Bill Barrett (BBG) 10-Q 2007 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, 2007

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.    Yes  x    No  ¨.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨

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

There were 44,357,424 shares of $0.001 par value common stock outstanding on May 7, 2007.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION			3
	Item 1.	Financial Statements	3
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	22
	Item 4.	Controls and Procedures	24
PART II. OTHER INFORMATION			25
	Item 1.	Legal Proceedings	25
	Item 1A.	Risk Factors	25
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	25
	Item 3.	Defaults Upon Senior Securities	25
	Item 4.	Submission of Matters to a Vote of Security Holders	25
	Item 5.	Other Information	25
	Item 6.	Exhibits	26
SIGNATURES			28

2

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	December 31, 2006			March 31, 2007
	(in thousands, except share and per share data)
Assets:
Current Assets:
Cash and cash equivalents	$	41,322		$	25,255
Accounts receivable, net of allowance for doubtful accounts of $284 as of December 31, 2006 and March 31, 2007		56,280			55,322
Prepayments and other current assets		2,697			4,167
Derivative assets		38,208			28,454
Total current assets		138,507			113,198
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		1,114,536			1,169,763
Unevaluated oil and gas properties, excluded from amortization		202,946			220,406
Oil and gas properties held for sale, net, excluded from amortization		75,496			77,221
Furniture, equipment and other		14,696			16,058
		1,407,674			1,483,448
Accumulated depreciation, depletion, amortization and impairment		(369,079	)		(407,185	)
Total property and equipment, net		1,038,595			1,076,263
Deferred Financing Costs, Derivative Assets and Other		10,299			5,505
Total	$	1,187,401		$	1,194,966
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	69,519		$	49,748
Amounts payable to oil and gas property owners		13,933			18,249
Production taxes payable		22,348			23,984
Other current liabilities		34			8
Deferred income taxes		13,961			10,327
Total current liabilities		119,795			102,316
Note Payable to Bank		188,000			200,000
Asset Retirement Obligations		29,224			29,868
Liabilities Associated with Assets Held for Sale		3,374			3,486
Deferred Income Taxes		89,730			95,245
Other Noncurrent Liabilities		881			914
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 44,141,453 and 44,332,980 shares issued and outstanding at December 31, 2006 and March 31, 2007, respectively, with 254,524 and 354,829 shares subject to restrictions, respectively		44			44
Additional paid-in capital		727,486			729,204
Retained earnings (Accumulated deficit)		(504	)		13,635
Accumulated other comprehensive income		29,371			20,254
Total stockholders’ equity		756,397			763,137
Total	$	1,187,401		$	1,194,966

See notes to condensed consolidated financial statements.

3

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended March 31,
	2006			2007
	(in thousands, except share and per share data)
Operating Revenues:
Oil and gas production	$	97,498		$	96,882
Other		276			1,498
Total operating revenues		97,774			98,380
Operating Expenses:
Lease operating expense		6,822			8,840
Gathering and transportation expense		3,951			5,126
Production tax expense		8,254			5,557
Exploration expense		3,284			1,606
Impairment, dry hole costs and abandonment expense		144			3,598
Depreciation, depletion and amortization expense		30,767			39,073
General and administrative expense		8,494			9,168
Total operating expenses		61,716			72,968
Operating Income		36,058			25,412
Other Income and Expense:
Interest and other income		646			532
Interest expense		(1,468	)		(2,875	)
Total other income and expense		(822	)		(2,343	)
Income before Income Taxes		35,236			23,069
Provision for Income Taxes		13,102			8,885
Net Income	$	22,134		$	14,184
Net Income Per Common Share, Basic	$	0.51		$	0.32
Net Income Per Common Share, Diluted	$	0.50		$	0.32
Weighted Average Common Shares Outstanding, Basic		43,575,465			43,931,828
Weighted Average Common Shares Outstanding, Diluted		44,066,176			44,201,207

See notes to 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 (Accumulated deficit)			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity			Comprehensive Income
	(in thousands)
Balance — December 31, 2005	$	44	$	721,145		$	(62,515	)	$	(5,180	)	$	(22,711	)	$	630,783
Exercise of options and shares exchanged for exercise and tax withholding		—		9,644			—			(5,059	)		—			4,585		$	—
Stock-based compensation		—		6,944			—			—			—			6,944			—
Retirement of treasury stock		—		(10,239	)		—			10,239			—			—			—
Other		—		(8	)		—			—			—			(8	)		—
Comprehensive income:
Net income		—		—			62,011			—			—			62,011			62,011
Effect of derivative financial instruments, net of tax		—		—			—			—			52,082			52,082			52,082
Total comprehensive income																		$	114,093
Balance — December 31, 2006		44		727,486			(504	)		—			29,371			756,397
Cumulative effect of adoption of Financial Accounting Standards Board Interpretation No. (FIN) 48		—		—			(45	)					—			(45	)		—
Exercise of options and shares exchanged for exercise and tax withholding		—		2,857			—			(3,187	)		—			(330	)		—
Stock-based compensation		—		2,048			—			—			—			2,048			—
Retirement of treasury stock		—		(3,187	)		—			3,187			—			—			—
Comprehensive income:
Net income		—		—			14,184			—			—			14,184			14,184
Effect of derivative financial instruments, net of tax		—		—			—			—			(9,117	)		(9,117	)		(9,117	)
Total comprehensive income																		$	5,067
Balance — March 31, 2007	$	44	$	729,204		$	13,635		$	—		$	20,254		$	763,137

See notes to condensed consolidated financial statements.

5

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March 31,
	2006			2007
	(in thousands)
Operating Activities:
Net Income	$	22,134		$	14,184
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		30,767			39,073
Deferred income taxes		13,102			8,885
Impairment, dry hole costs and abandonment expense		144			3,598
Stock compensation and other non-cash charges		1,792			2,069
Amortization of deferred financing costs		229			112
Gain on sale of properties		(139	)		(1,002	)
Change in operating assets and liabilities:
Accounts receivable		14,649			958
Prepayments and other assets		(215	)		(1,483	)
Accounts payable, accrued and other liabilities		(7,829	)		(13,492	)
Amounts payable to oil and gas property owners		(10,976	)		4,316
Production taxes payable		2,428			1,636
Net cash provided by operating activities		66,086			58,854
Investing Activities:
Additions to oil and gas properties, including acquisitions		(101,217	)		(87,094	)
Additions of furniture, equipment and other		(720	)		(1,432	)
Proceeds from sale of properties		818			1,335
Net cash used in investing activities		(101,119	)		(87,191	)
Financing Activities:
Proceeds from debt		11,000			12,000
Principal payments on debt		(9,000	)		—
Proceeds from sale of common stock		393			352
Deferred financing costs and other		(720	)		(82	)
Net cash provided by financing activities		1,673			12,270
Decrease in Cash and Cash Equivalents		(33,360	)		(16,067	)
Beginning Cash and Cash Equivalents		68,282			41,322
Ending Cash and Cash Equivalents	$	34,922		$	25,255

See notes to condensed consolidated financial statements.

