Bill Barrett (BBG) 10-Q 2006 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, 2006

OR

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

For the transition period from ________ to ________

Commission file number 001-32367

BILL BARRETT CORPORATION

(Exact name of registrant as specified in its charter)

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

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

(303) 293-9100

(Registrant’s telephone number, including area code)

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

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

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

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

There were 44,065,174 shares of $0.001 par value common stock outstanding on November 3, 2006.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements	3
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3. Quantitative and Qualitative Disclosures about Market Risk	25
Item 4. Controls and Procedures	27
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	28
Item 1A. Risk Factors	28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	28
Item 3. Defaults Upon Senior Securities	29
Item 4. Submission of Matters to a Vote of Security Holders	29
Item 5. Other Information	29
Item 6. Exhibits	30
SIGNATURES	32
EXHIBIT INDEX	33

2

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	December 31, 2005			September 30, 2006
	(in thousands, except share and per share data)
Assets:
Current Assets:
Cash and cash equivalents	$	68,282		$	50,293
Accounts receivable, net of allowance for doubtful accounts of $171 and $252 as of December 31, 2005 and September 30, 2006, respectfully		55,960			36,095
Prepayments and other current assets		6,598			4,892
Derivative assets		—			28,617
Deferred income taxes		10,478			—
Total current assets		141,318			119,897
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		804,421			1,071,530
Unevaluated oil and gas properties, excluded from amortization		168,284			252,561
Oil and gas properties held for sale, excluded from amortization		—			7,367
Furniture, equipment and other		11,533			13,750
		984,238			1,345,208
Accumulated depreciation, depletion, amortization and impairment		(238,290	)		(330,858	)
Total property and equipment, net		745,948			1,014,350
Deferred Financing Costs and Other Assets		1,679			11,881
Total	$	888,945		$	1,146,128
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	58,113		$	57,507
Amounts payable to oil and gas property owners		19,697			7,014
Production taxes payable		25,930			35,927
Derivative liability		29,058			—
Deferred income taxes		—			10,775
Total current liabilities		132,798			111,223
Note Payable to Bank		86,000			185,000
Asset Retirement Obligations		23,733			30,494
Deferred Income Taxes		7,960			81,945
Other Noncurrent Liabilities		7,671			758
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 43,695,286 and 44,021,291 shares issued and outstanding at December 31, 2005 and September 30, 2006, respectively, with 26,577 and 268,524 shares subject to restrictions, respectively		44			44
Additional paid-in capital		721,145			723,504
Accumulated deficit		(62,515	)		(11,470	)
Treasury stock, at cost: 124,024 shares at December 31, 2005 and zero shares at September 30, 2006		(5,180	)		—
Accumulated other comprehensive income (loss)		(22,711	)		24,630
Total stockholders’ equity		630,783			736,708
Total	$	888,945		$	1,146,128

See notes to consolidated financial statements.

3

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2006			2005			2006
	(in thousands, except share and per share amounts)
Operating Revenues:
Oil and gas production	$	70,471		$	80,468		$	175,118		$	256,179
Other		766			23,944			2,474			28,618
Total operating revenues		71,237			104,412			177,592			284,797
Operating Expenses:
Lease operating expense		5,165			7,329			14,059			21,522
Gathering and transportation expense		3,113			3,510			8,717			11,528
Production tax expense		8,525			6,473			21,554			21,252
Exploration expense		4,152			3,333			6,817			7,258
Impairment, dry hole costs and abandonment expense		646			5,099			44,321			12,187
Depreciation, depletion and amortization		21,982			34,506			60,936			98,314
General and administrative		6,708			8,585			19,741			25,495
Total operating expenses		50,291			68,835			176,145			197,556
Operating Income		20,946			35,577			1,447			87,241
Other Income and Expense:
Interest and other income		343			650			1,384			1,888
Interest expense		(734	)		(3,153	)		(1,736	)		(7,508	)
Total other income and expense		(391	)		(2,503	)		(352	)		(5,620	)
Income before Income Taxes		20,555			33,074			1,095			81,621
Provision for Income Taxes		7,258			12,373			615			30,576
Net Income	$	13,297		$	20,701		$	480		$	51,045
Net Income Per Common Share, Basic	$	0.31		$	0.47		$	0.01		$	1.17
Net Income Per Common Share, Diluted	$	0.30		$	0.47		$	0.01		$	1.16
Weighted Average Common Shares Outstanding, Basic		43,285,381			43,730,199			43,186,417			43,647,850
Weighted Average Common Shares Outstanding, Diluted		43,782,874			44,007,475			43,628,292			44,176,225

See notes to consolidated financial statements.

4

BILL BARRETT CORPORATION

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

	Convertible Preferred Stock		Common Stock		Additional Paid-In Capital			Accumulated Deficit			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity			Comprehensive Income
	(in thousands)
Balance — December 31, 2004	$	—	$	43	$	709,578		$	(86,320	)	$	—		$	(3,569	)	$	619,732
Exercise of options		—		1		7,149			—			(5,180	)		—			1,970		$	—
Tax benefit from option exercises		—		—		1,227			—			—			—			1,227			—
Stock-based compensation		—		—		3,211			—			—			—			3,211			—
Other		—		—		(20	)		—			—			—			(20	)		—
Comprehensive income (loss):
Net income		—		—		—			23,805			—			—			23,805			23,805
Effect of derivative financial instruments, net of tax		—		—		—			—			—			(19,142	)		(19,142	)		(19,142	)
Total comprehensive income																				$	4,663
Balance — December 31, 2005	$	—	$	44	$	721,145		$	(62,515	)	$	(5,180	)	$	(22,711	)	$	630,783
Exercise of options		—		—		7,307			—			(4,891	)		—			2,416		$	—
Stock-based compensation		—		—		5,131			—			—			—			5,131			—
Retirement of treasury stock		—		—		(10,071	)		—			10,071			—			—			—
Other		—		—		(8	)		—						—			(8	)		—
Comprehensive income:
Net income		—		—		—			51,045			—			—			51,045			51,045
Effect of derivative financial instruments, net of tax		—		—		—			—			—			47,341			47,341			47,341
Total comprehensive income																				$	98,386
Balance — September 30, 2006	$	—	$	44	$	723,504		$	(11,470	)	$	—		$	24,630		$	736,708

See notes to consolidated financial statements.

