 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, including nonvested performance awards, which were granted during the last nine months of 2009 and during the three months ended March 31, 2010.

The components of non-cash stock-based compensation for the three months ended March 31, 2010 and 2009 are shown in the following table:

	Three Months Ended March  31,
	2010		2009
	(in thousands)
Stock options and nonvested equity shares of common stock	$	3,657	$	3,492
Shares issued for 401(k) plan		246		233
Shares issued for directors’ fees		71		69
Total	$	3,974	$	3,794

Interest Expense.Interest expense increased to $10.1 million for the three months ended March 31, 2010 from $5.1 million for the three months ended March 31, 2009. Although our weighted average outstanding debt balance decreased for the three months ended March 31, 2010 to $403.3 million from $433.2 million for the three months ended March 31, 2009, our effective interest rate was higher for the three months ended March 31, 2010 compared to the three months ended March 31, 2009 primarily due to our 9.875% Senior Notes due 2016 (“Senior Notes”) issued in July 2009. Our weighted average interest rate for the three months ended March 31, 2010, including interest and amortization of discounts and deferred financing fees on our credit facility amended March 16, 2010 (“Amended Credit Facility”), 5% Convertible Notes due 2028 (“Convertible Notes”) and Senior Notes, was 11.4% compared to 5.6% for the three months ended March 31, 2009.

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, 2010 and 2009 were 11.4% and 5.6%, respectively, which included interest and amortization of discounts and deferred financing fees on our Convertible Notes, Senior Notes, and Amended Credit Facility. We capitalized interest costs of $1.3 million and $0.8 million for the three months ended March 31, 2010 and 2009, respectively.

Income Tax Expense. Income tax expense totaled $13.5 million for the three months ended March 31, 2010 compared to $16.7 million for the three months ended March 31, 2009, resulting in effective tax rates of 36.1% and 38.7%, respectively. The effective tax rate decrease was primarily the result of a greater proportion of our operating revenue being attributable to lower tax rate jurisdictions, thereby decreasing the overall effective tax rate. The effect of this rate change on our prior year net deferred tax liability was included in income tax expense for the three months ended March 31, 2010. The effective tax rate will vary from period to period due to changes in the composition of income between state tax jurisdictions resulting from our activity. For both the 2010 and 2009 periods, our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes.

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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, including our Convertible Notes and Senior Notes, net cash provided by operating activities, bank credit facilities, 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 reserves 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. The recent credit market dislocation has improved; however, the costs to raise debt and equity capital have increased. 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 hedge positions provide relative certainty on a significant portion of our cash flows from operations through 2010 even with a general decline in the prices 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. We filed an automatically effective shelf registration statement with the SEC that we used for the offering of our Senior Notes and that we may use for future securities offerings.

At March 31, 2010, we had cash and cash equivalents of $51.3 million with a balance of $15.0 million of borrowings outstanding under our Amended Credit Facility. Under our Amended Credit Facility, we have a borrowing base of $800.0 million with commitments from 19 lenders for a total of $700.0 million.

Cash Flow from Operating Activities

For the three months ended March 31, 2010, we generated $89.0 million of cash provided by operating activities, a decrease of $53.5 million over the same period in 2009. Cash provided by operating activities decreased primarily due to a decrease in net income excluding non-cash commodity derivative losses, which were $0.9 million for the three months ended March 31, 2010 compared to $26.0 million for the three months ended March 31, 2009. In addition, lower natural gas and oil volumes and lower average sales prices for both crude oil and natural gas produced in the three months ended March 31, 2010 contributed to the decrease in operating cash compared to the three months ended March 31, 2009. Cash provided by operating activities further decreased due to changes in current assets and liabilities.

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, NGL and oil. Prices for these commodities are determined primarily by prevailing market conditions. National 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 “Item 3.—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, NGL and oil prices, we have entered into financial commodity swap and cashless collar contracts (purchased put options and written call options) to receive fixed prices for a portion of our production revenue. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production. We typically hedge a fixed price for natural gas at our sales points (New York Mercantile Exchange (“NYMEX”) less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. In addition to the swaps and collars, we also have 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. At March 31, 2010, we had in place natural gas, NGL and crude oil financial collars, swaps and basis only swaps covering portions of our 2010, 2011 and 2012 production.