6

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

March 31, 2007

1. Organization

Bill Barrett Corporation (the “Company”, “we” or “us”), a Delaware corporation, is an independent oil and gas company engaged in the exploration, development and production of natural gas and crude oil. Since its inception on January 7, 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States. We completed our initial public offering (“IPO”) in December 2004.

2. Summary of Significant Accounting Policies

Basis of Presentation.The accompanying unaudited condensed consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information. Pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), they do not include all 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 our financial position as of March 31, 2007. Operating results for the three months ended March 31, 2007 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, the uncertainty of exploration and development drilling results, and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, these condensed consolidated financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2006 previously filed with the SEC.

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

Oil and Gas Properties.The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Condensed Consolidated Statements of Cash Flows pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs also are 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. Until the third quarter of 2006, the Company had not capitalized any interest expense. The weighted average interest rate used to capitalize interest for the three months ended March 31, 2007 was 7.1%, including interest and commitment fees paid on the unused portion of our credit facility, amortization of deferred financing costs and the effects of interest rate hedges. The Company capitalized interest costs of $0.4 million for the three months ended March 31, 2007.

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

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

The following table sets forth the net capitalized costs and associated accumulated depreciation, depletion and amortization, including impairments, relating to the Company’s natural gas and oil producing activities, including net capitalized costs associated with properties held for sale as of March 31, 2007 of $60.1 million in total proved properties (excluded from amortization), which is net of $11.0 million of accumulated depreciation, depletion, amortization and impairment, and $17.1 million in total unevaluated properties (see Note 5 for further information on properties held for sale).

	As of December 31, 2006			As of March 31, 2007
	(in thousands)
Proved properties	$	346,619		$	349,738
Wells and related equipment and facilities		736,007			790,326
Support equipment and facilities		86,932			88,055
Materials and supplies		2,258			1,801
Total proved oil and gas properties		1,171,816			1,229,920
Accumulated depreciation, depletion, amortization and impairment		(363,587	)		(401,120	)
Total proved oil and gas properties, net	$	808,229		$	828,800
Unevaluated properties	$	139,689		$	148,373
Wells and equipment in progress		81,473			89,097
Total unevaluated oil and gas properties, excluded from amortization	$	221,162		$	237,470

Net changes in capitalized exploratory well costs for the three months ended March 31, 2007 are reflected in the following table (in thousands).

Beginning of period	$	69,596
Additions to capitalized exploratory well costs pending the determination of proved reserves		47,852
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(52,714	)
Exploratory well costs charged to dry hole costs and abandonment expense		(3,402	)
End of period	$	61,332

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

	March 31, 2007
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	42,637
Capitalized exploratory well costs that have been capitalized for a period greater than one year		18,695
End of period balance	$	61,332
Number of exploratory wells that have costs capitalized for a period greater than one year		157

As of March 31, 2007, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling include costs of $18.7 million. The majority of our exploratory wells that have been capitalized for a period greater than one year are located in the Powder River Basin. In this basin, we drill wells into various coal seams. In order to produce gas from the coal seams, a period of dewatering lasting from a few to 24 months, or in some cases longer, is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering and to classify the reserves as proved.

8

In addition to our wells in the Powder River Basin, the Company has one well that has been capitalized for greater than one year in the Wind River Basin. This well cannot be completed until the Bureau of Land Management grants approval for the right of way to build a gathering line to an existing gas pipeline.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. For the three months ended March 31, 2006 and 2007, the Company realized no impairment expense.

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

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

For awards granted while we were a nonpublic company (those granted prior to April 16, 2004, the date of which is defined by SFAS No. 123R as the date we became a public company as a result of making a filing with a regulatory agency in preparation for the sale of equity securities in a public market), we continue to use the minimum value method described under APB Opinion No. 25.

For awards granted after we were a public company (those granted subsequent to April 16, 2004) and for new, modified, repurchased, or cancelled awards on or subsequent to our adoption of SFAS No. 123R on October 1, 2004, we recognized share-based employee compensation cost based on the fair value as computed under SFAS No. 123R.

During the three months ended March 31, 2007, the Company granted 706,500 options to purchase shares of common stock with a weighted average exercise price of $30.55 per share and 159,000 nonvested equity shares of common stock. We recorded non-cash stock-based compensation related to option and nonvested equity share awards of $1.6 million and $1.9 million for the three months ended March 31, 2006 and 2007, respectively. As of March 31, 2007, there were $24.9 million of total compensation costs related to grants of nonvested stock options and nonvested equity shares of common stock grants that are expected to be recognized over a weighted-average period of 3.2 years.

New Accounting Pronouncements. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157,Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and expands disclosure requirements regarding fair value measurement. Where applicable, this statement simplifies and codifies fair value related guidance previously issued within GAAP. Although this statement does not require any new fair value measurements, its application may, for some entities, change current practice. SFAS No. 157 will be effective for the Company beginning January 1, 2008. The adoption of SFAS No. 157 is not expected to have a material impact on our financial statements.

3. Per Share Data and Earnings Per Share

Basic net income per common share is calculated by dividing net income attributable to common stock by the weighted average of vested common shares outstanding during each period. Diluted net income attributable to common stockholders is calculated by dividing net income attributable to common stockholders by the weighted average of common shares outstanding and other dilutive securities.

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,
	2006		2007
Net income	$	22,134	$	14,184
Adjustments to net income for dilution		—		—
Net income adjusted for the effect of dilution	$	22,134	$	14,184
Basic weighted-average common shares outstanding in period		43,575		43,932
Add dilutive effects of stock options and nonvested equity shares of common stock		491		269
Diluted weighted-average common shares outstanding in period		44,066		44,201
Basic income per common share	$	0.51	$	0.32
Diluted income per common share	$	0.50	$	0.32

4. Supplemental Disclosures of Cash Flow Information

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

	For three months ended March 31,
	2006			2007
Cash paid for interest	$	1,501		$	2,931
Cash paid for income taxes		—			152
Supplemental disclosures of non-cash investing and financing activities:
Retirement of treasury stock		(5,187	)		(3,187	)
Exchange of oil and gas properties for equipment and other properties		50			—
Adjustment of deferred tax liability – Powder River Basin properties acquisition purchase price allocation		—			1,635
Changes in current assets and liabilities that are reflected in investing activities		(1,900	)		(7,337	)
Net change in asset retirement obligations		495			353
Treasury stock acquired from employee stock option exercises		—			3,187

5. Acquisitions and Property Held for Sale

Acquisitions

On May 8, 2006, the Company acquired 100% of the outstanding stock of CH4 Corporation, a Delaware corporation (“CH4”), for $74.2 million in cash and agreed to pay $6.5 million of indebtedness of CH4. The acquisition was funded with borrowings under the Company’s credit facility. The primary assets of CH4 consisted of approximately 84,300 gross (52,000 net) acres of oil and gas leasehold interests of coal bed methane properties in the Powder River Basin of Wyoming and an estimated 11.0 Bcfe of proved reserves.

