Bill Barrett (BBG) 10-Q 2005 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2005
	OR
o	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 (State or other jurisdiction of Incorporation or organization)	80-0000545 (IRS Employer Identification No.)
1099 18th Street, Suite 2300 Denver, Colorado (Address of principal executive offices)	80202 (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 þ No o.

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ.

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

There were 43,431,547 shares of $.001 par value common stock outstanding on October 31, 2005.

TABLE OF CONTENTS

Rule 13a-14(a)/15d-14(a) Certification of CEO

Rule 13a-14(a)/15d-14(a) Certification of CFO

Section 1350 Certification of CEO

Section 1350 Certification of CFO

 Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer

 Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer

 Section 1350 Certification of Chief Executive Officer

 Section 1350 Certification of Chief Financial Officer

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

	December 31,			September 30,
	2004			2005
	(in thousands, except share data)
Assets:
Current Assets:
Cash and cash equivalents	$	99,926		$	37,664
Accounts receivable, net of allowance for doubtful accounts of $89 and $144 as of December 31, 2004 and September 30, 2005, respectfully		31,149			41,261
Prepayments and other current assets		4,625			5,372
Deferred income taxes		2,190			23,225
Total current assets		137,890			107,522
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		517,210			697,263
Unevaluated oil and gas properties, excluded from amortization		137,605			175,622
Furniture, equipment and other		4,964			6,839
		659,779			879,724
Accumulated depreciation, depletion, amortization, and impairment		(107,614	)		(204,007	)
Total property and equipment, net		552,165			675,717
Deferred Income Taxes		3,081			8,486
Deferred Financing Costs and Other Assets		3,022			1,996
Total	$	696,158		$	793,721
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	37,392		$	44,915
Amounts payable to oil and gas property owners		5,390			6,506
Production taxes payable		15,437			28,747
Derivative liability and other		3,887			61,016
Total current liabilities		62,106			141,184
Note Payable to Bank		—			43,000
Asset Retirement Obligations		11,806			13,807
Other Noncurrent Liabilities		2,514			18,388
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 43,323,270 and 43,431,118 shares issued at December 31, 2004 and September 30, 2005, respectively, with 283,887 and 92,090 shares subject to restrictions, respectively		43			43
Additional paid-in capital		709,578			712,774
Accumulated deficit		(86,320	)		(85,840	)
Accumulated other comprehensive loss		(3,569	)		(49,635	)
Total stockholders’ equity		619,732			577,342
Total	$	696,158		$	793,721

See notes to consolidated financial statements.

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BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2005			2004			2005
	(in thousands, except share and per share amounts)
Revenues:
Oil and gas production	$	42,431		$	70,471		$	118,873		$	175,118
Other		244			766			2,642			2,474
Total revenues		42,675			71,237			121,515			177,592
Operating Expenses:
Lease operating expense		3,822			5,165			11,009			14,059
Gathering and transportation expense		1,600			3,113			4,091			8,717
Production tax expense		5,219			8,525			14,784			21,554
Exploration expense		6,469			4,152			9,282			6,817
Impairment, dry hole costs and abandonment expense		7,606			646			7,887			44,321
Depreciation, depletion and amortization		17,718			21,982			48,720			60,936
General and administrative		4,441			6,708			15,249			19,741
Total operating expenses		46,875			50,291			111,022			176,145
Operating income (loss)		(4,200	)		20,946			10,493			1,447
Other Income and Expense:
Interest income		103			343			231			1,384
Interest expense		(2,006	)		(734	)		(3,389	)		(1,736	)
Total other income and expense		(1,903	)		(391	)		(3,158	)		(352	)
Income (Loss) before Income Taxes		(6,103	)		20,555			7,335			1,095
Provision for (Benefit from) Income Taxes		(2,163	)		7,258			3,503			615
Net Income (Loss)		(3,940	)		13,297			3,832			480
Less Cumulative Dividends on Preferred Stock		(5,049	)		—			(14,387	)		—
Net Income (Loss) Attributable to Common Stock	$	(8,989	)	$	13,297		$	(10,555	)	$	480
Net Income (Loss) Per Common Share, Basic	$	(6.08	)	$	0.31		$	(7.67	)	$	0.01
Net Income (Loss) Per Common Share, Diluted	$	(6.08	)	$	0.30		$	(7.67	)	$	0.01
Weighted Average Common Shares Outstanding, Basic		1,477,595			43,285,381			1,376,692			43,186,417
Weighted Average Common Shares Outstanding, Diluted		1,477,595			43,782,874			1,376,692			43,628,292

See notes to consolidated financial statements.

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BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE LOSS (UNAUDITED)

													Accumulated
	Convertible						Additional						Other			Total
	Preferred			Common			Paid-In			Accumulated			Comprehensive			Stockholders’			Comprehensive
	Stock			Stock			Capital			Deficit			Loss			Equity			(Loss) Income
	(in thousands)
Balance — December 31, 2003	$	51		$	9		$	251,633		$	(8,966	)	$	(4,401	)	$	238,326
Issuance of Series B convertible preferred stock for cash		7			—			33,723			—			—			33,730			—
Exercise of options		—			—			52			—			—			52			—
Issuance of Series B convertible preferred stock for acquisition of mineral leasehold interests		—			—			322			—			—			322			—
Cancellation of Series A convertible preferred stock		—			—			(500	)		—			—			(500	)		—
Reverse stock split: 1-for-4.658		—			(7	)		7			—			—			—			—
Proceeds from initial public offering (net of underwriters’ discount of $26,445)		—			15			347,290			—			—			347,305			—
Conversion of convertible note payable into common stock		—			—			1,900			—			—			1,900			—
Conversion of issued and outstanding Series A convertible preferred stock into common stock upon initial public offering		(6	)		2			4			—			—			—			—
Conversion of issued and outstanding Series B convertible preferred stock into common stock upon initial public offering		(52	)		24			28			—			—			—			—
Recognition of 7% cumulative dividend on Series B convertible stock in common stock		—			—			35,745			(35,745	)		—			—			—
Recognition of deemed dividends related to the conversion of Series B convertible stock into common stock upon initial public offering		—			—			36,343			(36,343	)		—			—			—
Stock-based compensation		—			—			3,031			—			—			3,031			—
Comprehensive (loss) income:
Net loss		—			—			—			(5,266	)		—			(5,266	)		(5,266	)
Effect of derivative financial instruments, net of tax		—			—			—			—			832			832			832
Total comprehensive loss																			$	(4,434	)
Balance — December 31, 2004	$	0		$	43		$	709,578		$	(86,320	)	$	(3,569	)	$	619,732
Exercise of options		—			—			995			—			—			995			—
Stock-based compensation		—			—			2,221			—			—			2,221			—
Other		—			—			(20	)		—			—			(20	)		—
Comprehensive loss:
Net income		—			—			—			480			—			480			480
Effect of derivative financial instruments, net of tax		—			—			—			—			(46,066	)		(46,066	)		(46,066	)
Total comprehensive loss																			$	(45,586	)
Balance — September 30, 2005	$	0		$	43		$	712,774		$	(85,840	)	$	(49,635	)	$	577,342

See notes to consolidated financial statements.

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BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

	Nine Months Ended
	September 30,
	2004			2005
	(in thousands)
Operating Activities:
Net Income	$	3,832		$	480
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		48,720			60,936
Deferred income taxes		3,503			615
Impairment, dry hole costs and abandonment expense		7,887			44,321
Stock compensation and other non-cash charges		2,672			2,103
Amortization of deferred financing costs		681			882
Gain on disposal of properties		(2,348	)		(2,101	)
Change in current assets and liabilities:
Accounts receivable		(6,281	)		(10,112	)
Prepayments and other current assets		(2,193	)		(653	)
Accounts payable, accrued and other liabilities		(1,084	)		(153	)
Amounts payable to oil and gas property owners		579			1,116
Production taxes payable		9,403			13,310
Net cash provided by operating activities		65,371			110,744
Investing Activities:
Additions to oil and gas properties		(274,828	)		(224,135	)
Additions of furniture, equipment and other		(1,342	)		(1,852	)
Proceeds from sale of properties		7,219			9,036
Net cash used in investing activities		(268,951	)		(216,951	)
Financing Activities:
Proceeds from debt		254,000			66,000
Principal payments on debt		(68,000	)		(23,000	)
Proceeds from sale of common and preferred stock		33,773			995
Offering costs		(1,163	)		—
Deferred financing costs and other		(6,169	)		(50	)
Net cash provided by financing activities		212,441			43,945
Increase (Decrease) in Cash and Cash Equivalents		8,861			(62,262	)
Beginning Cash and Cash Equivalents		16,034			99,926
Ending Cash and Cash Equivalents	$	24,895		$	37,664

See notes to consolidated financial statements.