5

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended September 30,
	2005			2006
	(in thousands)
Operating Activities:
Net Income	$	480		$	51,045
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		60,936			98,314
Deferred income taxes		615			30,576
Impairment, dry hole costs and abandonment expense		44,321			12,187
Stock compensation and other non-cash charges		2,103			5,165
Amortization of deferred financing costs		882			442
Gain on disposal of properties		(2,101	)		(18,875	)
Change in operating assets and liabilities:
Accounts receivable		(10,112	)		19,970
Prepayments and other assets		(653	)		2,119
Accounts payable, accrued and other liabilities		(153	)		(759	)
Amounts payable to oil and gas property owners		1,116			(12,683	)
Production taxes payable		13,310			9,997
Net cash provided by operating activities		110,744			197,498
Investing Activities:
Additions to oil and gas properties		(224,135	)		(376,456	)
Additions of furniture, equipment and other		(1,852	)		(2,285	)
Proceeds from sale of properties		9,036			68,875
Net cash used in investing activities		(216,951	)		(309,866	)
Financing Activities:
Proceeds from debt		66,000			143,000
Principal payments on debt		(23,000	)		(50,495	)
Proceeds from sale of common stock		995			2,760
Deferred financing costs and other		(50	)		(886	)
Net cash provided by financing activities		43,945			94,379
Decrease in Cash and Cash Equivalents		(62,262	)		(17,989	)
Beginning Cash and Cash Equivalents		99,926			68,282
Ending Cash and Cash Equivalents	$	37,664		$	50,293

See notes to consolidated financial statements.

6

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

September 30, 2006

1. Organization

Bill Barrett Corporation (the “Company”, “we” or “us”), a Delaware corporation, is an independent oil and gas company engaged in the exploration, development and production of natural gas and crude oil. Since its inception on January 7, 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States. 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 $347.3 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 (“GAAP”) for interim financial information. Pursuant to the rules and regulations of the SEC, they do not include all the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of September 30, 2006. Operating results for the three and nine months ended September 30, 2006 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, the uncertainty of exploration and development drilling results, and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, these 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, 2005 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. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs also are capitalized. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. Until the third quarter of 2006, the Company had not capitalized any interest expense. The weighted average interest rate used to capitalize interest for the current quarter was 7.2 percent, including interest and commitment fees paid on the unused portion of the credit facility and amortization of deferred financing costs. The Company capitalized interest costs of $0.5 million for the three and nine months ended September 30, 2006.

7

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

Materials and supplies consists primarily of tubular goods and well equipment to be 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 December 31, 2005			As of September 30, 2006
Proved properties	$	286,503		$	314,209
Wells and related equipment and facilities		445,943			671,026
Support equipment and facilities		64,969			82,932
Materials and supplies		7,006			3,363
Total proved oil and gas properties		804,421			1,071,530
Accumulated depreciation, depletion, amortization and impairment		(234,713	)		(325,870	)
Total proved oil and gas properties, net	$	569,708		$	745,660
Unevaluated properties	$	93,145		$	163,021
Wells and equipment in progress		75,139			89,540
Total unevaluated oil and gas properties, excluded from amortization	$	168,284		$	252,561

Net changes in capitalized exploratory well costs for the nine months ended September 30, 2006 are reflected in the following table (in thousands).

Beginning of period	$	61,530
Additions to capitalized exploratory well costs pending the determination of proved reserves		160,066
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(144,220	)
Exploratory well costs charged to dry hole costs and abandonment expense		(10,397	)
End of period	$	66,979

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

	September 30, 2006
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	47,993
Capitalized exploratory well costs that have been capitalized for a period greater than one year		18,985
End of period balance	$	66,978
Number of exploratory wells that have costs capitalized for a period greater than one year		115

As of September 30, 2006, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling include costs of $19.0 million. The majority of our exploratory wells that have been capitalized for a period greater than one year are located in the Powder River Basin. In this basin, we drill wells into various coal seams. In order to produce gas from the coal seams, a period lasting from a few to 24 months, or in some cases longer, of dewatering is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering, and to classify the reserves as proved.

8

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

As of September 30, 2006, the Company had identified certain oil and gas properties to divest and classified the properties as held-for-sale. Upon classification as held-for-sale, the carrying value of the related properties was analyzed in relation to the estimated fair value, and as a result, the Company recognized a $1.2 million non-cash impairment charge in the current quarter.

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

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

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

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

During the nine months ended September 30, 2006, the Company granted 738,370 options to purchase shares of common stock with a weighted average exercise price of $31.92 per share and 286,485 nonvested equity shares of common stock. During the three months ended September 30, 2006, the Company granted 312,000 options to purchase shares of common stock with a weighted average exercise price of $27.60 per share and 35,765 nonvested equity shares of common stock. Included within operating expenses is non-cash stock based compensation related to option and nonvested equity share awards of $2.2 million and $4.8 million for the nine months ended September 30, 2005 and 2006, respectively, and $0.7 million and $1.6 million for the three months ended September 30, 2005 and 2006, respectively. As of September 30, 2006, there were $18.0 million of total compensation costs related to nonvested stock options and nonvested equity shares of common stock grants that are expected to be recognized over a weighted-average period of 3.2 years.

New Accounting Pronouncements.In June 2005, the Financial Accounting Standards Board (“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. SFAS No. 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 was effective for fiscal years beginning after December 15, 2005, and its adoption did not 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 was effective for our Company as of January 1, 2006. 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. The adoption of this FSP did not have an impact on our financial statements.