The CH4 acquisition was recorded using the purchase method of accounting, and the results of operations from the acquisition are included with the results of the Company from the date of closing. The total purchase price of the transaction was allocated preliminarily to the assets acquired and the liabilities assumed based on fair values at the acquisition date. The table below summarizes the allocation, which has been revised in the current quarter based on updated information (in thousands):

Purchase Price:
Cash paid, net of cash received	$	72,547
Debt assumed		6,495
Total	$	79,042
Allocation of Purchase Price:
Working capital	$	(327	)
Proved oil and gas properties		40,164
Unevaluated oil and gas properties		74,888
Other non-current assets		122
Deferred income taxes		(35,168	)
Asset retirement obligation		(637	)
Total	$	79,042

10

Property Held for Sale

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

During 2006, the Board of Directors of the Company acknowledged management’s plan to sell the Company’s oil and gas properties in the Williston Basin. In addition, the Company also decided to divest its Tri-State exploration project in the DJ Basin. In accordance with SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, these properties are carried at the lower of historical cost or fair value less cost to sell and were reclassified to oil and gas properties held for sale on the Condensed Consolidated Balance Sheet. Any liabilities related to those properties were also reclassified to liabilities associated with oil and gas properties held for sale on the Condensed Consolidated Balance Sheet. Under Emerging Issues Task Force (“EITF”) Issue No. 03-13, we determined that these sales do not qualify for discontinued operations reporting.

The following table presents the assets and liabilities associated with the oil and gas properties held for sale in the Williston and DJ Basins as of March 31, 2007 (in thousands):

Proved oil and gas properties	$	60,158
Unevaluated oil and gas properties	$	17,063
Noncurrent liabilities	$	3,486

For the three months ended March 31, 2007, total production volumes associated with the properties held for sale were 654 MMcfe.

6. Note Payable to Bank

On March 17, 2006, the Company amended its credit facility (the “Amended Credit Facility”). The Amended Credit Facility has a face value of $400.0 million, expandable up to $600.0 million, and had an initial borrowing base of $280.0 million. Based upon 2006 mid-year reserves, the borrowing base was increased to $310.0 million on October 6, 2006. Based on year-end 2006 reserves, the borrowing base was increased to $365.0 million on March 30, 2007. Upon disposal of our Williston Basin properties, the borrowing base will be reduced by $25.0 million. Future borrowing bases will be computed based on proved natural gas and oil reserves. The Amended Credit Facility matures on March 17, 2011 and bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 1.0% to 1.75% or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 0.25%. The Company pays commitment fees ranging from 0.25% to 0.375% of the unused borrowing base. The Amended Credit Facility is secured by natural gas and oil properties representing at least 80% of the value of the Company’s proved reserves and the pledge of all of the stock of our subsidiaries.

As of March 31, 2007, borrowings outstanding under the Amended Credit Facility totaled $200.0 million. The Amended Credit Facility also contains certain financial covenants. We have complied with all financial covenants for all periods.

7. Asset Retirement Obligations

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

A reconciliation of our asset retirement obligations for the three months ended March 31, 2007, which includes $3.5 million associated with oil and gas properties held for sale, is as follows (in thousands):

Beginning of period	$	32,598
Liabilities incurred		406
Liabilities settled		(70	)
Accretion expense		753
Revisions to estimate		17

11

End of period	$	33,704
Less: current asset retirement obligations		350
Long-term asset retirement obligations	$	33,354

8. Fair Value of Derivatives and Other Financial Instruments

The Company’s financial instruments, including cash and cash equivalents, accounts and notes receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Amended Credit Facility, as discussed in Note 6, approximates the fair value due to its floating rate structure. The Company’s derivatives are marked to market with changes in fair value being recorded in other comprehensive income.

Oil and Gas Commodity Hedges

The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its natural gas and oil production by reducing its exposure to price fluctuations. We have entered into commodity swap and collar contracts to fix the floor and ceiling prices we receive for a portion of our natural gas and oil production. Our natural gas and oil derivative financial instruments have been designated as cash flow hedges in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.

The Company was a party to various swap and collar contracts for natural gas based on the Colorado Interstate Gas Rocky Mountains (“CIGRM”) index during the three months ended March 31, 2006 and 2007. As a result, the Company recognized a reduction of natural gas production revenues related to these contracts of $0.7 million in the quarter ended March 31, 2006 and an increase of $7.2 million in the quarter ended March 31, 2007. The Company also was a party to various collar contracts for oil based on a West Texas Intermediate (“WTI”) index recognizing a reduction to oil production revenues related to these contracts of $0.9 million in the quarter ended March 31, 2006 and an increase of $0.2 million in the quarter ended March 31, 2007. As the underlying prices in the Company’s hedge contracts were consistent with the indices used to sell its natural gas and oil, no ineffectiveness was recognized related to its hedge contracts for the quarters ended March 31, 2006 and 2007.

At May 1, 2007, the Company had the following swap contracts and cashless collars (purchased put options and written call options) in order to hedge a portion of our 2007 and 2008 natural gas and oil production. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas production.

Product	Deliveries Per Day	Quantity Type	Weighted Average Floor Pricing		Weighted Average Ceiling Pricing		Weighted Average Fixed Price		Index Price (1)	Contract Period
Cashless Collars:
Natural gas	64,000	MMBtu	$	6.07	$	9.61		n/a	CIGRM	1/1/2007 —12/31/2007
Oil	800	Bbls	$	55.00	$	79.85		n/a	WTI	1/1/2007 —12/31/2007
Natural gas	35,000	MMBtu	$	6.50	$	10.00		n/a	CIGRM	1/1/2008 —12/31/2008
Oil	500	Bbls	$	70.00	$	80.15		n/a	WTI	1/1/2008 —12/31/2008
Swap Contracts:
Natural gas	5,000	MMBtu		n/a		n/a	$	5.21	CIGRM	2/1/2007 —10/31/2007
Natural gas	45,000	MMBtu		n/a		n/a	$	5.47	CIGRM	4/1/2007 —10/31/2007
Natural gas	5,000	MMBtu		n/a		n/a	$	5.14	CIGRM	5/1/2007 — 5/31/2007
Natural gas	55,000	MMBtu		n/a		n/a	$	6.90	CIGRM	11/1/2007 —3/31/2008
Natural gas	10,000	MMBtu		n/a		n/a	$	8.00	CIGRM	1/1/2008 — 3/31/2008
Natural gas	10,000	MMBtu		n/a		n/a	$	6.75	CIGRM	1/1/2008 —12/31/2008
Natural gas	5,000	MMBtu		n/a		n/a	$	6.30	CIGRM	4/1/2008 —10/31/2008

(1) CIGRM refers to Colorado Interstate Gas Rocky Mountains price as quoted in Platt’s Inside FERC on the first business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

The Company’s natural gas and oil derivative financial instruments have been designated as cash flow hedges in accordance with SFAS No. 133 and are included in current and other noncurrent assets on the Company’s Condensed Consolidated Balance Sheets.