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BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

September 30, 2005

1. Organization

     Bill Barrett Corporation (the “Company”, “we”, or “us”), a Delaware corporation, is an independent oil and gas company engaged in the acquisition, 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. On December 9, 2004, our Registration Statements on Form S-1 (SEC File Nos. 333-114554, 333-121128 and 333-121142) concerning our initial public offering (“IPO”) were declared effective by the Securities and Exchange Commission (the “SEC”). The offering was completed on December 15, 2004 and the underwriters purchased a total 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 million after deducting underwriting fees and other offering costs.

2. Summary of Significant Accounting Policies

     Basis of Presentation.The accompanying unaudited consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information. Pursuant to the rules and regulations of the SEC, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of September 30, 2005, the results of operations for the nine and three months ended September 30, 2004 and 2005, and cash flows for the nine months ended September 30, 2004 and 2005. Operating results for the nine and three months ended September 30, 2005 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 and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, these 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, 2004 previously filed with the SEC.

     In the course of preparing the 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. Generally, if an exploratory well does not find proved reserves within one year following completion of drilling, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the 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 exploration and development projects that require greater than six months to be readied for their intended use. To date, the Company has not capitalized any interest expense.

     Other exploration costs, including personnel costs, 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

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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. Maintenance and repairs are charged to expense and renewals and betterments are capitalized to the appropriate property and equipment accounts.

     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 consists primarily of tubular goods and well equipment used in future drilling operations or repair operations and is 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 (in thousands):

	As of			As of
	December 31, 2004			September 30, 2005
Proved properties	$	258,387		$	270,874
Wells and related equipment and facilities		216,335			361,920
Support equipment and facilities		38,890			57,532
Materials and supplies		3,598			6,937
Total proved oil and gas properties		517,210			697,263
Accumulated depreciation, depletion, amortization and impairment		(105,633	)		(200,883	)
Total proved oil and gas properties, net	$	411,577		$	496,379
Unevaluated properties	$	97,099		$	97,824
Wells and equipment in progress		40,506			77,798
Total unevaluated oil and gas properties, excluded from amortization	$	137,605		$	175,622

     The following table reflects the net changes in capitalized exploratory well costs for the nine months ended September 30, 2005 (in thousands). As of September 30, 2005, the Company does not have any exploratory well costs that have been capitalized for more than one year.

Beginning of period	$	19,940
Additions to capitalized exploratory well costs pending the determination of proved reserves		142,422
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(94,932	)
Exploratory well costs charged to impairment, dry hole costs and abandonment expense		(6,812	)
End of period	$	60,618

     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, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

     During the nine months ended September 30, 2005, the Company recognized non-cash impairment charges of $36.3 million related to its proved oil and gas properties in the Wind River Basin, all of which was recorded in the second quarter of 2005. This was primarily a result of production from existing and recently drilled wells in the Cooper Reservoir field declining more rapidly than anticipated due to interference caused by infill drilling. Additionally, in the Talon field, production from exploratory wells was at a rate that did not justify the capital investment in those wells. The carrying amount of these properties was adjusted to fair value, which was determined based upon the present value of future cash flows, net of operating and development costs, discounted at various rates consistent with current market conditions at which similar types of properties are being traded.

     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

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into consideration in the calculation of DD&A are estimated future dismantlement, restoration and abandonment costs, net of estimated salvage values.

     Stock-Based Compensation.In December 2004, the Financial Accounting Standards Board (“FASB”) issued 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. We early adopted the provisions of the new standard effective October 1, 2004. Prior to the adoption of SFAS No. 123R, we used the intrinsic value method in accordance with APB Opinion No. 25 and the disclosure provisions of SFAS No. 123.

     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 adopted SFAS No. 123R using the prospective transition method. Under the prospective transition method, we continue to account for awards granted prior to becoming a public company using the minimum value method described under APB Opinion No. 25. Accordingly, zero compensation expense was recorded upon adoption of SFAS No. 123R for those awards. Additionally, the calculated fair value of those awards using the minimum value method is not comparable to those options granted subsequent to April 16, 2004, for which a fair-value-based method was used.

     For awards granted after we were a public company (those granted subsequent to April 16, 2004), we adopted SFAS No. 123R using the modified prospective application effective October 1, 2004, whereby as of that date we began applying the provisions of SFAS No. 123R to new awards and to awards modified, repurchased, or cancelled on or after October 1, 2004. For awards granted after April 16, 2004 and before October 1, 2004, we recognized share-based employee compensation cost (as deferred compensation) based on the historical grant-date fair value as computed under SFAS No. 123 on October 1, 2004 for the portion of awards previously granted and for which the requisite service had not yet been rendered.

     During the nine months ended September 30, 2005, the Company granted 251,200 options to purchase shares of common stock with a weighted average exercise price of $31.78 per share and 5,352 nonvested equity shares of common stock. For the three months ended September 30, 2005, the Company granted 81,700 options to purchase shares of common stock with a weighted average exercise price of $35.09 per share. Included within general and administrative expense is non-cash stock based compensation related to option and nonvested equity share awards of $2.6 million and $2.2 million for the nine months ended September 30, 2004 and 2005, respectively, and $0.3 million and $0.7 million for the three months ended September 30, 2004 and 2005, respectively.

     Reclassifications.The Company reclassified $9.3 million related to geologic, geophysical and other exploration costs from cash used in investing activities to cash used in operating activities in the statements of cash flows for the nine months ended September 30, 2004 to conform to the current year presentation.

     The Company reclassified $7.6 million and $7.9 million from exploration expense to impairment, dry hole costs and abandonment expense in the statements of operations for the three and nine months ended September 30, 2004, respectively, to conform to the current year presentation.

     New Accounting Pronouncements.In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47,Accounting for Conditional Asset Retirement Obligations. This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143,Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of a company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company does not believe that its financial position, results of operations or cash flows will be impacted by this Interpretation.

     On April 4, 2005, the FASB issued FASB Staff Position (“FSP”) FAS No. 19-1Accounting for Suspended Well Costs. This staff position amends SFAS No. 19 and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if (1) a sufficient quantity of reserves

9

are discovered in the well to justify its completion as a producing well and (2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires the annual disclosure of (1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, (2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and (3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The guidance in this FSP is required to be applied to the first reporting period beginning after April 4, 2005 on a prospective basis to existing and newly capitalized exploratory well costs. The Company provided the disclosure requirements of this FSP in its Annual Report on Form 10-K for the year ended December 31, 2004 and will continue to provide the disclosures required by the FSP in future filings with the SEC.

     In June 2005, the FASB issued SFAS No. 154,Accounting Changes and Error Corrections, which replaces APB Opinion No. 20,Accounting Changes, and SFAS No. 3,Reporting Accounting Changes in Interim Financial Statements. Statement 154 changes the requirements for the accounting and reporting of a change in accounting principle. APB Opinion No. 20 previously required that most voluntary changes in an accounting principle be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. SFAS No. 154 now requires retrospective application of changes in an accounting principle to prior period financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The Statement is effective for fiscal years beginning after December 15, 2005. We do not expect the adoption of this statement will have a material impact on our financial statements.

     On August 31, 2005, the FASB issued FSP FAS No. 123(R)-1,Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement 123(R). This guidance applies to equity shares, as well as stock options, and requires that a freestanding financial instrument issued to an employee in exchange for past or future employee services that is subject to SFAS No. 123(R) shall continue to be subject to the recognition and measurement provisions of SFAS No. 123(R) throughout the life of the instrument, unless its terms are modified when the holder is no longer an employee. The Company adopted FSP FAS No. 123(R)-1 during the quarter ended September 30, 2005, and it did not have an impact on our financial statements.

     On October 18, 2005, the FASB issued FSP FAS No. 123(R)-2,Practical Accommodation to the Application of Grant Date as Defined in SFAS No. 123(R), which provides a reasonable approach in determining the grant date of an equity award. The Position clarifies that a mutual understanding of the grant terms shall be presumed to exist at the date the award is approved if (1) the grantee is not able to negotiate the terms of the award and (2) the terms of the grant are communicated to the grantee within a reasonable period of time. FSP FAS No. 123(R)-2 is effective for our Company as of the fourth quarter of 2005. We have evaluated the provisions of FSP FAS No. 123(R)-2 and do not believe that its adoption will have an impact on our financial statements.

     In October 2005, the FASB issued FSP FAS No. 13-1,Accounting for Rental Costs Incurred during a Construction Period, which is effective for reporting periods beginning after December 15, 2005. This Position requires that rental costs associated with ground or building operating leases that are incurred during a construction period be recognized as rental expense. We do not expect the adoption of FSP No. 13-1 to have an impact on our financial statements.

3. Per Share Data and Earnings Per Share

     In connection with our IPO in December 2004, a common stock reverse split of 1-for-4.658 was effected. All share and per share amounts for periods prior to December 2004 reflect the reverse split.