9

In July 2006, the FASB issued FASB Interpretation (“FIN”) No. 48,Accounting for Uncertainty in Income Taxes – an interpretation of FAS 109. This Interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109,Accounting for Income Taxes. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning after December 15, 2006. We do not expect the adoption of FIN 48 to have a material impact on our financial statements.

In September 2006, the SEC issued Staff Accounting Bulletin (“SAB”) No. 108,Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. SAB 108 provides guidance on the consideration of effects of the prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. The SEC Staff believes registrants must quantify errors using both a balance sheet and income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. SAB 108 will be effective for the Company as of December 31, 2006; however, it is not expected to have a material affect on the Company’s financial statements.

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

3. Per Share Data and Earnings Per Share

Basic net income per common share 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.

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,
	2005		2006		2005		2006
Net income	$	13,297	$	20,701	$	480	$	51,045
Adjustments to net income for dilution		—		—		—		—
Net income adjusted for the effect of dilution	$	13,297	$	20,701	$	480	$	51,045
Basic weighted-average common shares outstanding in period		43,285		43,730		43,186		43,648
Add dilutive effects of stock options and nonvested equity shares of common stock		498		277		442		528
Diluted weighted-average common shares outstanding in period		43,783		44,007		43,628		44,176
Basic income per common share	$	0.31	$	0.47	$	0.01	$	1.17
Diluted income per common share	$	0.30	$	0.47	$	0.01	$	1.16

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4. Supplemental Disclosures of Cash Flow Information

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

	For nine months ended September 30,
	2005		2006
Cash paid for interest	$	927	$	6,888
Supplemental disclosures of noncash investing and financing activities:
Retirement of treasury stock		—		(10,071	)
Exchange of oil and gas properties for equipment and other properties		—		9,304
Assumption of debt and deferred tax liability – CH4 acquisition		—		43,660
Changes in current assets and liabilities that are reflected in investing activities		7,706		(310	)
Net change in asset retirement obligations		1,278		4,849
Treasury stock acquired from employee stock option exercises		—		4,891

5. Acquisitions and Divestitures

On May 8, 2006, the Company acquired 100% of the outstanding stock of CH4 Corporation, a Delaware corporation (“CH4”), for $75.6 million in cash and agreed to pay $6.5 million of indebtedness of CH4. The acquisition was funded with borrowings under the Company’s credit facility. The primary assets of CH4 consisted of approximately 84,300 gross (52,000 net) acres of oil and gas leasehold interests of coal bed methane properties in the Powder River Basin of Wyoming and an estimated 11.0 Bcfe of proved reserves.

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

Purchase Price:
Cash paid, net of cash received	$	73,557
Debt assumed		6,495
Total	$	80,052
Allocation of Purchase Price:
Working capital	$	(1,166	)
Proved oil and gas properties		39,402
Unevaluated oil and gas properties		79,496
Other non-current assets		122
Deferred income taxes		(37,165	)
Asset retirement obligation		(637	)
Total	$	80,052

We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the preliminary allocation may be revised, if necessary.

In August 2006, the Company completed the sale of approximately 17,000 net acres of certain coalbed methane properties that were acquired with the CH4 acquisition. Proceeds from the sale were $30.7 million and no gain or loss was recognized.

The Company entered into joint exploration agreements and completed other property sales in the Powder River, Paradox, Williston, Wind River, Big Horn, Montana Overthrust and DJ Basins resulting in gains recognized of $23.8 million and $28.1 million during the three and nine months ended September 30, 2006, respectively, which is included in other operating revenues in the Consolidated Statement of Operations.

6. Note Payable to Bank

On March 17, 2006, the Company amended its credit facility (the “Amended Credit Facility”). The Amended Credit Facility has a face value of $400 million, expandable up to $600 million, and had an initial borrowing base of $280 million. Based upon 2006 mid-year reserves, the borrowing base was increased to $310 million on October 6, 2006. Future borrowing bases will be computed based on proved natural gas and oil reserves. The Amended Credit Facility matures on March 17, 2011 and bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate, or LIBOR, plus applicable margins ranging from 1.0% to 1.75%, or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 0.25%. The Company pays commitment fees ranging from 0.25% to 0.375% of the unused borrowing base. This facility is secured by natural gas and oil properties representing at least 80% of the value of the Company’s proved reserves and the pledge of all of the stock of our subsidiaries.

As of September 30, 2006, borrowings outstanding under the Amended Credit Facility totaled $185 million. The Amended Credit Facility also contains certain financial covenants. We have complied with all financial covenants for all periods.

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7. 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 flows. 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, 2006 follows (in thousands):

Beginning of period	$	23,733
Liabilities incurred		2,679
Liabilities settled		(1,231	)
Accretion expense		2,031
Revisions to estimate		3,282
End of period	$	30,494

8. 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.

For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income (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 that 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, we have entered into commodity swap and collar contracts to fix the floor and ceiling prices we receive for a portion of our natural gas and oil production. Our natural gas and oil derivative financial instruments have been designated as cash flow hedges in accordance with SFAS No. 133.

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, 2005 and 2006. As a result, the Company recognized a reduction of natural gas production revenues related to these contracts of $3.8 million and an increase of $5.9 million in the three months ended September 30, 2005 and 2006, respectively, and a reduction of $6.0 million and an increase of $10.2 million in the nine months ended September 30, 2005 and 2006, respectively. The Company also was a party to various collar contracts for oil based on a West Texas Intermediate (“WTI”) index recognizing a reduction to oil production revenues related to these contracts of $1.3 million in the three months ended September 30, 2005 and 2006, and $2.6 million and $3.5

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million in the nine months ended September 30, 2005 and 2006, respectively. 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, 2005 and 2006.