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At March 31, 2007, the estimated fair value of contracts designated and qualifying as cash flow hedges under SFAS No. 133 was a net asset of $32.2 million. The Company will reclassify the appropriate amount to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of March 31, 2007 to be reclassified from accumulated other comprehensive income to net income in the next 12 months would be approximately $16.0 million. The Company anticipates that all originally forecasted transactions will occur by the end of the originally specified time periods.

Interest Rate Derivative Contracts

In December 2006, the Company entered into two interest rate derivative contracts to manage the Company’s exposure to changes in interest rates. The first contract was a floating-to-fixed interest rate swap for a notional amount of $10.0 million and the second was a floating-to-fixed interest rate collar for a notional amount of $10.0 million, both to terminate on December 12, 2009. The Company’s interest rate derivative instruments have been designated as cash flow hedges in accordance with SFAS No. 133. The derivatives were structured to mirror the critical terms of the hedged debt instruments; therefore, no ineffectiveness has been recorded in earnings.

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

As of March 31, 2007, the Company had received an insignificant amount in settlement payments, which were deducted from interest expense in the quarter ended March 31, 2007. The Company anticipates that all originally forecasted transactions will occur by the end of the originally specified time periods and, based on current projected interest rates, the net amount of existing unrealized after-tax income as of March 31, 2007 to be reclassified from accumulated other comprehensive income to net income in the next 12 months would be approximately $0.02 million. At March 31, 2007, the estimated fair value of the interest rate derivatives was a net asset of $0.06 million.

9. Income Taxes

The Company adopted FIN 48,Accounting for Uncertainty in Income Taxes, on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109,Accounting for Income Taxes. FIN 48 also prescribes a recognition threshold and measurement standard for the financial statement recognition and measurement of an income tax position taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption. In addition, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. As a result of the implementation of FIN No. 48, the Company recognized an increase of $0.2 million in the deferred liability for unrecognized tax benefits. Of this increase, $0.04 million was accounted for as a decrease to the beginning balance of retained earnings on the Condensed Consolidated Balance Sheet.

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in our income tax provision. As of the date of adoption of FIN 48, we did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the quarter.

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

At March 31, 2007, the Company’s balance sheet reflected a net deferred tax liability of $105.9 million, of which $12.0 million pertains to a net deferred tax liability of derivative instruments reflected in accumulated other comprehensive income and $24.8 million pertains to the deferred tax liability assumed through the CH4 acquisition.

Income tax expense for the three months ended March 31, 2006 and 2007 differs from the amounts that would be provided by applying the U.S. federal income tax rate to income before income taxes principally due to state income taxes, stock-based compensation not deductible for income tax purposes, and other permanent differences.

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10. Stockholders’ Equity

On December 9, 2004, the Company priced its shares to be issued in its IPO and began trading on the New York Stock Exchange the following day under the ticker symbol “BBG”. In connection with the IPO, a $1.9 million mandatorily convertible note was converted into 455,635 shares of Series A convertible preferred stock, all of the then outstanding shares of Series A and Series B convertible preferred stock were converted into 2,592,317 and 23,795,362 shares, respectively, of common stock, and the 9,242,648 shares of issued common stock were reverse split into 1,984,303 shares of common stock. Through the IPO, the Company sold an additional 14,950,000 shares of common stock to the public at the offering price of $25.00 per share, resulting in total outstanding shares of 43,321,982 immediately following the IPO. The Company received $347.3 million in net proceeds after deducting underwriters’ fees and related offering expenses. The proceeds received from the IPO were used principally to pay down debt outstanding under our credit facility and a bridge loan.

The Company’s authorized capital structure consists of 75,000,000 shares of $0.001 par value preferred stock and 150,000,000 shares of $0.001 par value common stock. In October 2004, 150,000 shares of $0.001 par value preferred stock were designated as Series A Junior Participating Preferred Stock, none of which are outstanding. At March 31, 2007, the Series A Junior Participating Preferred Stock was the Company’s only designated preferred stock, the remainder of authorized preferred stock being undesignated.

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

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

The Company may occasionally acquire treasury stock in connection with the vesting and exercise of share-based awards, which is recorded at cost. As of March 31, 2007, all treasury stock held by the Company was retired.

11.Accumulated Other Comprehensive Income

The components of accumulated other comprehensive income and related tax effects for the three months ended March 31, 2007 were as follows:

	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated other comprehensive income—December 31, 2006	$	46,807		$	(17,436	)	$	29,371
Change in fair value of hedges		(6,961	)		2,593			(4,368	)
Reclassification adjustment for realized gains on hedges included in net income		(7,569	)		2,820			(4,749	)
Accumulated other comprehensive income—March 31, 2007	$	32,277		$	(12,023	)	$	20,254

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

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conditions, regulatory changes, 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 (including in Part II, Item 1A) and in our Annual Report on Form 10-K for the year ended December 31, 2006 under the “Cautionary Note Regarding Forward-Looking Statements” section and the “Risk Factors” section, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

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

Results of Operations

The financial information with respect to the three months ended March 31, 2006 and 2007 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.

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Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2007

	Three Months Ended March 31,				Increase (Decrease)
	2006		2007		Amount			Percent
			($ in thousands)
Operating Results:
Operating Revenues
Oil and gas production revenues	$	97,498	$	96,882	$	(616	)	(1	)%
Other		276		1,498		1,222		443	%
Operating Expenses
Lease operating expense		6,822		8,840		2,018		30	%
Gathering and transportation expense		3,951		5,126		1,175		30	%
Production tax expense		8,254		5,557		(2,697	)	(33	)%
Exploration expense		3,284		1,606		(1,678	)	(51	)%
Impairment, dry hole costs and abandonment expense		144		3,598		3,454		nm	*
Depreciation, depletion and amortization expense		30,767		39,073		8,306		27	%
General and administrative expense (1)		6,866		7,278		412		6	%
Non-cash stock-based compensation (1)		1,628		1,890		262		16	%
Total operating expenses	$	61,716	$	72,968	$	11,252		18	%
Production Data:
Natural gas (MMcf)		12,204		13,031		826		7	%
Oil (MBbls)		156		190		34		22	%
Combined volumes (MMcfe)		13,140		14,171		1,031		8	%
Daily combined volumes (Mmcfe/d)		146		157		11		8	%
Average Prices (includes effects of hedges) (2):
Natural gas (per Mcf)	$	7.34	$	6.68	$	(0.66	)	(9	)%
Oil (per Bbl)		50.62		51.72		1.10		2	%
Combined (per Mcfe)		7.42		6.84		(0.58	)	(8	)%
Average Costs (per Mcfe):
Lease operating expense	$	0.52	$	0.62	$	0.10		19	%
Gathering and transportation expense		0.30		0.36		0.06		20	%
Production tax expense		0.63		0.39		(0.24	)	(38	)%
Depreciation, depletion and amortization (3)		2.34		2.89		0.55		24	%
General and administrative (4)		0.52		0.51		(0.01	)	(2	)%