In addition to financial contracts, 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. 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 and are included in the Unaudited Condensed Consolidated Balance Sheets as assets or liabilities. 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 accumulated other comprehensive income (“AOCI”) until the forecasted transaction occurs. The ineffective portion of hedge derivatives is reported in commodity derivative loss in the Unaudited Condensed Consolidated Statements of Operations. Realized gains and losses on cash flow hedges are transferred from AOCI 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.

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If, during the derivative’s term, we determine that the hedge is no longer effective or necessary, hedge accounting is prospectively discontinued. All subsequent changes in the derivative’s fair value are recorded in earnings, and all accumulated gains or losses, based on the effective portion of the derivative at that date, recorded in AOCI will remain in AOCI and are reclassified to earnings when the underlying transaction 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. All current mark-to-market gains and losses are recorded in earnings, and all accumulated gains or losses recorded in AOCI related to the hedging instrument are also reclassified to earnings. For additional information, see above “— Results of Operations — Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009”.

Some of our derivatives do not qualify for hedge accounting or are not designated as cash flow hedges 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 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 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 an appropriate part of a mitigation strategy, the basis only swaps do not qualify for hedge accounting 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, 2010, we had basis only hedges in place for a portion of our anticipated natural gas production in 2010, 2011 and 2012 for a total of 24,860,000 MMbtu. We recognized $0.8 million in unrealized net losses and $4.7 million in realized losses within commodity derivative loss in the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2010 attributable to these basis swaps. 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.

We have also entered into swap contracts to hedge a portion of the amount received related to NGL resulting from the processing of our gas. Our NGL hedges were not designated as cash flow hedges, and the fair value of these derivative instruments were recorded in earnings. As of March 31, 2010, we had NGL hedges in place for a total of 33,750,000 gallons (equivalent to approximately 3,072,000 MMBtu of natural gas) in 2010. We recognized $0.5 million in unrealized loss within commodity derivative loss in the Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2010 attributable to these NGL swaps.

At March 31, 2010, the estimated fair value of all of our commodity derivative instruments was a net asset of $129.0 million comprised of current and noncurrent assets and liabilities, including a fair value liability of $38.6 million for basis only swaps and a net fair value liability of $0.7 million for NGL swaps. We will reclassify the appropriate cash flow hedge amounts from AOCI to 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, 2010 to be reclassified from AOCI to earnings in the next 12 months would be a gain of approximately $84.4 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.

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. Ineffectiveness related to our cash flow derivative instruments for the three months ended March 31, 2010 and 2009 was a gain of $0.4 million and a loss of $5.9 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.

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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,
	2010			2009
Realized gains on derivatives designated as cash flow hedges (1)	$	21,008		$	87,119
Realized losses on derivatives not designated as cash flow hedges	$	(4,763	)	$	—
Unrealized ineffectiveness gains (losses) recognized on derivatives designated as cash flow hedges		393			(5,863	)
Unrealized losses on derivatives not designated as cash flow hedges		(1,294	)		(20,093	)
Total commodity derivative loss (2)	$	(5,664	)	$	(25,956	)

(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.

The following table summarizes all of our hedges in place as of March 31, 2010:

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:
Remainder of 2010
Natural gas	4,280,000	MMBtu	$	6.00	$	10.41		N/A		N/A		NWPL	$	9,648
Natural gas	1,757,500	MMBtu	$	4.85	$	5.65		N/A		N/A		CIGRM	$	1,939
Natural gas	2,140,000	MMBtu	$	7.00	$	11.00		N/A		N/A		TCO	$	6,059
Oil	110,000	Bbls	$	80.00	$	148.13		N/A		N/A		WTI	$	725
2011
Natural gas	2,140,000	MMBtu	$	4.75	$	6.00		N/A		N/A		CIGRM	$	667
Swap Contracts:
Remainder of 2010
Natural gas	30,180,000	MMBtu		N/A		N/A	$	6.58		N/A		CIGRM	$	81,844
Natural gas	4,885,000	MMBtu		N/A		N/A	$	6.34		N/A		NWPL	$	10,087
Natural gas	856,000	MMBtu		N/A		N/A	$	7.47		N/A		PEPL	$	3,062
Natural gas	2,140,000	MMBtu		N/A		N/A	$	9.43		N/A		DA	$	11,157
Natural gas liquids	33,750,000	Gallons		N/A		N/A	$	1.16		N/A		Mt. Belvieu	$	(708	)
Oil	275,000	Bbls		N/A		N/A	$	81.55		N/A		WTI	$	(931	)
2011
Natural gas	25,235,000	MMBtu		N/A		N/A	$	6.20		N/A		CIGRM	$	30,731
Natural gas	10,927,500	MMBtu		N/A		N/A	$	6.17		N/A		NWPL	$	12,991
Oil	73,000	Bbls		N/A		N/A	$	85.25		N/A		WTI	$	(65	)
2012
Natural gas	915,000	MMBtu		N/A		N/A	$	5.96		N/A		CIGRM	$	479
Basis Only Swap Contracts(2):
Remainder of 2010
Natural gas	4,890,000	MMBtu		N/A		N/A		N/A	$	(2.67	)	NWPL	$	(11,520	)
Natural gas	5,350,000	MMBtu		N/A		N/A		N/A	$	(2.45	)	CIGRM	$	(11,254	)
2011
Natural gas	7,300,000	MMBtu		N/A		N/A		N/A	$	(1.72	)	NWPL	$	(9,982	)
2012
Natural gas	3,660,000	MMBtu		N/A		N/A		N/A	$	(1.24	)	NWPL	$	(3,135	)
Natural gas	3,660,000	MMBtu		N/A		N/A		N/A	$	(1.20	)	CIGRM	$	(2,749	)