At November 3, 2006, the Company had the following swap contracts and cashless collars (purchased put options and written call options) in order to hedge a portion of our 2006, 2007 and 2008 natural gas and oil production. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas production.

Product	Volume Per Day	Quantity Type	Weighted Average Floor Pricing		Weighted Average Ceiling Pricing		Fixed Price		Index Price (1)	Contract Period
Cashless Collars:
Natural gas	35,000	MMBtu	$	4.82	$	6.72		n/a	NORRM	1/1/2006 — 12/31/2006
Natural gas	24,000	MMBtu	$	7.54	$	13.68		n/a	CIGRM	1/1/2006 — 12/31/2006
Natural gas	15,000	MMBtu	$	7.50	$	12.25		n/a	CIGRM	11/1/2006 — 3/31/2007
Oil	750	Bbls	$	42.53	$	52.26		n/a	WTI	1/1/2006 — 12/31/2006
Natural gas	64,000	MMBtu	$	6.07	$	9.61		n/a	CIGRM	1/1/2007 — 12/31/2007
Oil	800	Bbls	$	55.00	$	79.85		n/a	WTI	1/1/2007 — 12/31/2007
Natural gas	35,000	MMBtu	$	6.50	$	10.00		n/a	CIGRM	1/1/2008 — 12/31/2008
Oil	500	Bbls	$	70.00	$	80.15		n/a	WTI	1/1/2008 — 12/31/2008
Swap Contracts:
Natural gas	15,000	MMBtu		n/a		n/a	$	6.52	CIGRM	9/1/2006 — 10/31/2006

(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.

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

At September 30, 2006, the estimated fair value of contracts designated and qualifying as cash flow hedges under SFAS No. 133 was a net asset of $38.8 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 income as of September 30, 2006 to be reclassified from accumulated other comprehensive income to net income in the next 12 months would be approximately $14.0 million. The Company anticipates that all originally forecasted transactions will occur by the end of the originally specified time periods.

9. 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.

At September 30, 2006, the Company’s balance sheet reflected net deferred tax liability of $92.7 million, of which $14.2 million pertains to a net deferred tax liability of derivative instruments reflected in accumulated other comprehensive income and $37.2 million pertains to the deferred tax liability assumed through the CH4 acquisition.

Income tax expense for the three and nine months ended September 30, 2005 and 2006 differs from the amounts that would be provided by applying the U.S. federal income tax rate to income before income taxes principally due to state income taxes, stock-based compensation not deductible for income tax purposes, and other permanent differences.

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10. Stockholders’ Equity

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

The Company’s authorized capital structure consists of 75,000,000 shares of $0.001 par value preferred stock and 150,000,000 shares of $0.001 par value common stock. In October 2004, 150,000 shares of $0.001 par value preferred stock were designated as Series A Junior Participating Preferred Stock, none of which are outstanding. At September 30, 2006, 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.

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

The Company may occasionally acquire treasury stock in connection with the vesting and exercise of share-based awards, which is recorded at cost. As of September 30, 2006, all treasury stock held by the Company was retired.

11.Accumulated Other Comprehensive Income (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 income and related tax effects for the nine months ended September 30, 2006 were as follows:

	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated other comprehensive loss — December 31, 2005	$	(36,050	)	$	13,339		$	(22,711	)
Change in fair value of hedges		80,844			(29,688	)		51,156
Reclassification adjustment for realized losses on hedges included in net income		(6,007	)		2,192			(3,815	)
Accumulated other comprehensive income — September 30, 2006	$	38,787		$	(14,157	)	$	24,630

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 (including in Part II, Item 1A) and in our Annual Report on Form 10-K for the year ended December 31, 2005 under the “Cautionary Note Regarding Forward-Looking Statements” section and the “Risk Factors” section, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

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Overview

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

Results of Operations

The financial information with respect to the nine and three months ended September 30, 2005 and 2006 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, 2005 Compared to Nine Months Ended September 30, 2006

	Nine Months Ended September 30,				Increase (Decrease)
	2005		2006		Amount			Percent
	($ in thousands)
Operating Results:
Operating Revenues
Oil and gas production revenues	$	175,118	$	256,179	$	81,061		46	%
Other		2,474		28,618		26,144		1,057	%
Operating Expenses
Lease operating expense		14,059		21,522		7,463		53	%
Gathering and transportation expense		8,717		11,528		2,811		32	%
Production tax expense		21,554		21,252		(302	)	(1	%)
Exploration expense		6,817		7,258		441		6	%
Impairment, dry hole costs and abandonment expense		44,321		12,187		(32,134	)	(73	%)
Depreciation, depletion and amortization		60,936		98,314		37,378		61	%
General and administrative		17,520		20,695		3,175		18	%
Non-cash stock-based compensation (1)		2,221		4,800		2,579		116	%
Total operating expenses	$	176,145	$	197,556	$	21,411		12	%
Production Data:
Natural gas (MMcf)		24,813		34,955		10,142		41	%
Oil (MBbls)		386		498		112		29	%
Combined volumes (MMcfe)		27,126		37,943		10,817		40	%
Daily combined volumes (Mmcfe/d)		99		139		40		40	%
Average Prices (includes effects of hedges) (2):
Natural gas (per Mcf)	$	6.34	$	6.55	$	0.21		3	%
Oil (per Bbl)		46.04		54.89		8.85		19	%
Combined (per Mcfe)		6.46		6.75		0.29		4	%
Average Costs (per Mcfe):
Lease operating expense	$	0.52	$	0.57	$	0.05		10	%
Gathering and transportation expense		0.32		0.30		(0.02	)	(6	%)
Production tax expense		0.79		0.56		(0.23	)	(29	%)
Depreciation, depletion and amortization		2.25		2.60		0.35		16	%
General and administrative (3)		0.65		0.55		(0.10	)	(15	%)

(1) Non-cash stock-based compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $19.7 million and $25.5 million for the nine months ended September 30, 2005 and 2006, respectively, in the Consolidated Statement of Operations. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows more accurate comparison to our peers, who may have higher or lower costs associated with equity grants.