* not meaningful

(1) Non-cash stock-based compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $8.5 million and $9.2 million for the three months ended March 31, 2006 and 2007, respectively, in the Condensed Consolidated Statements of Operations. This separate presentation is a non-GAAP financial 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 more accurate comparison to our peers, who may have higher or lower costs associated with equity grants.

(2) Average prices shown in the table are net of the effects of hedging transactions. As a result of hedging transactions, natural gas and oil production revenues were reduced by $1.6 million for the three months ended March 31, 2006 and were increased by $7.4 million for the three months ended March 31, 2007. Before the effect of hedging contracts, the average price we received for natural gas and oil for the three months ended March 31, 2006 was $7.40 per Mcf and $55.99 per Bbl, respectively, compared with $6.13 per Mcf and $50.61 per Bbl, respectively, for the three months ended March 31, 2007.

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

(4) Excludes non-cash stock-based compensation as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation, as presented in the Condensed Consolidated Statement of Operations, would be $0.65 for the three months ended March 31, 2006 and 2007.

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Production Revenues.Production revenues decreased from $97.5 million for the three months ended March 31, 2006 to $96.9 million for the current year period primarily due to a decrease in natural gas prices after the effect of hedges, offset by a slight increase in oil prices and an 8% increase in production. The net decrease in prices on an Mcfe basis lowered production revenues by approximately $7.6 million, and the production increases added approximately $7.0 million of production revenues, after natural production declines, so that new production from our drilling program more than offset natural production declines.

On an Mcf equivalent basis, total production volumes for the three months ended March 31, 2007 increased 8% from total production for the prior year comparable period. Production increased in the Uinta, Piceance and Williston Basins by 28%, 54% and 12%, respectively. These increases in production were partially offset by decreases in the Wind River and Powder River Basins of 42% and 18%, respectively. Additional information concerning production is in the following table.

	Three Months Ended March 31, 2006			Three Months Ended March 31, 2007
	Oil	Natural Gas	Total	Oil	Natural Gas	Total
	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MMcf)	(MMcfe)
Uinta Basin	10	4,451	4,511	9	5,742	5,796
Piceance Basin	37	2,532	2,755	64	3,847	4,231
Wind River Basin	12	3,420	3,490	9	1,968	2,022
Powder River Basin	—	1,748	1,748	—	1,434	1,434
Williston Basin (1)	91	38	584	103	34	652
Other	6	15	52	5	6	36
Total	156	12,204	13,140	190	13,031	14,171

(1) The Williston Basis is classified as held for sale as of March 31, 2007.

The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields. The production increase in the Uinta Basin reflects our successful exploration and development activities in the West Tavaputs field. Furthermore, the addition of three compressors, one in early January and two in March 2007, increased our takeaway capacity in the West Tavaputs field by approximately 20 MMcf per day. The production increase in the Piceance Basin is the result of our continued development activities. The production decrease in the Powder River Basin is due to natural production declines in our existing mature fields and the lag time between drilling of coal bed methane wells and production of natural gas while dewatering occurs, which are partially offset by the initial production from the properties we acquired from CH4 in early May 2006. As of March 31, 2007, we had 123 net operated coal bed methane wells in the dewatering stage with little or no production.

Hedging Activities.During the three months ended March 31, 2006, approximately 41% of our natural gas volumes and 43% of our oil volumes were hedged, resulting in a reduction in revenues of $1.6 million. During the three months ended March 31, 2007, approximately 57% of our natural gas volumes and 38% of our oil volumes were hedged, resulting in an increase in revenues of $7.4 million.

Other Operating Revenues. Other operating revenues increased from $0.3 million for the three months ended March 31, 2006 to $1.5 million for the three months ended March 31, 2007. The increase is primarily due to gains realized on joint exploration agreements entered into in the Paradox Basin.

Lease Operating Expense and Gathering and Transportation Expense.Our lease operating expense increased from $0.52 per Mcfe in the first three months of 2006 to $0.62 per Mcfe in the current year period, and our gathering and transportation expense increased from $0.30 per Mcfe in the first three months of 2006 to $0.36 per Mcfe in the current year period. The increase in lease operating expenses is primarily due to an increase in the Powder River Basin from $0.81 per Mcfe for the three months ended March 31, 2006 to $1.43 per Mcfe in the current year period and the Wind River Basin from $0.52 per Mcfe for the three months ended March 31, 2006 to $0.97 per Mcfe in the current year period. The increase on a per Mcfe basis in the Powder River Basin is substantially due to higher water handling charges on dewatering wells in new pilot areas that have no offsetting gas production as yet. As of March 31, 2007, we had 123 net operated coal bed methane wells in the dewatering stage. The increase on a per Mcfe basis in the Wind River Basin is due to the natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields, while overall lease operating expenses have remained relatively consistent.

We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to avoid possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production from the Piceance and Uinta Basins where we expect to spend a significant portion of our capital expenditure program in future years. Included in the above gathering and transportation expense is $0.07 per Mcfe and $0.06 per Mcfe of transportation expense from long-term contracts for the three months ended March 31, 2006 and 2007, respectively.

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Production Tax Expense.Total production taxes decreased from $8.3 million for the three months ended March 31, 2006 to $5.6 million for the current year period. Although our production volumes increased and our production revenues decreased only slightly, our overall production taxes decreased, as a larger portion of our revenues came from areas with lower tax rates. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 8.3% for the three months ended March 31, 2006 and 6.2% for the current year period. Production taxes are primarily based on the wellhead values of production and tax rates that vary across the different areas in which we operate. As the proportion of our production changes from area to area, our production tax rate will either increase or decrease depending on the quantities produced from each area and the production tax rates in effect in each individual area.