     Basic net income per common share of stock 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.

     Net income attributable to common stock is calculated by reducing net income by dividends earned on preferred securities. For the three and nine months ended September 30, 2004, Series B preferred dividends, whether or not declared or paid, were considered earned for purposes of these calculations. The Series A and Series B preferred stock and a convertible note that subsequently converted into Series A preferred stock were not included in the computation of earnings per share for the three and nine months ended September 30, 2004 because their inclusion would have been anti-dilutive.

10

     The Emerging Issues Task Force (EITF) has issued EITF Issue No. 03-6,Participating Securities and the Two-Class Method under FASB Statement No. 128“Earnings Per Share”(“EITF 03-6”). We adopted EITF 03-6 as of January 1, 2004. EITF 03-6 provides guidance for the computation of earnings per share using the two-class method for enterprises with participating securities or multiple classes of common stock as required by SFAS No. 128. The two-class method allocates undistributed earnings to each class of common stock and participating securities for the purpose of computing basic earnings per share. However, upon completion of our IPO on December 15, 2004, all outstanding preferred securities were converted into common stock and, thus, we were not required to apply the two-class method subsequent to that date.

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

	Three months ended September 30,					Nine months ended September 30,
	2004			2005		2004			2005
Net income (loss)	$	(3,940	)	$	13,297	$	3,832		$	480
Less cumulative dividends on preferred stock		(5,049	)		n/a		(14,387	)		n/a
Net income (loss) to be allocated		(8,989	)		13,297		(10,555	)		480
Less allocation of undistributed earnings to participating preferred stock		—			n/a		—			n/a
Net income (loss) attributable to common stock		(8,989	)		13,297		(10,555	)		480
Adjustments to net income for dilution		—			—		—			—
Net income (loss) adjusted for the effect of dilution	$	(8,989	)	$	13,297	$	(10,555	)	$	480
Basic weighted-average common shares outstanding in period		1,478			43,285		1,377			43,186
Add dilutive effects of stock options and nonvested equity shares of common stock		—			498		—			442
Diluted weighted-average common shares outstanding in period		1,478			43,783		1,377			43,628
Basic income (loss) per common share	$	(6.08	)	$	0.31	$	(7.67	)	$	0.01
Diluted income (loss) per common share	$	(6.08	)	$	0.30	$	(7.67	)	$	0.01

4. Supplemental Disclosures of Cash Flow Information:

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

	Nine Months Ended September 30,
	2004			2005
Cash paid for interest	$	2,313		$	927
Supplemental disclosures of noncash investing and financing activities:
Preferred stock issued for payment of oil and gas properties		322			—
Preferred stock returned in settlement to terminate an exploration agreement		(500	)		—
Changes in current assets and liabilities that are reflected in investing activities		(5,438	)		7,706
Net change in asset retirement obligations		7,911			1,278

5. Derivative Instruments and Hedging Activities.

     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. The Company accounts for such activities pursuant to SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the Consolidated Balance Sheets as assets or liabilities.

     The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. SFAS No. 133 requires that a company formally document, at the inception of a hedge, the hedging relationship and the entity’s risk management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged, the method that will be used to assess effectiveness and the method that will be used to measure hedge ineffectiveness of derivative instruments that receive hedge accounting treatment.

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     For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive loss until the hedged item is recognized in earnings. Hedge effectiveness is assessed quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings.

     The Company may utilize derivative financial instruments which have not been designated as hedges under SFAS No. 133 even though they protect the Company from changes in commodity prices. These instruments are marked to market with the resulting changes in fair value recorded in earnings.

     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. Our natural gas and oil derivative financial instruments have been designated as cash flow hedges in accordance with SFAS No. 133.

     The Company was a party to various swap and collar contracts for natural gas based on Northwest Pipeline Rocky Mountains (“NORRM”) and Colorado Interstate Gas Rocky Mountains (“CIGRM”) indexes during the nine months ended September 30, 2004 and 2005. As a result, the Company recognized a reduction of natural gas production revenues related to these contracts of $2.7 million and $3.8 million for the quarters ended September 30, 2004 and 2005, respectively, and $7.5 million and $6.0 million for the nine months ended September 30, 2004 and 2005, respectively. The Company was a party to various swap and collar contracts for oil based on a West Texas Intermediate (“WTI”) index recognizing a reduction to oil production revenues related to these contracts of $1.3 million in the three months ended September 30, 2005 and $2.6 million in the nine months ended September 30, 2005. There were no swap or collar contract settlements for oil during the nine months ended September 30, 2004. 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 three and nine months ended September 30, 2004 and 2005.

     As of October 31, 2005, we had the following commodity swap contracts in place to hedge cash flow and reduce the impact of natural gas and oil price fluctuations:

	Average
	Volume		Quantity	Fixed		Index	Contract
Product	Per Day		Type	Price		Price(1)	Period
Natural gas		10,000	MMBtu	$	5.05	NORRM	1/1/2005-12/31/2005
Natural gas		10,000	MMBtu		5.27	NORRM	1/1/2005-12/31/2005
Oil		100	Bbls		32.96	WTI	1/1/2005-12/31/2005
Oil		100	Bbls		34.05	WTI	1/1/2005-12/31/2005
Oil		100	Bbls		36.12	WTI	1/1/2005-12/31/2005
Oil		100	Bbls		36.00	WTI	1/1/2005-12/31/2005

(1) NORRM refers to Northwest Pipeline Rocky Mountains price and 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.

     As of October 31, 2005, we had the following cashless collars (purchased put options and written call options) in order to hedge a portion of our 2005, 2006, and 2007 natural gas and oil production. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production.

	Average
	Volume		Quantity	Floor-Ceiling		Index	Contract
Product	Per Day		Type	Pricing		Price	Period
Natural gas		10,000	MMBtu	$	4.75-7.00	NORRM	1/1/2005-12/31/2005
Natural gas		5,000	MMBtu		4.75-6.75	NORRM	1/1/2005-12/31/2005
Natural gas		10,000	MMBtu		4.75-7.10	NORRM	1/1/2005-12/31/2005
Natural gas		5,000	MMBtu		5.00-6.46	CIGRM	4/1/2005-10/31/2005
Natural gas		5,000	MMBtu		5.25-10.60	CIGRM	8/1/2005-12/31/2005
Oil		400	Bbls		45.00-55.25	WTI	4/1/2005-12/31/2005
Natural gas		5,000	MMBtu		4.75-6.05	NORRM	1/1/2006-12/31/2006
Natural gas		5,000	MMBtu		4.75-6.18	NORRM	1/1/2006-12/31/2006
Natural gas		15,000	MMBtu		4.75-6.21	NORRM	1/1/2006-12/31/2006

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	Average
	Volume		Quantity	Floor-Ceiling		Index	Contract
Product	Per Day		Type	Pricing		Price	Period
Natural gas		10,000	MMBtu		5.00-8.10	NORRM	1/1/2006-12/31/2006
Natural gas		4,000	MMBtu		5.25-12.05	CIGRM	1/1/2006-12/31/2006
Oil		700	Bbls		42.00-50.20	WTI	1/1/2006-12/31/2006
Oil		50	Bbls		50.00-81.10	WTI	1/1/2006-12/31/2006
Oil		600	Bbls		50.00-78.15	WTI	1/1/2007-12/31/2007
Natural gas		29,000	MMBtu		5.25-10.22	CIGRM	1/1/2007-12/31/2007

     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 liabilities in the Company’s Consolidated Balance Sheets.

     At September 30, 2005, the estimated fair value of contracts designated and qualifying as cash flow hedges under SFAS No. 133 was a liability of $78.8 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 loss as of September 30, 2005 to be reclassified from accumulated other comprehensive loss to net income in the next twelve months would be $37.3 million. Of this amount, $7.6 million pertains to swap contracts, and $29.7 million pertains to collar contracts. In regards to the collar contracts, no amounts will be reclassified if actual prices received fall between the floor and ceiling prices as set forth in the contracts. The Company anticipates that all original forecasted transactions will occur by the end of the originally specified time periods.

6. Asset Retirement Obligations

     The Company follows the provisions of SFAS No. 143,Accounting for Asset Retirement Obligations,in accounting for its obligations associated with the retirement of tangible long-lived assets. The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the accompanying Consolidated Statements of Operations. A reconciliation of the changes in the liability for the nine months ended September 30, 2005 follows (in thousands):

Beginning of period	$	11,806
Liabilities incurred		1,312
Liabilities settled		(50	)
Accretion expense		773
Revisions to estimate		(34	)
End of period	$	13,807

7. Income Taxes

     Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates.