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The following table includes all hedges entered into subsequent to March 31, 2010 through April 23, 2010:

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Price	Weighted Average Ceiling Price	Weighted Average Fixed Price		Basis Differential	Index Price(1)
Swap Contracts:
2010
Natural gas liquids	3,150,000	Gallons	N/A	N/A	$	1.36	N/A	Mt. Belvieu
2011
Oil	73,000	Bbls	N/A	N/A	$	90.00	N/A	WTI

(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. Mt. Belvieu refers to the average daily price as quoted by Oil Price Information Service (“OPIS”) for Mont Belvieu spot gas liquid prices. 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.

By removing the price volatility from a portion of our natural gas production for 2010, 2011 and 2012 and a portion of our oil production for 2010 and 2011, 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 that 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, all of our derivative contracts are documented with an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”) or other contracts that 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.

We believe all of our counterparties 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 23, 2010, 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,
	2010		2009
	(in millions)
Basin/Area
Piceance	$	67.0	$	47.3
Uinta		31.6		43.8
Powder River		1.1		5.8
Wind River		1.9		1.6
Other		2.0		12.5
Total	$	103.6	$	111.0

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	Three Months Ended March  31,
	2010		2009
	(in millions)
Acquisitions of proved and unevaluated properties and other real estate	$	1.8	$	1.1
Drilling, development, exploration and exploitation of natural gas and oil properties(1)		101.0		108.1
Geologic and geophysical costs		0.3		0.9
Furniture, fixtures and equipment		0.5		0.9
Total(2)	$	103.6	$	111.0

(1) Includes related gathering and facilities costs.

(2) For the three months ended March 31, 2010, we received $3.1 million of proceeds principally from the sale of interests in oil and gas properties, which are not deducted from the capital expenditures presented above.

Our current estimate is for a capital expenditure budget of $450.0 to $470.0 million in 2010, which may be adjusted throughout the year as business conditions warrant. We believe that we have sufficient available liquidity through 2010 to fund our capital expenditures budget from cash flow from operations and the Amended Credit Facility. 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.

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 generally 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 March 16, 2010, we amended our credit facility (the “Amended Credit Facility”) and extended the maturity date to April 1, 2014. 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 2.0% to 3.0% (an increase from 1.75% to 2.50% previously) or an alternate base rate (“ABR”), 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 1.0% to 2.0% (an increase from 0.75% to 1.50% previously). The average annual interest rates incurred on the Amended Credit Facility were 2.1% and 2.3% for the three months ended March 31, 2010 and 2009, respectively. Based on our year-end 2009 proved reserves and hedge positions, the borrowing base was increased to $800.0 million with commitments of $700.0 million. Future borrowing bases will be computed based on proved natural gas and oil reserves, estimated future cash flows from those reserves and hedge position, as well as any other outstanding debt. The borrowing base is required to be redetermined twice per year. We pay annual commitment fees of 0.5% of the unused amount of the commitments. 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 “Item 3.—Quantitative and Qualitative Disclosure about Market Risk — Interest Rate Risks” below.