(2) Average prices shown in the table are net of the effects of hedging transactions. As a result of hedging transactions, natural gas and oil production revenues were reduced by $8.6 million for the nine months ended September 30, 2005 and were increased by $6.7 million for the nine months ended September 30, 2006. Before the effect of hedging contracts, the average price we received for natural gas and oil for the nine months ended September 30, 2005 was $6.58 per Mcf and $52.69 per Bbl, respectively, compared with $6.26 per Mcf and $61.83 per Bbl, respectively, for the nine months ended September 30, 2006.

(3) Excludes non-cash stock-based compensation as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation, as presented in the Consolidated Statement of Operations, would be $0.73 and $0.67 for the nine months ended September 30, 2005 and 2006, respectively.

Production Revenues.Production revenues increased from $175.1 million for the nine months ended September 30, 2005 to $256.2 million for the current year period due to both an increase in production and increases in natural gas and oil prices after the effect of hedges. Price increases added approximately $7.9 million of production revenues and production increases added approximately $73.2 million of production revenues, after natural production declines, so that our new production from our drilling program and our acquisition more than offset natural production declines.

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On a Mcf equivalent basis, total production volumes for the nine months ended September 30, 2006 increased 40% from total production for the prior year comparable period. Additional information concerning production is in the following table.

	Nine Months Ended September 30, 2005			Nine Months Ended September 30, 2006
	Oil	Natural Gas	Total	Oil	Natural Gas	Total
	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MMcf)	(MMcfe)
Wind River Basin	57	10,629	10,970	35	8,791	9,001
Uinta Basin	4	4,625	4,646	32	11,180	11,372
Powder River Basin	—	6,411	6,411	—	5,391	5,391
Piceance Basin	28	3,018	3,185	134	9,447	10,251
Williston Basin	278	108	1,776	278	104	1,772
Other	19	22	138	19	42	156
Total	386	24,813	27,126	498	34,955	37,943

The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch and Cooper Reservoir Fields. The decrease in production is partially offset by our new deep Lakota discovery well, the Bullfrog 33-19, which had first production at the end of June 2006. The production increase in the Uinta Basin reflects our successful exploration and development activities in the West Tavaputs field along with first production from our initial Lake Canyon discovery wells. Furthermore, the completion of a third party gas processing facility in mid-August increased our takeaway capacity in the West Tavaputs field. The production increase in the Piceance Basin is the result of our continued development activities. The production decrease in the Powder River Basin is due to natural production declines in our existing mature fields and the lag time between drilling of coal bed methane wells and production of natural gas while dewatering occurs, which are partially offset by the production from the properties acquired in early May 2006. In late August 2006, the majority of the then producing properties acquired in the CH4 acquisition were sold. As of September 30, 2006, we had 109 net operated coal bed methane wells in the dewatering stage.

Hedging Activities.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. During the nine months ended September 30, 2006, approximately 42% of our natural gas volumes and 41% of our oil volumes were hedged, resulting in an increase in revenues of $6.7 million.

Other Operating Revenues. Other operating revenues increased from $2.5 million for the nine months ended September 30, 2005 to $28.6 million for the nine months ended September 30, 2006. The increase is primarily due to gains realized on joint exploration agreements entered into and other property sales in the Powder River, Paradox, Williston, Wind River, Big Horn, Montana Overthrust and DJ Basins.

Lease Operating Expense and Gathering and Transportation Expense.Our lease operating expense increased from $0.52 per Mcfe in the first nine months of 2005 to $0.57 per Mcfe in the current year period while our gathering and transportation expense decreased slightly from $0.32 per Mcfe in the first nine months of 2005 to $0.30 per Mcfe in the current year period. The increase in lease operating expenses is primarily due to an increase in the Powder River Basin from $0.58 per Mcfe for the nine months ended September 30, 2005 to $1.00 per Mcfe in the current year period. This increase on a per Mcfe basis in the Powder River Basin is substantially due to higher water handling charges on dewatering wells in new pilot areas that have no offsetting gas production as yet. As of September 30, 2006, we had 109 net operated coal bed methane wells in the dewatering stage. Lease operating expense also increased in the Williston Basin from $1.06 per Mcfe for the first nine months of 2005 to $1.55 per Mcfe in the current year period as a result of the high volumes of water being produced from wells recently put onto production.

We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to avoid possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production from the Piceance and Uinta Basins where we expect to spend a significant portion of our capital expenditure program in future years. Included in the above gathering and transportation expense per Mcfe is $0.04 and $0.07 per Mcfe of transportation expense from long-term contracts for the nine months ended September 30, 2005 and 2006, respectively.

Production Tax Expense.Total production taxes decreased from $21.6 million for the nine months ended September 30, 2005 to $21.3 million for the current year period. Although we realized higher production revenues from the increase in both our production volumes and natural gas and oil prices received, our overall production taxes decreased as a larger portion of our revenues came from areas with lower tax rates. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 11.7% for

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the nine months ended September 30, 2005 and 8.5% for the current year period. Production taxes are primarily based on the wellhead values of production and tax rates that vary across the different areas that we operate. As the proportion of our production changes from area to area, our production tax rate will either increase or decrease depending on the quantities produced from each area and the production tax rates in effect in each individual area. For example, as we continue to develop our acreage position in the Piceance Basin in Colorado, where the overall production tax rate approximates 6%, which is lower than our current overall rate, our overall production tax rate will decrease as proportionately more volumes are added from this lower tax rate area.