Exploration Expense.Exploration costs decreased from $3.3 million in the first three months of 2006 to $1.6 million in the current year period. The costs for the three months ended March 31, 2006 consisted of $3.0 million for seismic programs principally in the Piceance, Uinta, Wind River and DJ Basins and Montana Overthrust, and $0.3 million for delay rentals and other costs. The costs for the three months ended March 31, 2007 consisted of $1.4 million for seismic programs, principally in the Montana Overthrust, Uinta Basin, and Paradox Basin, and $0.2 million for delay rentals and other exploration costs.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense increased from $0.1 million during the first three months of 2006 to $3.6 million during the current year period. For the three months ended March 31, 2006, abandonments were $0.1 million. For the three months ended March 31, 2007, dry hole costs were $3.0 million, and abandonment expense was $0.6 million. Dry hole costs for the three months ended March 31, 2007 were primarily attributable to the Cooper Deep #1, an exploration well located in the Wind River Basin. This well, which was completed in late November 2006, was tested and determined to be non-commercial in the zones below the Niobrara formation; thus, a proportionate share of the well cost is being expensed.

We evaluate the impairment of our oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. If the carrying amount exceeds the properties’ estimated fair value, we will adjust the carrying amount of the properties to fair value through a charge to impairment expense. For the three months ended March 31, 2006 and 2007, we did not incur any impairment charges.

We account for oil and gas exploration and production activities using the successful efforts method under which we capitalize exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense. Otherwise, the costs remain capitalized and are depleted as production occurs. The following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and gas properties as of March 31, 2007 pending determination of whether the wells will be assigned proved reserves. The following table does not include $12.7 million related to exploratory wells in progress for which drilling had not been completed at March 31, 2007:

	Time Elapsed Since Drilling Completed
	0-3 Months		4-6 Months		7-12 Months		> 12 Months		Total
	(in thousands)
Wells for which drilling has been completed	$	19,932	$	2,436	$	7,577	$	18,695	$	48,640

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense was $30.8 million for the three months ended March 31, 2006 compared to $39.1 million for the current year period. Of the increase, $0.9 million is due to the 3% increase in production, excluding the Williston and DJ Basins, and $7.4 million is due to an increased DD&A rate for the three months ended March 31, 2007. During the three months ended March 31, 2006, the weighted average DD&A rate was $2.34 per Mcfe. In the three months ended March 31, 2007, the weighted average depletion rate was $2.89 per Mcfe. The DD&A rate for the three months ended March 31, 2007 excludes production of 654 MMcfe associated with our properties held for sale in the Williston and DJ Basins. Under successful efforts accounting, depletion expense is separately computed for each producing area based on geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average depletion rate for current production. Our cost of finding oil and gas reserves in certain areas yielded an overall higher depletion rate for the three months of 2007 compared to the prior year period. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

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General and Administrative Expense.General and administrative expense, excluding non-cash stock-based compensation, increased from $6.9 million in the three months ended March 31, 2006 to $7.3 million in the current year period. This increase was primarily due to increased personnel required for our capital program and production levels. As of March 31, 2007, we had 142 full time employees in our corporate office compared to 129 as of March 31, 2006. On a per unit of production basis, however, general and administrative expense decreased from $0.52 per Mcfe in the first three months of 2006 to $0.51 per Mcfe in the current year period due to increased production.

Non-cash charges for stock-based compensation were $1.6 million in the first three months of 2006 compared to $1.9 million in the current year period. The increase in charges for non-cash compensation is primarily due to the additional equity awards that were granted during the later part of 2006 and during the three months ended March 31, 2007.

Interest Expense.Interest expense increased to $2.9 million in the three months ended March 31, 2007 from $1.5 million in the prior year period. The increase is due to higher debt levels in the first quarter of 2007 to fund exploration and development activities. The weighted average outstanding balance under our credit facility for the three months ended March 31, 2006 was $87.7 million compared to $189.4 million in the quarter ended March 31, 2007.

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. Until the third quarter of 2006, we had not capitalized any interest expense. The weighted average interest rate used to capitalize interest for the current quarter was 7.1%, including interest and commitment fees paid on the unused portion of our credit facility, amortization of deferred financing costs and the effects of interest rate hedges. We capitalized interest costs of $0.4 million for the three months ended March 31, 2007.

Income Tax Expense.Our effective tax rate was 37.2% and 38.5% in the three months ended March 31, 2006 and 2007, respectively. For both the 2006 and 2007 periods, our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense under APB 25 and SFAS No. 123R that is not deductible for income tax purposes. All of our income tax liabilities and benefits are deferred. Due to the tax deductions being created by our drilling activities, we expect that we will incur cash income tax liabilities relating to the alternative minimum tax in the next year.

Net Income.We generated net income of $14.2 million in the three months ended March 31, 2007 compared to a net income of $22.1 million in the prior year period. The reasons for the decrease in net income include the decrease in natural gas prices, giving effect to hedges, increases in operating expenses and an increase in interest expense, as previously discussed in this section. Offsetting these was an increase in other operating revenues during the first quarter of 2007 as compared to the prior year period.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been from sales and other issuances of securities, net cash provided by operating activities, bank credit facilities, proceeds from joint exploration agreements and sales of interests in properties. For 2007, we expect to receive proceeds from our properties held for sale in excess of the carrying value of $77.2 million, which will be available for our capital needs. Our primary use of capital has been for the exploration, development, and acquisition of natural gas and oil properties. As we pursue reserve and production growth, we continually monitor the capital resources available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash, we may need to obtain additional equity or debt financing.

At March 31, 2007, our balance sheet reflected a cash balance of $25.3 million with a balance of $200.0 million outstanding on our credit facility.

Cash Flow from Operating Activities

Net cash provided by operating activities was $66.1 million and $58.9 million for the three months ended March 31, 2006 and 2007, respectively. The decrease in net cash provided by operating activities was due to decreased production revenues and increased expenses, as discussed above in “Results of Operations.” Changes in current assets and liabilities decreased cash flow from operations by $1.9 million and $8.1 million for the three months ended March 31, 2006 and 2007, respectively.

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Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas and oil produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

To mitigate some of the potential negative impact on cash flow caused by changes in natural gas and oil prices and to comply with our credit agreement we have entered into commodity swap and collar contracts to receive fixed prices for a portion of our natural gas and oil production. At March 31, 2007, we had in place natural gas and crude oil collars and swaps covering portions of our 2007 and 2008 production. Our natural gas and oil derivative financial instruments have been designated as cash flow hedges in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities,and are classified as either current or noncurrent assets in our Condensed Consolidated Balance Sheets based on scheduled delivery of the underlying production.

As of May 1, 2007, we had hedges in place for approximately 31,810,000 MMbtu and 23,455,000 MMbtu of natural gas production for the remaining three quarters of 2007 and for the year 2008, respectively, and approximately 220 thousand barrels (“MBbls”) and 183 MBbls of oil production for the remaining three quarters of 2007 and for the year 2008, respectively.