     Income tax expense (benefit) for the three and nine months ended September 30, 2004 and 2005 differs from the amounts that would be provided by applying the U.S. federal income tax rate to income (loss) before income taxes principally due to state income taxes, stock-based compensation not deductible for income tax purposes and other permanent differences.

     At September 30, 2005, the Company’s balance sheet reflected net deferred tax assets of $31.7 million, of which $29.2 million pertains to the tax effects of derivative instruments reflected in other comprehensive loss. The Company has not recognized a valuation allowance against its net deferred tax assets because it believes that it is more likely than not that the net deferred tax assets will be realized on future income tax returns, primarily from the generation of future taxable income.

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8. 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 the 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. At September 30, 2005, 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 Stock shall entitle the holder thereof to 1,000 votes on all matters submitted to a vote of the Company’s stockholders.

     As of September 30, 2005, of the 1,800,548 common shares issued to founding management and employees, 100% were dollar vested and 1,713,198 shares were time vested. The remaining time vesting will occur ratably through January 2006.

     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.

9.Accumulated Other Comprehensive Loss

     The Company follows the provisions of SFAS No. 130,Reporting Comprehensive Income, which establishes standards for reporting comprehensive income. The components of accumulated other comprehensive loss and related tax effects for the nine months ended September 30, 2005 were as follows:

				Tax			Net of
	Gross			Effect			Tax
	(in thousands)
Accumulated other comprehensive loss — December 31, 2004	$	(5,665	)	$	2,096		$	(3,569	)
Change in fair value of hedges		(86,212	)		31,898			(54,314	)
Reclassification adjustment for realized losses on hedges included in net loss		13,091			(4,844	)		8,247
Accumulated other comprehensive loss — September 30, 2005	$	(78,786	)	$	29,151		$	(49,635	)

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10.Commitments and Contingencies

     During the three months ended September 30, 2005, the Company entered into a non-cancelable operating lease for additional office space. The future minimum annual payments under this lease is as follows (in thousands):

Year 1	$	150
Year 2		417
Year 3		497
Year 4		504
Year 5		522
Thereafter		265
Total	$	2,355

     There were no other material changes to our commitments and contingencies since December 31, 2004.

11. Subsequent Events

     On October 17, 2005, the Company signed a letter of intent with an industry party to sell a 40% interest in approximately 40,000 net undeveloped acres within our Red Bank Extension in the Williston Basin. The letter of intent provides that the Company will drill two exploratory wells at depths and locations to be mutually determined. This transaction and the drilling commitments are subject to the negotiation of a definitive agreement, which is anticipated to be completed in the fourth quarter of 2005.

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

     The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, as well as those factors discussed below and in our Annual Report onForm 10-K for the year ended December 31, 2004 under the “Cautionary Note Regarding Forward-Looking Statements” section and the “Risk Factors” subsection of the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and in the “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” sections of our prospectus dated August 17, 2005, 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 or around the Gibson Gulch field in the Piceance Basin of Colorado. In December 2004, we completed our 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.

Results of Operations

     The financial information with respect to the nine and three months ended September 30, 2004 and 2005 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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Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2005

	Nine Months Ended
	September 30,				Increase (Decrease)
	2004		2005		Amount			Percent
			($ in thousands)
Operating Results:
Revenues
Oil and gas production revenues	$	118,873	$	175,118	$	56,245			47	%
Other income		2,642		2,474		(168	)		(6	%)
Operating Expenses
Lease operating expense		11,009		14,059		3,050			28	%
Gathering and transportation expense		4,091		8,717		4,626			113	%
Production tax expense		14,784		21,554		6,770			46	%
Exploration expense		9,282		6,817		(2,465	)		(27	%)
Impairment, dry hole costs and abandonment expense		7,887		44,321		36,434		nm*
Depreciation, depletion and amortization		48,720		60,936		12,216			25	%
General and administrative		15,249		19,741		4,492			29	%
Total operating expenses	$	111,022	$	176,145	$	65,123			59	%
Production Data:
Natural gas (MMcf)		21,449		24,813		3,364			16	%
Oil (MBbls)		352		386		34			10	%
Combined volumes (MMcfe)		23,558		27,126		3,568			15	%
Daily combined volumes (Mmcfe/d)		86		99		13			15	%
Average Prices (includes effects of hedges):
Natural gas (per Mcf)	$	4.93	$	6.34	$	1.41			29	%
Oil (per Bbl)		37.06		46.04		8.98			24	%
Combined (per Mcfe)		5.05		6.46		1.41			28	%
Average Costs (per Mcfe):
Lease operating expense	$	0.47	$	0.52	$	0.05			11	%
Gathering and transportation expense		0.17		0.32		0.15			88	%
Production tax expense		0.63		0.79		0.16			25	%
Depreciation, depletion and amortization		2.07		2.25		0.18			9	%
General and administrative		0.65		0.73		0.08			12	%

* Not meaningful.

     Production Revenues.Production revenues increased from $118.9 million for the nine months ended September 30, 2004 to $175.1 million for the current year period due to both an increase in production and increases in natural gas and oil prices. Price increases added approximately $33.4 million of production revenues and production increases from the development of existing properties added approximately $22.8 million of production revenues, after natural production declines so that our new production more than offset natural production declines.

     On a Mcf equivalent basis, total production volumes for the nine months ended September 30, 2005 increased 15% from total production for the prior year period. Additional information concerning production is in the following table.

	Nine Months Ended September 30, 2004						Nine Months Ended September 30, 2005
	Oil		Natural Gas		Total		Oil		Natural Gas		Total
	(MBbls)		(MMcf)		(MMcfe)		(MBbls)		(MMcf)		(MMcfe)
Wind River Basin		90		13,889		14,429		57		10,629		10,970
Uinta Basin		5		3,826		3,856		4		4,625		4,646
Powder River Basin		—		3,402		3,402		—		6,411		6,411
Piceance Basin*		1		186		193		28		3,018		3,185
Williston Basin		234		132		1,536		278		108		1,776
Other		22		14		142		19		22		138
Total		352		21,449		23,558		386		24,813		27,126

* We purchased our interest in the Piceance Basin on September 1, 2004.

     The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields that occurred in late 2004 and throughout 2005. These natural production declines in the Wind River Basin were partially offset as the result of our development activities in the Talon field along with the exploration success of the Bullfrog Federal 14-18 well, which was put on production in late July 2005. The production increase in the Uinta Basin is due to exploration and development activities in both the West Tavaputs and Hill Creek fields. The production increase in the Powder River Basin reflects the success of our development activities. The production increase in the Williston Basin is principally due to continued exploration and development activities on our properties in this basin. The production increase in the Piceance Basin is a result of the acquisition made in September 2004. The 2005 production in the Piceance Basin includes 116 MMcf of a gas balancing settlement pertaining to production in the last quarter of 2004.

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     Hedging Activities.During the nine months ended September 30, 2004, approximately 36% of our natural gas volumes and no oil volumes were hedged, resulting in a reduction in revenues of $7.5 million. During the nine months ended September 30, 2005, approximately 50% of our natural gas volumes and 47% of our oil volumes were hedged, resulting in a reduction in revenues of $8.6 million.

     Lease Operating Expense and Gathering and Transportation Expense.Our lease operating expense increased from $0.47 per Mcfe in the first nine months of 2004 to $0.52 per Mcfe in the current year period, and our gathering and transportation expense increased from $0.17 per Mcfe in the first nine months of 2004 to $0.32 per Mcfe in the current year period. The increase in lease operating expenses is primarily due to workovers of $0.5 million in the Hill Creek field in the Uinta Basin and in the Cave Gulch field in the Wind River Basin, equipment rentals and diesel fuel costs associated with a temporary electrical power supply for new wells in the Powder River Basin of $1.4 million. The increase on a per Mcfe basis is also due to the declining production in our Cave Gulch, Cooper Reservoir and Wallace Creek fields in the Wind River Basin without a corresponding decrease in fixed costs associated with operating these gas wells. The increase in gathering and transportation expense is principally attributable to an increase of $4.3 million for the CBM properties in the Powder River Basin relating to increased third party charges for compressor fuel, processing charges incurred for removal of CO₂ in order to meet pipeline specifications, the relative increase in production in the Powder River Basin, which is a higher gathering cost area as compared to our conventional gas areas, and firm transportation fees we commenced incurring in the first quarter of 2005. 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.

     Production Tax Expense.Production taxes as a percentage of natural gas and oil sales before hedging losses of $7.5 million and $8.6 million remained at 11.7% for the nine months ended September 30, 2004 and 2005, respectively. Production taxes are primarily based on the wellhead values of production and vary across the different areas that we operate. Total production taxes increased as a result of higher production revenues, primarily due to higher prices in the nine months ended September 30, 2005 compared to the prior year period.