Exploration Expense.Exploration costs increased from $6.8 million in the first nine months of 2005 to $7.3 million in the current year period. The costs for the nine months ended September 30, 2005 consist of $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. The costs for the nine months ended September 30, 2006 consist of $6.3 million for seismic programs, principally in the Montana Overthrust, Wind River, Uinta, Paradox and DJ Basins, and $1.0 million for delay rentals and other exploration costs.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense decreased from $44.3 million during the first nine months of 2005 to $12.2 million during the current year period. For the nine months ended September 30, 2005, impairment expense was $36.3 million, dry hole costs were $6.8 million for dry holes in the Wind River, Green River and Uinta Basins, and abandonment expense was $1.2 million. For the nine months ended September 30, 2006, dry hole costs were $10.1 million for dry holes primarily in the Williston and Uinta Basins, and abandonment expense was $0.9 million. Included in the $10.1 million of dry hole costs for the nine months ended September 30, 2006 is $3.6 million related to the #1DLB, an exploration well located in the Lake Canyon area of the Uinta Basin. This well, which was completed in late April 2006, was tested and determined to be commercial in the Wasatch formation and non-commercial in the zones below the Wasatch; thus, a proportionate share of the well cost is being expensed.

The Company evaluates the impairment of its oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. If the carrying amount exceeds the properties’ estimated fair value, the Company will adjust the carrying amount of the properties to fair value through a charge to impairment expense. With respect to our Cedar Camp and Tumbleweed properties within the Uinta Basin, the Company, based upon our fair value analysis, recognized a $1.2 million non-cash impairment charge for the nine months ended September 30, 2006. We are currently in the process of selling these properties.

We account for oil and gas exploration and production activities using the successful efforts method under which we capitalize exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense, otherwise, the costs remain capitalized and are depleted as production occurs. The following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and gas properties as of September 30, 2006 pending determination of whether the wells will be assigned proved reserves. The following table does not include $24.9 million related to exploratory wells in progress for which drilling had not been completed at September 30, 2006:

	Time Elapsed Since Drilling Completed
	0-3 Months		4-6 Months		7-12 Months		> 12 Months		Total
	(in thousands)
Wells for which drilling has completed	$	16,383	$	2,829	$	3,877	$	18,985	$	42,074

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense was $60.9 million for the nine months ended September 30, 2005 compared to $98.3 million for the current year period. Of the increase, $24.2 million is due to the 40% increase in production and $13.2 million is due to an increased depletion rate for the nine months of 2006. During the nine months ended September 30, 2005, the weighted average depletion rate was $2.25 per Mcfe. In the nine months ended September 30, 2006, the weighted average depletion rate was $2.60 per Mcfe. Under successful efforts accounting, depletion expense is separately computed for each producing area based on geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average depletion rate for current production. The Company’s cost of finding oil and gas reserves in certain areas yielded an overall higher depletion rate for the nine months of 2006 compared to the prior year period. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

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General and Administrative Expense.General and administrative expense, excluding non-cash stock-based compensation, increased from $17.5 million in the nine months ended September 30, 2005 to $20.7 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, 2006, we had 134 full time employees in our corporate office compared to 125 as of September 30, 2005. The Company also incurred $0.4 million of nonrecurring expenses during the nine months ended September 30, 2006 as a result of exploring financing options. On a per unit of production basis, however, general and administrative expense decreased from $0.65 per Mcfe in the first nine months of 2005 to $0.55 per Mcfe in the current year period due to increases in production.

Non-cash charges for stock-based compensation were $2.2 million in the first nine months of 2005 compared to $4.8 million in the current year period. The increase in charges for non-cash compensation is primarily due to the increased number of equity awards that were granted during the later part of 2005 and during the nine months ended September 30, 2006. Equity awards to employees generally were made in the first quarter of 2006 and were not made in the first quarter of 2005 because of the awards previously made in connection with our IPO in December 2004. The increase is also due to the acceleration of vesting of share-based awards for certain officers of the Company who left the Company during 2006. Additionally, the Company amended its 401(k) Plan on January 1, 2006 to increase the Company’s match of the employees’ contribution from 4% up to 6%, of which 50% of the match is made with the Company’s common stock.

Interest Expense.Interest expense increased to $7.5 million in the nine months ended September 30, 2006 from $1.7 million in the prior year period. The increase was due to higher debt levels during 2006 to fund exploration 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 for the nine months ended September 30, 2005 was $6.8 million. As a result, the interest expense during the first nine months of 2005 was primarily comprised of debt commitment fees and amortization of deferred financing costs. The weighted average outstanding balance under our credit facility for the nine months ended September 30, 2006 was $150.4 million.

Income Tax Expense.Our effective tax rate was 56% and 37% in the nine months ended September 30, 2005 and 2006, respectively. For both the 2005 and 2006 periods, our effective tax rate differs from the statutory rates primarily because the Company recorded stock-based compensation expense under APB 25 and SFAS No. 123R that is not deductible for income tax purposes. All of our income tax liabilities and benefits are deferred. Due to the tax deductions being created by our drilling activities, we expect that we will not incur cash income tax liabilities for at least the next year.

Net Income.We generated net income of $51.0 million in the nine months ended September 30, 2006 compared to a net income of $0.5 million in the prior year period. The reasons for the increase in net income include the increase in production, increases in natural gas and oil prices, giving effect to hedges, and an increase in other operating revenues, as previously discussed in this section. Additionally, impairment, dry hole costs and abandonment expense decreased by $32.1 million. Offsetting the increase in operating revenues were increases in operating expenses and interest expense during the nine months of 2006 as compared to the prior year period.