The table below summarizes the deliveries associated with the swap and collar contracts as of May 1, 2007:

Product	Deliveries Per Day	Quantity Type	Weighted Average Floor Pricing		Weighted Average Ceiling Pricing		Weighted Average Fixed Price		Index Price (1)	Contract Period
Cashless Collars:
Natural gas	64,000	MMBtu	$	6.07	$	9.61		n/a	CIGRM	1/1/2007 —12/31/2007
Oil	800	Bbls	$	55.00	$	79.85		n/a	WTI	1/1/2007 —12/31/2007
Natural gas	35,000	MMBtu	$	6.50	$	10.00		n/a	CIGRM	1/1/2008 —12/31/2008
Oil	500	Bbls	$	70.00	$	80.15		n/a	WTI	1/1/2008 —12/31/2008
Swap Contracts:
Natural gas	5,000	MMBtu		n/a		n/a	$	5.21	CIGRM	2/1/2007 —10/31/2007
Natural gas	45,000	MMBtu		n/a		n/a	$	5.47	CIGRM	4/1/2007 —10/31/2007
Natural gas	5,000	MMBtu		n/a		n/a	$	5.14	CIGRM	5/1/2007 — 5/31/2007
Natural gas	55,000	MMBtu		n/a		n/a	$	6.90	CIGRM	11/1/2007 —3/31/2008
Natural gas	10,000	MMBtu		n/a		n/a	$	8.00	CIGRM	1/1/2008 — 3/31/2008
Natural gas	10,000	MMBtu		n/a		n/a	$	6.75	CIGRM	1/1/2008 —12/31/2008
Natural gas	5,000	MMBtu		n/a		n/a	$	6.30	CIGRM	4/1/2008 —10/31/2008

(1) CIGRM refers to Colorado Interstate Gas Rocky Mountains price as quoted in Platt’s Inside FERC on the first business day of each month. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

By removing the price volatility from a portion of our natural gas and oil production for 2007 and 2008, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers.

Based on hedging contracts outstanding on March 31, 2007, our cash flow hedge positions from natural gas and oil derivatives had an estimated net pre-tax asset of $32.2 million recorded as both current and non-current assets, as appropriate. We will reclassify this amount to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of March 31, 2007 to be reclassified from accumulated other comprehensive income to net income in the next 12 months would be $16.0 million. We anticipate that all original forecasted transactions will occur by the end of the originally specified time periods.

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Capital Expenditures

Our capital expenditures were $103.1 million and $80.9 million for the three months ended March 31, 2006 and 2007, respectively. The total for the three month period of 2006 consists of $11.1 million for acquisitions of properties, $88.1 million for drilling, development, exploration and exploitation of natural gas and oil properties (including related gathering and facilities, but excluding exploratory dry holes, which are expensed under successful efforts accounting as exploration expense), $3.4 million related to geologic and geophysical costs and exploratory dry holes and abandonment costs and $0.5 million for furniture, fixtures and equipment. Total capital expenditures for the three months ended March 31, 2007 consist of $11.7 million for acquisitions of properties, $62.9 million for drilling, development, exploration and exploitation of natural gas and oil properties, $5.0 million for geologic and geophysical costs and exploratory dry holes and abandonment costs and $1.3 million for furniture, fixtures and equipment.

Unevaluated properties increased $16.3 million to $237.5 million at March 31, 2007, including a decrease of $1.2 million related to unevaluated properties in the Williston and DJ Basins that are currently classified as held for sale at March 31, 2007, from $221.2 million at December 31, 2006. The increase is principally from increases in leasehold acquisitions, and wells in progress as of March 31, 2007.

Excluding material acquisitions, our current capital budget for 2007 is $425.0 to $450.0 million, of which we plan to spend approximately $315.0 to $325.0 million for development drilling and facilities, $78.0 to $88.0 million on exploration drilling, $20.0 to $25.0 million for leasehold acquisitions, $8.0 million on geologic and geophysical costs, and $4.0 million for equipment and other costs. While we may reallocate capital among our areas of activity, our approved budget provides that we will spend $190.0 to $195.0 million in the Piceance, $165.0 to $175.0 million in the Uinta, $30.0 to $35.0 million in the Powder River, $20.0 million in the Wind River, and $20.0 to $25.0 million in other areas. Based upon our current natural gas and oil price expectations and our hedge position for 2007, we anticipate that our operating cash flow, expected proceeds from property sales, and available borrowing capacity under our credit facility will be sufficient to fund our planned capital expenditures and other cash requirements for 2007. However, future cash flows are subject to a number of variables, including the level of natural gas and oil production and prices. There can be no assurance that operations and other capital resources will provide sufficient amounts to maintain planned levels of capital expenditures.

The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If natural gas and oil prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a portion of these planned 2007 capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and crews.

Financing Activities

Credit Facility.Our current bank line of credit has a face value of $400.0 million. The credit facility matures on March 17, 2011 and, as of March 29, 2007, had a borrowing base of $310.0 million. On March 30, 2007, the borrowing base increased to $365.0 million, subject to reduction to $340.0 million upon the sale of our Williston Basin properties. Future borrowing bases will be computed based on proved natural gas and oil reserves. The credit facility bears interest, based on the borrowing base usage, at the applicable LIBOR plus applicable margins ranging from 1.0% to 1.75%, or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 0.25%. We pay commitment fees ranging from 0.25% to 0.375% of the unused borrowing base. This facility is secured by our 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. At March 31, 2007, the outstanding balance under our Amended Credit Facility was $200.0 million.

The amended credit facility contains certain financial covenants. As of March 31, 2007, we were in compliance with all of the financial covenants under the facility.

In December 2006, we entered into two interest rate derivative contracts to manage our exposure to changes in interest rates. The first contract was a floating-to-fixed interest rate swap for a notional amount of $10.0 million and the second was a floating-to-fixed interest rate collar for a notional amount of $10.0 million, both to terminate on December 12, 2009. Under the swap, we will

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make payments to (or receive payments from) the contract counterparty when the variable rate of one-month LIBOR falls below (or exceeds) the fixed rate of 4.70%. Under the collar, we will make payments to (or receive payments from) the contract counterparty when the variable rate falls below the floor rate of 4.50% or exceeds the ceiling rate of 4.95%. Our interest rate derivative instruments have been designated as cash flow hedges in accordance with SFAS No. 133. The derivatives were structured to mirror the critical terms of the hedged debt instruments; therefore, no ineffectiveness has been recorded in earnings.

As of March 31, 2007, we had received an insignificant amount in settlement payments, which were deducted from interest expense in the current quarter. We anticipate that all originally forecasted transactions will occur by the end of the originally specified time periods, and based on current projected interest rates, the net amount of existing unrealized after-tax income as of March 31, 2007 to be reclassified from accumulated other comprehensive income to net income in the next 12 months would be approximately $0.02 million. At March 31, 2007, the estimated fair value of the interest rate derivatives was a net asset of $0.06 million.