     Exploration Expense.Exploration costs decreased from $9.3 million in the first nine months of 2004 to $6.8 million in the current year period. The costs for the nine months ended September 30, 2004 include $1.2 million, $5.8 million and $0.9 million for seismic programs in the DJ Basin, Wind River Basin and Uinta Basins, respectively, along with $1.4 million for delay rentals and other costs. The costs for the nine months ended September 30, 2005 include $5.7 million for seismic programs, principally in the Uinta, Wind River and Big Horn Basins, and Montana Overthrust, and $1.1 million for delay rentals and other costs.

     Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense increased from $7.9 million during the first nine months of 2004 to $44.3 million during the current year period. For the nine months ended September 30, 2004 dry hole costs were $7.5 million for dry holes primarily in the Wind River Basin, abandonments were $0.4 million, and impairment expense was zero. For the nine months ended September 30, 2005 dry hole costs were $6.8 million for dry holes in the Wind River, Green River, and Uinta Basins, abandonments were $1.2 million, and impairment expense was $36.3 million. The impairment expense is the result of a $29.5 million impairment charge in the Cooper Reservoir field and $6.8 million impairment charge in the Talon field, both of which are located in the Wind River Basin, during that quarter. During the quarter ended June 30, 2005, production from existing and recently drilled infill wells in the Cooper Reservoir field declined more rapidly than anticipated indicating well interference and limited downspacing opportunities. In the Talon field, production from exploratory wells was at a rate that does not justify the capital investment. Based on our review as of September 30, 2005, there were no additional impairments of proved oil and gas properties.

     Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense was $60.9 million for the nine months ended September 30, 2005 compared to $48.7 million for the prior year period. Of the increase, $7.4 million is due to the 15% increase in production and $4.8 million is due to an increased depletion rate for 2005 production. During the nine months ended September 30, 2004, the weighted average depletion rate was $2.07 per Mcfe. In the nine months ended September 30, 2005, the weighted average depletion rate was $2.25 per Mcfe. Under successful efforts accounting, depletion expense is separately computed for each producing area. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a depletion rate for current production. The Company’s cost of finding oil and gas reserves in certain areas yielded an overall higher depletion rate for the first nine months of 2005 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 increased $4.5 million from $15.2 million in the nine months ended September 30, 2004 to $19.7 million in the current year period. This increase was primarily due to increased personnel required for our capital program and production levels. As of September 30, 2005, we had 125 full time employees in our corporate office compared to 94 as of September 30, 2004. Additionally, the Company filed a registration statement in August 2005 in an underwritten offering covering shares sold by selling stockholders. No shares were offered or sold by the Company. As a result, the Company incurred an additional $0.4 million in costs associated with the offering during the nine months ended September 30, 2005. The Company also incurred $0.2 million related to the termination of the accounting out-sourcing arrangement with a third party service provider as of August 1, 2005.

     General and administrative expense includes non-cash charges for stock-based compensation, including $2.6 million in the first nine months of 2004 and $2.2 million in the current year period. The decrease in charges for non-cash compensation was due to a stock-based compensation charge related to the dollar vesting of common stock to founding management in January and May of 2004. On a per unit production basis, general and administrative expense increased from $0.65 per Mcfe in the first nine months of 2004 to $0.73 per Mcfe in the current year period. Our capital budget relative to our production levels is high and requires an appropriate number of personnel and related costs to prudently manage our capital expenditure program. Until our capital expenditure program significantly increases our production levels, we expect general and administrative expense per unit of production to remain at current levels.

     Interest Income.Interest income, including amortization of deferred financing costs, increased $1.2 million to $1.4 million during the nine months ended September 30, 2005 from $0.2 million during the prior year period. This increase is a result of interest earned on an average cash and short-term investment balance of $62.7 million for the nine months ended September 30, 2005 compared to an average balance of $22.4 million for the prior year period. The increased investment balance resulted primarily from the receipt of the net proceeds from our initial public offering in December 2004.

     Interest Expense.Interest expense decreased $1.7 million to $1.7 million in the nine months ended September 30, 2005 from $3.4 million in the prior year period. The decrease was due to higher debt levels during 2004 to fund acquisitions and development activities and a lack of a need to draw on our credit facility until the third quarter of 2005 due to the availability of the proceeds of our IPO in December 2004. The weighted average outstanding balance under our credit facility was $68.8 million for the nine months ended September 30, 2004 as compared to $6.8 million for the nine months ended September 30, 2005. In addition to borrowings under our credit facility, we borrowed $150 million under a bridge loan on September 1, 2004 to fund the acquisition of our Piceance Basin properties. The bridge loan was repaid in full in December 2004 with proceeds from our IPO and terminated at that time so that it had no outstanding balance as of September 30, 2005.

     Income Tax Expense.Our effective tax rate was 48% and 56% in the nine months ended September 30, 2004 and 2005, respectively. For both the 2004 and 2005 periods, our effective tax rate differs from the statutory rates primarily because the Company recorded stock-based compensation expense under APB 25 and FAS 123R that is not deductible for income tax purposes. All of our income tax provisions and benefits are deferred. Due to the tax deductions being created by our drilling activities, we expect that we will not incur cash tax liabilities for at least the next year.

     Net Income.We generated net income of $0.5 million in the nine months ended September 30, 2005 compared to net income of $3.8 million in the prior year period. The primary reasons for the decrease in results were non-cash impairment charges of $36.3 million during the second quarter of the current year. This increase in impairment, dry hole costs and abandonment expense was offset by an increase in operating income, excluding impairment, dry hole costs and abandonment expense, of $27.3 million, a decrease in other expenses of $2.8 million, and a decrease in income tax expense of $2.9 million.

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2005

	Three Months Ended
	September 30,				Increase (Decrease)
	2004		2005		Amount		Percent
	($ in thousands)
Operating Results:
Revenues
Oil and gas production revenues	$	42,431	$	70,471	$	28,040		66	%
Other income		244		766		522		214	%
Operating Expenses
Lease operating expense		3,822		5,165		1,343		35	%
Gathering and transportation expense		1,600		3,113		1,513		95	%
Production tax expense		5,219		8,525		3,306		63	%

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	Three Months Ended
	September 30,				Increase (Decrease)
	2004		2005		Amount			Percent
	($ in thousands)
Exploration expense		6,469		4,152		(2,317	)		(36	%)
Impairment, dry hole costs and abandonment expense		7,606		646		(6,960	)		(92	%)
Depreciation, depletion and amortization		17,718		21,982		4,264			24	%
General and administrative		4,441		6,708		2,267			51	%
Total operating expenses	$	46,875	$	50,291	$	3,416			7	%
Production Data:
Natural gas (MMcf)		7,389		9,287		1,898			26	%
Oil (MBbls)		124		136		12			10	%
Combined volumes (MMcfe)		8,130		10,101		1,971			24	%
Daily combined volumes (Mmcfe/d)		88		110		22			25	%
Average Prices (includes effects of hedges):
Natural gas (per Mcf)	$	5.04	$	6.85	$	1.81			36	%
Oil (per Bbl)		41.72		50.35		8.63			21	%
Combined (per Mcfe)		5.22		6.98		1.76			34	%
Average Costs (per Mcfe):
Lease operating expense	$	0.47	$	0.51	$	0.04			9	%
Gathering and transportation expense		0.20		0.31		0.11			55	%
Production tax expense		0.64		0.84		0.20			31	%
Depreciation, depletion and amortization		2.18		2.18		0.00			0	%
General and administrative		0.55		0.66		0.12			22	%

     Production Revenues.Production revenues increased from $42.4 million for the third quarter of 2004 to $70.5 million for the current year period due to both an increase in production and increases in natural gas and oil prices. Price increases added approximately $14.4 million of production revenues and production increases from the development of existing properties added approximately $13.6 million of production revenues, after natural production declines so that our new production more than offset natural production declines.

     On a Mcf equivalent basis, total production volumes for the third quarter of 2005 increased 24% from total production for the prior year period. Additional information concerning production is in the following table.

	Three Months Ended September 30, 2004						Three Months Ended September 30, 2005
	Oil		Natural Gas		Total		Oil		Natural Gas		Total
	(MBbls)		(MMcf)		(MMcfe)		(MBbls)		(MMcf)		(MMcfe)
Wind River Basin		33		4,685		4,881		16		4,241		4,337
Uinta Basin		1		1,221		1,228		1		1,609		1,617
Powder River Basin		—		1,250		1,250		—		2,151		2,151
Piceance Basin*		1		186		194		11		1,239		1,302
Williston Basin		82		44		533		102		37		647
Other		7		3		44		6		10		47
Total		124		7,389		8,130		136		9,287		10,101

* We purchased our interest in the Piceance Basin on September 1, 2004.