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Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2006

	Three Months Ended September 30,				Increase (Decrease)
	2005		2006		Amount			Percent
	($ in thousands)
Operating Results:
Operating Revenues
Oil and gas production revenues	$	70,471	$	80,468	$	9,997		14	%
Other		766		23,944		23,178		3,026	%
Operating Expenses
Lease operating expense		5,165		7,329		2,164		42	%
Gathering and transportation expense		3,113		3,510		397		13	%
Production tax expense		8,525		6,473		(2,052	)	(24	%)
Exploration expense		4,152		3,333		(819	)	(20	%)
Impairment, dry hole costs and abandonment expense		646		5,099		4,453		689	%
Depreciation, depletion and amortization		21,982		34,506		12,524		57	%
General and administrative		5,965		6,952		987		17	%
Non-cash stock-based compensation (1)		743		1,633		890		120	%
Total operating expenses	$	50,291	$	68,835	$	18,544		37	%
Production Data:
Natural gas (MMcf)		9,287		11,637		2,350		25	%
Oil (MBbls)		136		165		29		21	%
Combined volumes (MMcfe)		10,101		12,627		2,526		25	%
Daily combined volumes (Mmcfe/d)		110		137		27		25	%
Average Prices (includes effects of hedges) (2):
Natural gas (per Mcf)	$	6.85	$	6.09	$	(0.76	)	(11	%)
Oil (per Bbl)		50.35		58.05		7.70		15	%
Combined (per Mcfe)		6.98		6.37		(0.61	)	(9	%)
Average Costs (per Mcfe):
Lease operating expense	$	0.51	$	0.57	$	0.06		12	%
Gathering and transportation expense		0.31		0.28		(0.03	)	(10	%)
Production tax expense		0.84		0.51		(0.33	)	(39	%)
Depreciation, depletion and amortization		2.18		2.75		0.57		26	%
General and administrative (3)		0.59		0.55		(0.04	)	(7	%)

(1) Non-cash stock-based compensation is presented herein as a separate line item but is combined with general and administrative expense on the income statement for a total of $6.7 million and $8.6 million for the three months ended September 30, 2005 and 2006, respectively, in the Consolidated Statement of Operations. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows more accurate comparison to our peers, who may have higher or lower costs associated with equity grants.

(2) Average prices shown in the table are net of the effects of hedging transactions. As a result of hedging transactions, natural gas and oil production revenues were reduced by $5.1 million for the three months ended September 30, 2005 and increased by $4.6 million for the three months ended September 30, 2006. Before the effect of hedging contracts, the average price we received for natural gas and oil for the quarter ended September 30, 2005 was $7.26 per Mcf and $60.19 per Bbl, respectively, compared with $5.58 per Mcf and $65.97 per Bbl, respectively, for the quarter ended September 30, 2006.

(3) Excludes non-cash stock-based compensation as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation, as presented in the Consolidated Statement of Operations, would be $0.66 and $0.68 for the three months ended September 30, 2005 and 2006, respectively.

Production Revenues.Production revenues increased from $70.5 million for the three months ended September 30, 2005 to $80.5 million for the current year period due to an increase in production and increases in oil prices after the effect of hedges, which was offset by a decrease in natural gas prices. Despite the effect of price decreases of approximately $6.2 million on production revenues, the production increases added approximately $16.2 million of production revenues, after natural production declines, so that our new production from our drilling program and our acquisition more than offset natural production declines.

On a Mcf equivalent basis, total production volumes for the three months ended September 30, 2006 increased 25% from total production for the prior year period. Additional information concerning production is in the following table.

	Three Months Ended September 30, 2005			Three Months Ended September 30, 2006
	Oil	Natural Gas	Total	Oil	Natural Gas	Total
	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MMcf)	(MMcfe)
Wind River Basin	16	4,241	4,337	10	2,772	2,832
Uinta Basin	1	1,609	1,617	8	3,308	3,356
Powder River Basin	—	2,151	2,151	—	1,771	1,771
Piceance Basin	11	1,239	1,302	54	3742	4,066
Williston Basin	102	37	647	87	32	554
Other	6	10	47	6	12	48
Total	136	9,287	10,101	165	11,637	12,627

The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch and Cooper Reservoir Fields. The decrease in production is partially offset by our new deep Lakota discovery well, the Bullfrog 33-1, which had first production at the end of June 2006. The production increase in the Uinta Basin reflects our successful exploration and development activities in the West Tavaputs and Lake Canyon areas. Furthermore, the completion of a third party gas processing facility in mid-

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August added additional production capacity in the West Tavaputs field. The production increase in the Piceance Basin is the result of our continued development activities. The production decrease in the Powder River Basin is due to natural production declines in our Palm Tree and Tuit fields and the lag time between drilling of coal bed methane wells and production of natural gas while dewatering occurs, which are partially offset by the production from the properties acquired in early May 2006. In late August 2006, the majority of the then producing properties acquired in the CH4 acquisition were sold. As of September 30, 2006, we had 109 net operated coal bed methane wells in the dewatering stage.

Hedging Activities.During the three months ended September 30, 2005, approximately 46% of our natural gas volumes and 54% of our oil volumes were hedged, resulting in a reduction in revenues of $5.1 million. During the three months ended September 30, 2006, approximately 42% of our natural gas volumes and our oil volumes were hedged, resulting in an increase in revenues of $4.6 million.

Other Operating Revenues. Other operating revenues increased from $0.8 million for the three months ended September 30, 2005 to $23.9 million for the three months ended September 30, 2006. The increase is primarily due to gains realized on joint exploration agreements entered into and other property sales in the Powder River, Paradox, Wind River, Big Horn, Montana Overthrust and DJ Basins.

Lease Operating Expense and Gathering and Transportation Expense.Our lease operating expense increased from $0.51 per Mcfe in the third quarter of 2005 to $0.57 per Mcfe in the current year period, and our gathering and transportation expense decreased slightly from $0.31 per Mcfe in the third quarter of 2005 to $0.28 per Mcfe in the current year period. The increase in LOE is primarily attributable to higher salt water disposal costs in the Piceance, Williston and Powder River Basins. The increase in the Powder River Basin is substantially due to coal bed methane wells in the dewatering stage in new pilot areas that have no offsetting gas production as yet. As of September 30, 2006, we had 109 net operated coal bed methane wells in the dewatering stage.