As of March 31, 2010 and December 31, 2009, borrowings outstanding under the Amended Credit Facility totaled $15.0 million and $5.0 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.

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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 Convertible Notes are our senior unsecured obligation and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Senior Notes. The Convertible Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under our Amended Credit Facility. 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. We currently 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. 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 active, public market for the Convertible Notes. Based on market-based parameters of the various components of the Convertible Notes and over-the-counter trades, the aggregate estimated fair value was approximately $169.5 million as of March 31, 2010.

We recorded a debt discount of $23.1 million, which represented the fair value of the equity conversion 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. The amount of non-cash interest expense related to the Convertible Notes was $1.7 million and $1.5 million for the three months ended March 31, 2010 and 2009, respectively. The amount of cash interest expense recognized for both the three months ended March 31, 2010 and 2009 related to the 5% contractual interest coupon was $2.2 million. Including the non-cash interest expense, the effective interest rate on our Convertible Notes is 9.7% per annum.

As of March 31, 2010, 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		(12,361	)
Carrying amount of the Convertible Notes	$	160,139

Senior Notes. On July 8, 2009, we issued $250.0 million in principal amount of 9.875% Senior Notes due 2016 at 95.172% of par. The Senior Notes will mature on July 15, 2016. Interest is payable in arrears semi-annually on January 15 and July 15 beginning January 15, 2010. We received net proceeds of $232.3 million (net of related offering costs), which were used to repay a portion of the borrowings under the Amended Credit Facility. The Senior Notes are our senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes. The Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under our Amended Credit Facility. The Senior Notes include certain covenants that limit our ability to incur additional indebtedness, pay dividends, make restricted payments, create liens and sell assets. We are in compliance with all covenants as of March 31, 2010 and for all prior periods.

The debt discount is amortized as additional non-cash interest expense over the term of the Senior Notes. As of March 31, 2010, the net carrying amount of the Senior Notes is as follows (amounts in thousands):

Principal amount of the Senior Notes	$	250,000
Unamortized debt discount		(11,210	)
Carrying amount of the Senior Notes	$	238,790

As a result of the amortization of the debt discount and amortization of the transaction costs through non-cash interest expense, the effective interest rate on the Senior Notes is 11.3% per annum. The amount of the cash interest expense recognized with respect to the 9.875% contractual interest coupon for the three months ended March 31, 2010 was $6.2 million. The amount of non-cash interest expense related to the amortization of the debt discount and amortization of the transaction costs for the three month period ended March 31, 2010 was $0.6 million. The aggregate estimated fair value of the Senior Notes was approximately $270.0 million as of March 31, 2010 based on quoted market trades of these instruments.

Shelf Registration Statement.We have on file with the SEC an effective universal shelf registration statement to allow us to offer an indeterminate amount of securities in the future. Under the registration statement, we may periodically offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any combination of such securities in amounts, prices and on terms announced when and if the securities are offered. However, we recognize that the issuance of additional securities in periods of market volatility may be less likely. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of any such offering.

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Contractual Obligations.A summary of our contractual obligations as of and subsequent to March 31, 2010 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)	$	—	$	—	$	—	$	—	$	15,000	$	—	$	15,000
Convertible Notes (2)		8,625		180,981		—		—		—		—		189,606
Senior Notes (3)		24,688		24,688		24,688		24,688		24,688		281,888		405,328
Purchase commitments (4)(8)		9,274		7,064		—		—		—		—		16,338
Drilling rig commitments (5)(8)		13,575		769		—		—		—		—		14,344
Office and office equipment leases and other		2,444		283		222		222		222		449		3,842
Firm transportation and processing agreements (8) (9)		53,903		61,591		54,910		57,178		50,237		277,647		555,466
Asset retirement obligations (6)		843		8,716		1,622		542		1,083		36,067		48,873
Derivative liability (7)		6,904		4,814		4,275		—		—		—		15,993
Total	$	120,256	$	288,906	$	85,717	$	82,630	$	91,230	$	596,051	$	1,264,790

(1) Included in notes payable is the outstanding principal amount under our Amended Credit Facility due April 1, 2014. 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.

(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 to be redeemed in 2012 or have them put to us. We are also obligated to make annual interest payments equal to $8.6 million.

(3) On July 8, 2009, we issued $250.0 million aggregate principal amount of Senior Notes. We are obligated to make annual interest payments equal to $24.7 million.