     The production decrease in the Wind River Basin is due to natural production declines in our Cooper Reservoir and Wallace Creek fields that occurred throughout 2005 which are partially offset by production increases in our Cave Gulch and Talon fields. The production increase in the Cave Gulch field is the result of the Bullfrog Federal 14-18 well exploration success, which was put on production in late July 2005, while the production increase in the Talon field is the result of our development activities. The production increases in the Powder River, Uinta and Williston Basins reflects the success of our development activities. The production increase in the Piceance Basin is a result of the acquisition made in September 2004 and the success of our ongoing development activities.

     Hedging Activities.During the third quarter of 2004, we had approximately 35% of our natural gas volumes and no oil volumes hedged, incurring a reduction in revenues of $2.7 million. During the third quarter of 2005, we hedged approximately 46% of our natural gas volumes and 54% of our oil volumes, resulting in a reduction in revenues of $5.1 million.

     Lease Operating Expense and Gathering and Transportation Expense.Our lease operating expense increased to $0.51 per Mcfe in the third quarter of 2005 as compared to $0.47 per Mcfe in the prior year period, and our gathering and transportation expense

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increased from $0.20 per Mcfe in the third quarter of 2004 to $0.31 per Mcfe in the current year period. The increase in lease operating expense is primarily the result of rental and fuel charges incurred on our CBM wells in the Powder River Basin to supply electrical power until a permanent power supply is in place. The increase in gathering and transportation expense is principally attributable to an increase of $1.5 million for the CBM properties in the Powder River Basin relating to increased third party charges for compressor fuel, processing charges incurred for removal of CO₂ in order to meet pipeline specifications, the relative increase in production in the Powder River Basin, which is a higher gathering cost area as compared to our conventional gas areas, and firm transportation fees we commenced incurring in 2005. 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 on a portion of our production in the Wind River and Powder River Basins.

     Production Tax Expense.Production taxes as a percentage of natural gas and oil sales before hedging losses of $2.7 million and $5.1 million were 11.6% and 11.3% for the three months ended September 30, 2004 and 2005, respectively. Production taxes are primarily based on the wellhead values of production and vary across the different areas that we operate. The decrease in tax rate from the third quarter of 2004 to the current year period is primarily the result of increased production from our Piceance Basin properties in Colorado, which has a lower tax rate than Wyoming, which is where most of our prior year production was located. Total production taxes increased as a result of higher production revenues due to increased production and higher prices in the third quarter of 2005 compared to the prior year period.

     Exploration Expense.Exploration costs decreased from $6.5 million in the third quarter of 2004 to $4.2 million in the current year period. The costs for the third quarter of 2004 include $6.2 million for seismic programs primarily in the Wind River Basin and Uinta Basin and $0.3 million for delay rentals and other costs. The costs for the third quarter of 2005 include $3.8 million for seismic programs, principally in the Uinta and Wind River Basins and Montana Overthrust, and $0.4 million for delay rentals and other costs.

     Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense decreased from $7.6 million during the third quarter of 2004 to $0.6 million during the current year period. For the third quarter of 2004, dry hole costs were $7.4 million, abandonments were $0.2 million, and impairment expense was zero. For the current year period, dry hole costs were $0.4 million for a dry hole in the Wind River Basin, abandonments were $0.2 million, and impairment expense was zero.

     Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense was $22.0 million for the third quarter of 2005 compared to $17.7 million for the prior year period. The increase of $4.3 million is the result of a 24% increase in production in the third quarter of 2005 as compared to the prior year period. During the third quarter of 2004, the weighted average depletion rate was $2.18 per Mcfe compared to $2.18 per Mcfe for the current year period. Under successful efforts accounting, depletion expense is separately computed for each producing area. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a depletion rate for current production. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

     General and Administrative Expense.General and administrative expense increased $2.3 million from $4.4 million in the third quarter of 2004 to $6.7 million in the current year period. The increase was primarily due to increased personnel required for our capital program and production levels. As of September 30, 2005, we had 125 full time employees in our corporate office compared to 94 as of September 30, 2004. Additionally, the Company filed a registration statement in August 2005 in an underwritten offering covering shares sold by selling stockholders. No shares were offered or sold by the Company. As a result, the Company incurred an additional $0.4 million in costs associated with the offering during the three months ended September 30, 2005. The Company also incurred $0.2 million related to the termination of the accounting out-sourcing arrangement with a third party service provider as of August 1, 2005.

     General and administrative expense includes non-cash charges for stock based compensation, including $0.3 million in the third quarter of 2004 and $0.7 million in the current year period. On a per unit produced basis, general and administrative expense increased from $0.55 per Mcfe in the third quarter of 2004 to $0.66 per Mcfe in the current year period. Our capital budget relative to our production levels is high and requires an appropriate number of personnel and related costs to prudently manage our capital expenditure program. Until our capital expenditure program significantly increases our production levels, we expect general and administrative expense per unit of production to remain at current levels.

     Interest Expense.Interest expense, including amortization of deferred financing costs, decreased $1.3 million to $0.7 million in the three months ended September 30, 2005 from $2.0 million in the three months ended September 30, 2004. The decrease was due to higher debt levels during 2004 to fund acquisitions and development activities. The weighted average outstanding balance under our credit facility was $80.9 million for the three months ended September 30, 2004 as compared to $20.5 million for the three months

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ended September 30, 2005. In addition to borrowings under our credit facility, we borrowed $150 million under a bridge loan on September 1, 2004 to fund the acquisition of our Piceance Basin properties. This bridge loan was repaid and terminated in December 2004, and as a result, we had no outstanding indebtedness under this bridge loan during the third quarter of 2005.

     Income Tax Expense.Our effective tax rate was 35% for each of the three months ended September 30, 2004 and 2005. For both the 2004 and 2005 periods, our effective tax rate differs from the statutory rates primarily because the Company recorded stock-based compensation expense under APB 25 and FAS 123R that is not deductible for income tax purposes. All of our income tax provisions are deferred. Due to the tax deductions being created by our drilling activities, we expect that we will not incur cash tax liabilities for at least the next year.

     Net Income.We generated net income of $13.3 million in the three months ended September 30, 2005 compared to a net loss of $3.9 million in the prior year period. The primary reasons for the increase include an increase in total revenues of $28.5 million, a decrease in dry hole costs and abandonments of $7.0 million and a decrease in other expenses of $1.5 million. This was offset by an increase in operating expenses of $10.4 million and an increase in income tax expense of $9.4 million.

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, a bank line of credit and a bridge loan to finance our September 2004 acquisition of properties in the Piceance Basin in Colorado. Our primary use of capital has been for the acquisition, exploration, and development of natural gas and oil properties. As we pursue 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.

Cash Flow from Operating Activities

     Net cash provided by operating activities was $65.4 million and $110.7 million for the nine months ended September 30, 2004 and 2005, respectively. The increases in net cash provided by operating activities were partially due to increased production revenues, partially offset by increased expenses, as discussed above in “Results of Operations”. Changes in current assets and liabilities increased cash flow from operations by $0.4 million for the nine months ended September 30, 2004 and increased cash flow from operations by $3.5 million for the nine months ended September 30, 2005.

     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, we have entered into commodity swap and collar contracts to receive fixed prices for a portion of our natural gas and oil production. At October 31, 2005, we had in place natural gas and crude oil swap contracts and collars covering portions of our 2005, 2006, and 2007 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 liabilities in our Consolidated Balance Sheets based on scheduled delivery of the underlying production.

     The table below provides the volumes associated with the swap contracts as of October 31, 2005.

	Average
	Volume		Quantity	Fixed		Index	Contract
Product	Per Day		Type	Price		Price (1)	Period
Natural gas		10,000	MMBtu	$	5.05	NORRM	1/1/2005-12/31/2005
Natural gas		10,000	MMBtu		5.27	NORRM	1/1/2005-12/31/2005
Oil		100	Bbls		32.96	WTI	1/1/2005-12/31/2005
Oil		100	Bbls		34.05	WTI	1/1/2005-12/31/2005
Oil		100	Bbls		36.12	WTI	1/1/2005-12/31/2005
Oil		100	Bbls		36.00	WTI	1/1/2005-12/31/2005

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     The table below provides the volumes associated with the collar contracts as of October 31, 2005.