Contractual Obligations.A summary of our contractual obligations as of and subsequent to March 31, 2007 is provided in the following table (in thousands).

	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
Long-term debt (1)	$	—	$	—	$	—	$	200,000	$	—	$	—	$	200,000
Other commitments for developing oil and gas properties		19,906		2,029		—		—		—		—		21,935
Office and office equipment leases and other		15,448		15,366		1,553		1,307		337		—		34,011
Firm transportation and processing agreements		8,108		15,609		17,456		19,248		43,880		78,315		182,616
Asset Retirement Obligations (2)(3)		350		8,421		1,075		854		1,816		21,188		33,704
Total	$	43,812	$	41,425	$	20,084	$	221,409	$	46,033	$	99,503	$	472,266

(1) Amount does not include future commitment fees, interest expense, or other fees on our credit facility because the 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) 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, 2006 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(3) Amount includes Asset Retirement Obligations of $3.5 million associated with Williston and DJ Basins, which are currently classified as held for sale.

We have entered into contracts that provide firm transportation capacity and processing rights on pipeline systems. The remaining terms on these contracts range from 1 to 11 years and require us to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by us.

In addition to the commitments above, we have commitments for the purchase of facilities equipment as of and subsequent to March 31, 2007 for a total of $13.9 million.

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2006 and the notes to the 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.

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Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our price swap and collar contracts in place for the three months ended March 31, 2007, our income before income taxes, including hedge settlements, 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 change in crude oil prices.

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

As of May 1, 2007, we had hedges in place for 31,810,000 MMbtu and 23,455,000 MMbtu of natural gas production for the remaining three quarters of 2007 and for the year 2008, respectively, and approximately 220 thousand barrels (“MBbls”) and 183 MBbls of oil production for the remaining three quarters of 2007 and for the year 2008, respectively. These hedges are summarized in the table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities.” Based on the pricing and contracts outstanding as of March 31, 2007, the estimated fair value of our hedge positions was an asset of $32.2 million due to us from the counterparties.

Commodity Hedges

Commodity Swaps

Through a price swap, we have fixed the price we will receive on a portion of our natural gas production in the remaining quarters of 2007 and 2008. The weighted average price we will receive for the remaining three quarters of 2007 is $5.78 per MMBtu for a CIG price and $6.88 per MMBtu for 2008. The table presented under Item 2, “ Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities,” provides the deliveries associated with this arrangement as of May 1, 2007.

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

Commodity Collars

Through price collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas production in 2007 and 2008. The weighted average minimum, or floor, price we will receive for the remaining three quarters of 2007 is $6.07 per MMBtu for a CIG price and $6.50 per MMBtu for 2008. The weighted average maximum, or ceiling, price we will receive for the remaining three quarters of 2007 is $9.61 per MMBtu for a CIG price and $10.00 per MMBtu for 2008. We have also fixed the minimum price we will receive on a portion of our oil production in the remaining quarters of 2007 and 2008, when the collars are settled, based on a weighted average floor price of $55.00 and $70.00 per Bbl for a WTI price, respectively, and a weighted average maximum price of $79.85 and $80.15 per Bbl for a WTI price, respectively. The price collars allow us to share in upward price movements up to the ceiling prices referenced in the contracts. The table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities,” provides the deliveries and floor and ceiling prices associated with these various arrangements as of May 1, 2007.

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

Interest Rate Risks

At March 31, 2007, we had debt outstanding of $200.0 million, which bears interest at floating rates in accordance with our revolving credit facility. The average annual interest rate incurred on this debt for the three months ended March 31, 2007 was 6.2%. A one hundred basis point (1.0%) increase in each of the average LIBOR rate and federal funds rate for the three months ended March 31, 2007 would have resulted in an estimated $0.5 million increase in interest expense assuming a similar average debt level to the three months ended March 31, 2007.

Interest Rate Hedges

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

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the first fiscal quarter of 2007 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 from the risk factors previously disclosed in our “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2006, referred to as our 2006 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 2006 Annual Report. These risks and uncertainties are not the only ones facing us, and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our company.

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

The following table contains information about our acquisitions of equity securities during the three months ended March 31, 2007.

Issuer Purchases of Equity Securities

Period	Total Number of Shares (1)	Weighted Average Price Paid Per Share		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
January 1 – 31, 2007	—		—	—	—
February 1 – 28, 2007	103,873	$	30.65	—	—
March 1 – 31, 2007	101	$	29.27	—	—
Total	103,974	$	30.65	—	—

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

Item 3. Defaults Upon Senior Securities.

Not applicable.

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

Not applicable.

Item 5. Other Information.

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 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]
3.2	Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.5 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]
4.1	Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 3.2 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.2	Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
4.3	Stockholders’ Agreement, dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
4.4	Form of Rights Agreement concerning Shareholder Rights Plan, which includes as Exhibit A thereto the Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, and as Exhibits B thereto the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.5	Form of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, included as Exhibit A to Exhibit 4.4 above.
4.6	Form of Right Certificate, included as Exhibit B to Exhibit 4.4 above.
10.1(a)	Amended and Restated Credit Agreement, dated February 4, 2004, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.1(b)	First Amendment to Amended and Restated Credit Agreement dated as of September 1, 2004 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1(b) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.1(c)	Second Amended and Restated Credit Agreement dated March 17, 2006 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K reporting on event occurring March 17, 2006 filed with the SEC on March 22, 2006.]
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 the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.3(a)*	Form of Indemnification Agreement dated April 15, 2004, between Bill Barrett Corporation and each of the directors and certain executive officers. [Incorporated by reference to Exhibit 10.10(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
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 the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.4*	Amended and Restated 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.12 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

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10.5(a)*	Form of Tranche A Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.5(b)*	Form of Tranche B Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(b)to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.6*	2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to the Company���s Registration Statement on Form S-1 (File No. 333-115445).]
10.7*	Form of Stock Option Agreement for 2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.8	Form of Management Rights Agreement between Bill Barrett Corporation and certain investors. [Incorporated by reference to Exhibit 10.16 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
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 the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.10*	Form of Change in Control Severance Protection Agreement revised as of November 16, 2006 for named executive officers. [Incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.]
10.11*	2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.12*	Revised Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.]
10.13*	Severance Plan. [Incorporated by reference to Exhibit 10.23 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
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 8, 2007	By:	/s/ Fredrick J. Barrett
		Fredrick J. Barrett
		Chairman of the Board of Directors and Chief Executive Officer
		(Principal Executive Officer)
Date: May 8, 2007	By:	/s/ Robert W. Howard
		Robert W. Howard
		Chief Financial Officer
		(Principal Financial Officer)
Date: May 8, 2007	By:	/s/ David R. Macosko
		David R. Macosko
		Vice President - Accounting (Principal Accounting Officer)

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