(4) We have one take-or-pay carbon dioxide (“CO2”) purchasing agreement that expires in October 2011 that has a minimum volume commitment to purchase CO2 at a contracted price, subject to annual escalation. The contract provides 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.

(5) We currently have three drilling rigs under contract. Two contracts expire in 2010, and one contract expires in 2011. All other rigs currently performing work for us are on a well-by-well basis and, therefore, can be released without penalty at the conclusion of drilling on the current well. These latter types of drilling obligations have not been included in the table above.

(6) 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, 2009 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(7) Derivative liabilities represent the fair value for oil and gas commodity derivatives presented as liabilities in our Unaudited Condensed Consolidated Balance Sheets as of March 31, 2010. 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, 2009 and in “—Commodity Hedging Activities” above in this Quarterly Report on Form 10-Q for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

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

(9) 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.

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Trends and Uncertainties

For a discussion of trends and uncertainties that may affect our financial condition or liquidity, 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, 2009.

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, 2009 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 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, NGL and oil 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 derivative contracts in place for the three months ended March 31, 2010, our annual income before income taxes would have decreased by approximately $0.5 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 hedges with respect to a portion of our projected production through various financial transactions, which hedge future prices received. These transactions may include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty and cashless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we and the counterparty to the collars would be required to settle the difference. These financial hedging activities are intended to support natural gas and oil prices at targeted levels and to manage our exposure to natural gas and oil price fluctuations. In addition to the swaps and collars discussed above, we also entered into basis only swaps. With a basis only swap, we have fixed 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 points, CIGRM and NWPL. We may 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 or NWPL.

As of April 23, 2010, we have hedges in place for 46,238,500 MMBtu of natural gas production, 36,900,000 gallons of NGL and 385,000 Bbls of oil production for 2010, 38,302,500 MMBtu of natural gas production and 146,000 Bbls of oil production for 2011 and 915,000 MMBtu of natural gas production for 2012. In addition, we have basis only swaps in place for 10,240,000 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.”

Interest Rate Risks

At March 31, 2010, we had debt outstanding under our Amended Credit Facility of $15.0 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, 2010 was 2.1%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the three months ended March 31, 2010 would have resulted in an estimated $0.2 million increase in interest expense assuming a similar average debt level to the three months ended March 31, 2010. In addition, we had $172.5 million principal amount of Convertible Notes and $250.0 million principal amount of Senior Notes outstanding at March 31, 2010, which have fixed cash interest rates of 5.0% and 9.875% per annum, respectively.

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Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Based on an evaluation carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2010.

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, 2010 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. 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, 2009, referred to as our 2009 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 2009 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, 2010:

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, 2010	—	$	—	—	—
February 1 – 28, 2010	104,569		31.75	—	—
March 1 – 31, 2010	1,872		33.61	—	—
Total	106,441	$	31.79	—	—

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

Item 3. Defaults upon Senior Securities.

Not applicable.

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 Deutsche 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.]
4.1(c)	Indenture, dated July 8, 2009, between Bill Barrett Corporation and Deutsche 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 July 8, 2009.]
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.]
4.2(c)	First Supplemental Indenture, dated July 8, 2009, by Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 9.875% Senior Notes due 2016). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on July 8, 2009.]
4.3(a)	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.]
4.3(b)	Second Supplemental Indenture, dated July 8, 2009, by Bill Barrett Corporation, Bill Barrett CBM Corporation, Bill Barrett CBM LLC, Circle B Land Company LLC and Deutsche Bank Trust Company Americas, as Trustee (including form of 9.875% Senior Notes due 2016). [Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K with the Commission on July 8, 2009.]
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.]

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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.]
10.1(f)	Third Amended and Restated Credit Agreement, dated as of March 16, 2010, 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 17, 2010.]
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.]
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.]

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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 on 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). [Incorporated by reference to Exhibit 10.14(b) to our Quarterly Report on Form 10-Q for the three months ended March 31, 2009.]
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.]
10.18*	Form of Performance Vesting Restricted Stock Agreement for 2008 Stock Incentive Plan.
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 4, 2010	By:	/s/ Fredrick J. Barrett
		Fredrick J. Barrett
		Chairman of the Board of Directors and Chief Executive Officer
		(Principal Executive Officer)
Date: May 4, 2010	By:	/s/ Robert W. Howard
		Robert W. Howard
		Chief Financial Officer
		(Principal Financial Officer)

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