	Average
	Volume		Quantity	Floor-Ceiling	Index	Contract
Product	Per Day		Type	Pricing	Price (1)	Period
Natural gas		10,000	MMBtu	$4.75-7.00	NORRM	1/1/2005-12/31/2005
Natural gas		5,000	MMBtu	4.75-6.75	NORRM	1/1/2005-12/31/2005
Natural gas		10,000	MMBtu	4.75-7.10	NORRM	1/1/2005-12/31/2005
Natural gas		5,000	MMBtu	5.00-6.46	CIGRM	4/1/2005-10/31/2005
Natural gas		5,000	MMBtu	5.25-10.60	CIGRM	8/1/2005-12/31/2005
Oil		400	Bbls	45.00-55.25	WTI	4/1/2005-12/31/2005
Natural gas		5,000	MMBtu	4.75-6.05	NORRM	1/1/2006-12/31/2006
Natural gas		5,000	MMBtu	4.75-6.18	NORRM	1/1/2006-12/31/2006
Natural gas		15,000	MMBtu	4.75-6.21	NORRM	1/1/2006-12/31/2006
Natural gas		10,000	MMBtu	5.00-8.10	NORRM	1/1/2006-12/31/2006
Natural gas		4,000	MMBtu	5.25-12.05	CIGRM	1/1/2006-12/31/2006
Oil		700	Bbls	42.00-50.20	WTI	1/1/2006-12/31/2006
Oil		50	Bbls	50.00-81.10	WTI	1/1/2006-12/31/2006
Natural gas		29,000	MMBtu	5.25-10.22	CIGRM	1/1/2007-12/31/2007
Oil		600	Bbls	50.00-78.15	WTI	1/1/2007-12/31/2007

(1) NORRM refers to Northwest Pipeline Rocky Mountains price and CIGRM refers to Colorado Interstate Gas Rocky Mountains price as quoted in Platt’s for Inside FERC on the first business day of each month. WTI refers to the West Texas Intermediate price as quoted on the New York Mercantile Exchange. See Item 3, “Quantitative and Qualitative Disclosure about Market Risk”.

     By removing the price volatility from a portion of our natural gas and oil production for 2005, 2006, and 2007 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 major financial institutions deemed by management as competent and competitive market makers.

     Based on hedging contracts outstanding on September 30, 2005, our cash flow hedge positions from natural gas and oil derivatives had an estimated net pre-tax liability of $78.8 million recorded as both current and non-current liabilities, as appropriate. The Company 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 prices, the net amount of existing unrealized after-tax loss as of September 30, 2005 to be reclassified from accumulated other comprehensive loss to net income (loss) in the next twelve months would be $37.3 million. We anticipate that all original forecasted transactions will occur by the end of the originally specified time periods.

Capital Expenditures

     Our capital expenditures were $282.8 million and $240.4 million for the nine months ended September 30, 2004 and 2005, respectively. The total for the nine month period of 2004 includes $147.3 million for acquisitions of properties, $117.0 million for drilling, development, exploration and exploitation (including related gathering and facilities, but excluding exploratory dry holes) of natural gas and oil properties, $17.2 million related to geologic and geophysical costs and exploratory dry holes, which are expensed under successful efforts accounting as exploration expense and impairment, dry hole costs and abandonment expense, and $1.3 million for furniture, fixtures and equipment. The total capital expenditures for the nine month period of 2005 includes $18.9 million for the acquisition of properties, $204.9 million for drilling, development, exploration and exploitation (including related gathering and facilities, but excluding exploratory dry holes) of natural gas and oil properties, $14.8 million for geologic and geophysical costs and exploratory dry holes, and $1.8 million for furniture, fixtures and equipment.

     Unevaluated properties increased $38.0 million to $175.6 million at September 30, 2005 from $137.6 million at December 31, 2004, principally from increases in uncompleted wells in progress resulting from increased development and exploratory drilling activity during the nine months ended September 30, 2005.

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     Our current capital budget, which is anticipated to change as the Company conducts activities throughout the year, is approximately $317 million for 2005. Through the first nine months of 2005 we had incurred $233.5 million, net of costs recovered of $6.9 million related joint exploration agreements entered into and other property sales. Of the $317 million capital budget, we plan to spend approximately $256 million for development activities and $48 million for exploration activities, with the remaining $13 million allocated to other activities. We are projecting that cash on hand, cash available from operating activities, borrowings from our credit facility, and proceeds from selling down a portion of our interests in certain properties will be sufficient to fund our remaining 2005 capital budget. In addition to our 2005 capital budget, we plan to seek industry partners with whom we expect to enter into joint exploration agreements, which would result in a reduction of approximately 30% to 60% of our working interest in a number of exploration projects principally in Wyoming, Montana, North Dakota, and South Dakota. Proceeds from the joint exploration agreements will be used to accelerate and drill additional exploration wells not reflected in the 2005 capital budget. Through 2005, we received proceeds of $8.9 million for sales of partial interests in four exploratory projects, one each in the DJ Basin and Wind River Basin and two in the Williston Basin.

     The amount and timing of capital expenditures is largely discretionary and within our control. If natural gas and oil prices decline to levels below our acceptable levels, we could choose to defer a portion of these planned 2005 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. Based upon current natural gas and oil price expectations for 2005, we anticipate that our operating cash flow and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for 2005. The Company also believes that it has adequate borrowing capacity, along with anticipated operating cash flows, to fund its operations through 2006. 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 cash in sufficient amounts to maintain planned levels of capital expenditures.

Financing Activities

     Credit Facility.Our current bank line of credit provides a borrowing base of $200 million. This credit facility was entered into on February 4, 2004 and has a maturity of February 4, 2007. The credit facility was amended on September 1, 2004. The credit facility bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate, or LIBOR, plus applicable margins ranging from 1.25% to 3.75% 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 2.25%. We pay commitment fees ranging from 0.375% to 0.50% of the unused borrowing base. The credit facility is secured by natural gas and oil properties representing at least 85% of the value of our proved reserves included in our last reserve report and the pledge of all of the stock of our subsidiaries. The borrowing base includes a $25 million portion, referred to as the “Tranche B” portion, that allows the borrowing base to be greater than the typical borrowing base that would have been computed based on proved natural gas and oil reserves. The Tranche B portion of the borrowing base terminates on November 30, 2005, and, as a result, the borrowing base will decrease to $175 million until redetermined based upon our year-end reserve report. At September 30, 2005, the outstanding balance under our revolving credit facility was $43 million. On December 15, 2004, upon the completion of our IPO, we repaid the then outstanding balance of $123 million. None of the outstanding borrowings at the time of repayment were under the Tranche B portion of the borrowing base. For information concerning the effect of changes in interest rates on interest payments under this facility, see below, Item 3, “Quantitative and Qualitative Disclosure About Market Risk — Interest Rate Risks”.

     The credit facility contains certain financial covenants, including a minimum current ratio and a minimum present value to total debt ratio. The minimum present value covenant will be in place until the Tranche B portion of the credit facility is terminated on November 30, 2005. The credit facility also contains certain covenants that are based on what is defined in the credit facility as EBITDAX. The credit facility defines EBITDAX as our net income, subject to certain adjustments for the particular period plus the following expenses or charges to the extent deducted from net income during that period: interest, income taxes, depreciation, depletion, amortization, exploration and abandonment expenses and other similar non-cash charges and expenses, including stock based compensation and impairments of goodwill, minus all non-cash income added to net income, in each case, and without duplication, calculated after giving pro forma effect to acquisitions and dispositions during the period. These covenants require that our debt to EBITDAX ratio cannot exceed 4.0 to 1.0 until November 30, 2005 and 3.5 to 1.0 thereafter, and that our EBITDAX to interest ratio cannot be below 2.5 to 1.0. EBITDAX is not intended to represent net income (loss) as defined by generally accepted accounting principles in the United States, or GAAP, and such information should not be considered as an alternative to net income (loss), cash provided by operating activities or any other measure of performance prescribed by GAAP. The current ratio covenant

23

states that our current ratio adjusted for the unused portion of the borrowing base and to eliminate certain non-cash assets and liabilities related to hedging activities must be greater than 1.0. The ratio of present value of natural gas and oil properties to total debt covenant states that the defined present value divided by the outstanding debt must not be less than 1.5. This ratio is calculated every six months based on engineering estimates calculated at commodity prices and present value factors determined by the lenders. We have complied with all financial covenants for all periods.

     Contractual Obligations.We have assumed various contractual obligations and commitments in the normal course of our operations and financing activities. We have described these obligations and commitments in our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our 2004 Annual Report on Form 10-K. During the nine months ended September 30, 2005, we entered into two additional firm delivery contracts. One contract is for 8,500 MMbtu of natural gas per day at the inlet of the Questar pipeline for the period beginning May 2005 through March 2010 at the current Northwest Pipeline Rocky Mountains Index price as quoted in Platt’s Inside FERC Gas Market Report on the first business day of each month minus $0.25 per MMbtu. The second is for 10,000 MMbtu of natural gas per day at the Cheyenne Hub beginning April 2005 through March 2007 at the current Colorado Interstate Gas Rocky Mountains Index price as quoted in Platt’s Inside FERC Gas Market Report on the first business day of each month plus $0.16 per MMbtu.

     On October 17, 2005, the Company signed a letter of intent with an industry party to sell a 40% interest in approximately 40,000 net undeveloped acres within our Red Bank Extension in the Williston Basin. The letter of intent provides that the Company will drill two exploratory wells at depths and locations to be mutually determined. This transaction and the drilling commitments are subject to the negotiation of a definitive agreement, which is anticipated to be completed in the fourth quarter of 2005.

     During the third quarter of 2005, the Company entered into a non-cancelable operating lease for additional office space. The total future minimum lease payments is as follows (in thousands):

Year 1	$	150
Year 2		417
Year 3		497
Year 4		504
Year 5		522
Thereafter		265
Total	$	2,355

     In addition to the operating lease listed above, the outstanding balance under our revolving credit facility at September 30, 2005 was $43 million, which has a maturity date of February 4, 2007. See the “Credit Facility” section above for further information.

     There were no other material changes to our contractual obligations since December 31, 2004.

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, 2004 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.

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. For the nine months ended September 30, 2005, our income before income taxes, including hedge settlements, would have changed by $1,021,000 for each $0.10 per Mcf change in natural gas prices and $158,000 for each $1.00 per Bbl change in crude oil prices.

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     We periodically have entered into, and in the future we 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 October 31, 2005, we had hedges in place for approximately 4,755 MMbtu, 14,235 MMbtu, and 10,585 MMbtu of natural gas production for the remaining portion of 2005, 2006, and 2007, respectively, and approximately 74 thousand barrels (“MBbls”), 274 MBbls, and 219 MBbls of oil production for the remaining portion of 2005, 2006, and 2007, 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”.

Price Swaps

     Through various price swaps, we have fixed the price we will receive on a portion of our natural gas and oil production in 2005. 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 volumes associated with these various arrangements as of October 31, 2005.

     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.

Price Collars

     Through price collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas production in 2005, 2006, and 2007. The price collars also allow us to share in upward price movements up to the ceiling prices referenced in the contracts. The weighted average minimum, or floor, price we will receive in each of 2005 and 2006 is $4.75 and $4.82, respectively, per MMBtu for a Northwest Pipeline Corp. Rocky Mountain (“NORRM”) price and $5.10 and $5.25 per MMBtu for a Colorado Interstate Gas Rocky Mountain price, respectively. The minimum price we will receive in 2007 is $5.25 per MMBtu for a Colorado Interstate Gas Rocky Mountain price. The weighted average maximum, or ceiling, price we will receive in each of 2005 and 2006 is $6.99 and $6.72 per MMBtu for a NORRM price, respectively, and $8.19 and $12.05 per MMBtu for a Colorado Interstate Gas Rocky Mountain price, respectively. We also have fixed a portion of our oil production in 2005, 2006, and 2007 based on a weighted average floor price of $45.00, $42.53, and $50.00 per Bbl for a West Texas Intermediate (“WTI”) price, respectively, and a weighted average maximum price of $55.25, $52.26, and $78.15 WTI, respectively. 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 volumes and floor and ceiling prices associated with these various arrangements as of October 31, 2005.

     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 September 30, 2005, we had outstanding debt of $43 million, which bears interest at floating rates in accordance with our revolving credit facility, at an average interest rate of 5.0%. The weighted average amount outstanding in the three months ended September 2005 under our credit facility was $20.5 million. A one hundred basis point (1.0%) increase in each of the LIBOR rate and federal funds rate would result in an estimated $0.2 million increase in annualized interest expense assuming a similar average debt level to the three month period ended September 30, 2005. We expect our debt level to increase as we continue with our planned capital expenditure program.

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

     In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2005 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Internal Control over Financial Reporting

     In addition, the Company is continuously seeking to improve the efficiency and effectiveness of its internal controls as we prepare for our first required disclosures pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 in our Annual Report on Form 10-K for the year ending December 31, 2005. During July 2005, the portion of our accounting activities that were previously outsourced to a third party service provider were centralized under the direct supervision of our Controller. There have been no other changes in our internal controls over financial reporting that occurred during the quarter ended September 30, 2005 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

     The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position or results of operations.

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

     Not applicable.

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 and Reports on Form 8-K

Exhibits

Exhibit
Number		Description of Exhibits
3.1		Certificate of Incorporation of Bill Barrett Corporation, as amended to date. [Incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 (File No 333-115445).]
3.2		Restated Certificate of Incorporation of Bill Barrett Corporation effective December 15, 2004. [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.]
3.3		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.]
3.4		Certificate of Designations of Series A Preferred 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.]
4.1		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		Rights Agreement dated as of December 15, 2004 by and between the Company and Mellon Investor Services LLC. [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.]
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).]
10.2		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		Purchase and Sale Agreement, dated March 27, 2002, between Williams Production RMT Company and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.4		Purchase and Sale Agreement, dated April 1, 2002, among Wasatch Oil & Gas, LLC, Wasatch Gas Gathering, LLC and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.4 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.5		Purchase and Sale Agreement, November 4, 2002, among, Intoil, Inc., Aratex Production Company and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.5 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

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Exhibit
Number		Description of Exhibits
10.6		Purchase and Sale Agreement, dated January 1, 2003, among Independent Production Company, Inc., Sapphire Bay, LLC and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.6 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.7	(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).]
10.7	(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).]
10.8	*	Employment Letter Agreement, dated January 10, 2003, between Thomas B. Tyree, Jr. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.11 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.9	*	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).]
10.10	(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).]
10.10	(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).]
10.11	*	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).]
10.12	*	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).]
10.13		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).]
10.14		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).]
10.15		Purchase and Sale Agreement effective July 1, 2004 among Calpine Corporation and Calpine Natural Gas, L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.18 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.16		Senior Subordinated Credit and Guaranty Agreement dated as of September 1, 2004 among Bill Barrett Corporation, as Borrower, Bill Barrett Properties Inc. and Bill Barrett Production Company, as Guarantors, various lenders, Goldman Sachs Credit Partners L.P., as sole lead arranger and Goldman Sachs Credit Partners L.P., as administrative agent. [Incorporated by reference to Exhibit 10.19 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.17	*	Form of Change in Control Severance Protection Agreement for named executive officers. [Incorporated by reference to Exhibit 10.20 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.18	*	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).]
10.19	*	Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.22 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.20	*	Severance Plan. [Incorporated by reference to Exhibit 10.23 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

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Exhibit
Number	Description of Exhibits
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: November 3, 2005	By:	/s/ William J. Barrett
		William J. Barrett
		Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)
Date: November 3, 2005	By:	/s/ Thomas B. Tyree, Jr.
		Thomas B. Tyree, Jr.
		Chief Financial Officer (Principal Financial Officer)
Date: November 3, 2005	By:	/s/ Robert W. Howard
		Robert W. Howard
		Executive Vice President-Finance and Investor Relations, and Treasurer (Principal Accounting Officer)

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EXHIBIT INDEX

Exhibit
Number		Description of Exhibits
3.1		Certificate of Incorporation of Bill Barrett Corporation, as amended to date. [Incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
3.2		Restated Certificate of Incorporation of Bill Barrett Corporation effective December 15, 2004. [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.]
3.3		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.]
3.4		Certificate of Designations of Series A Preferred 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.]
4.1		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		Rights Agreement dated as of December 15, 2004 by and between the Company and Mellon Investor Services LLC. [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.]
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).]
10.2		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		Purchase and Sale Agreement, dated March 27, 2002, between Williams Production RMT Company and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.4		Purchase and Sale Agreement, dated April 1, 2002, among Wasatch Oil & Gas, LLC, Wasatch Gas Gathering, LLC and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.4 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.5		Purchase and Sale Agreement, November 4, 2002, among, Intoil, Inc., Aratex Production Company and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.5 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.6		Purchase and Sale Agreement, dated January 1, 2003, among Independent Production Company, Inc., Sapphire Bay, LLC and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.6 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

Exhibit
Number		Description of Exhibits
10.7	(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).]
10.7	(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).]
10.8	*	Employment Letter Agreement, dated January 10, 2003, between Thomas B. Tyree, Jr. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.11 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.9	*	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).]
10.10	(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).]
10.10	(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).]
10.11	*	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).]
10.12	*	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).]
10.13		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).]
10.14		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).]
10.15		Purchase and Sale Agreement effective July 1, 2004 among Calpine Corporation and Calpine Natural Gas, L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.18 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.16		Senior Subordinated Credit and Guaranty Agreement dated as of September 1, 2004 among Bill Barrett Corporation, as Borrower, Bill Barrett Properties Inc. and Bill Barrett Production Company, as Guarantors, various lenders, Goldman Sachs Credit Partners L.P., as sole lead arranger and Goldman Sachs Credit Partners L.P., as administrative agent. [Incorporated by reference to Exhibit 10.19 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.17	*	Form of Change in Control Severance Protection Agreement for named executive officers. [Incorporated by reference to Exhibit 10.20 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.18	*	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).]
10.19	*	Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.22 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.20	*	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

Exhibit
Number	Description of Exhibits
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.