We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to avoid possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production from the Piceance and Uinta Basins where we expect to spend a significant portion of our capital expenditure program in future years. Included in the above gathering and transportation expense per Mcfe is $0.04 and $0.07 per Mcfe of transportation expense from long-term contracts for the three months ended September 30, 2005 and 2006, respectively.

Production Tax Expense.Total production taxes decreased from $8.5 million for the three months ended September 30, 2005 to $6.5 million for the current year period. Although we realized higher production revenues from the increase in both our production volumes and oil prices received, our overall production taxes decreased as a larger portion of our revenues came from areas with lower tax rates. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 11.3% for the three months ended September 30, 2005 and 8.5% for the current year period. Production taxes are primarily based on the wellhead values of production and tax rates that vary across the different areas that we operate. As the proportion of our production changes from area to area, our production tax rate will either increase or decrease depending on the quantities produced from each area and the production tax rates in effect in each individual area. For example, as we continue to develop our acreage position in the Piceance Basin in Colorado, where the overall production tax rate will approximate 6%, which is lower than our current overall rate, our overall production tax rate will decrease as proportionately more volumes are added from this lower tax rate area.

Exploration Expense.Exploration costs decreased from $4.2 million in the third quarter of 2005 to $3.3 million in the current year period. The costs for the three months ended September 30, 2005 consist of $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. The costs for the three months ended September 30, 2006 consist of $3.0 million for seismic programs, principally in the Wind River, Montana Overthrust, and DJ Basins and $0.3 million for delay rentals and other exploratory costs.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense increased from $0.6 million during the third quarter of 2005 to $5.1 million during the current year period. For the three months ended September 30, 2005, impairment expense was zero, dry hole costs were $0.4 million for dry holes in the Wind River Basin, and abandonment expense was $0.2 million. For the three months ended September 30, 2006, dry hole costs were $3.7 million for dry holes primarily in the Williston and Wind River Basins and abandonment expense was $0.2 million.

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The Company evaluates the impairment of its oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. If the carrying amount exceeds the properties’ estimated

fair value, the Company will adjust the carrying amount of the properties to fair value through a charge to impairment expense. With respect to our Cedar Camp and Tumbleweed properties within the Uinta Basin, the Company, based upon our fair value analysis, recognized a $1.2 million non-cash impairment charge in the current quarter. We are currently in the process of selling these properties.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense was $22.0 million for the three months ended September 30, 2005 compared to $34.5 million for the current year period. Of the increase, $5.4 million is due to the 25% increase in production and $7.1 million is due to an increased depletion rate for the three months ended September 30, 2006. During the three months ended September 30, 2005, the weighted average depletion rate was $2.18 per Mcfe. In the three months ended September 30, 2006, the weighted average depletion rate was $2.75 per Mcfe. Under successful efforts accounting, depletion expense is separately computed for each producing area based on geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average depletion rate for current production. For the three months ended September 30, 2006, the relationship of capital expenditures, proved reserves and production from certain producing areas yielded a higher weighted average depletion rate as the comparable prior year period. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

General and Administrative Expense.General and administrative expense, excluding non-cash stock-based compensation, increased from $6.0 million in the three months ended September 30, 2005 to $7.0 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, 2006, we had 134 full time employees in our corporate office compared to 125 as of September 30, 2005. The Company also incurred $0.4 million of nonrecurring expenses during the three months ended September 30, 2006 as a result of exploring financing options. However, on a per unit of production basis, general and administrative expense decreased from $0.59 per Mcfe in the third quarter of 2005 to $0.55 per Mcfe in the current year period due to increases in production.

Non-cash charges for stock-based compensation were $0.7 million in the third quarter of 2005 compared to $1.6 million in the current year period. The increase in charges for non-cash compensation is primarily due to the increased number of equity awards that were granted throughout 2005 and during the quarter ended March 31, 2006. Equity awards to employees generally were made in the first quarter of 2006 and were not made in the first quarter of 2005 because of the awards made in connection with our IPO in December 2004. The increase is also due to the acceleration of vesting of share-based awards for certain officers of the Company who left the Company during 2006. Additionally, the Company amended its 401(k) Plan on January 1, 2006 to increase the Company’s match of the employees’ contribution from 4% up to 6%, of which 50% of the match is made with the Company’s common stock.

Interest Expense.Interest expense increased to $3.2 million in the three months ended September 30, 2006 from $0.7 million in the prior year period. The increase was due to higher debt levels during 2006 to fund exploration and development activities. The weighted average outstanding balance under our credit facility for the three months ended September 30, 2006 was $201.5 million compared to $20.5 million for the three months ended September 30, 2005.

Income Tax Expense.Our effective tax rate was 35% and 37% in the three months ended September 30, 2005 and 2006, respectively. For both the 2005 and 2006 periods, our effective tax rate differs from the statutory rates primarily because the Company recorded stock-based compensation expense under APB 25 and SFAS No. 123R that is not deductible for income tax purposes. All of our income tax liabilities and benefits are deferred. Due to the tax deductions being created by our drilling activities, we expect that we will not incur cash income tax liabilities for at least the next year.

Net Income.We generated net income of $20.7 million in the three months ended September 30, 2006 compared to net income of $13.3 million in the prior year period. The reasons for the increase in net income include the increase in production and other operating revenues, as previously discussed in this section. Offsetting the increase in operating revenues were increases in impairment, dry hole costs and abandonment expense, depreciation, depletion and amortization, other operating expenses and interest expense during the third quarter 2006 as compared to the prior year period.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been from sales and other issuances of securities, net cash provided by operating activities, a bank line of credit, a bridge loan to finance our September 2004 acquisition of properties in the Piceance Basin in Colorado and sales of interests in properties. In addition, we have the ability to offer our common stock, preferred stock, depositary shares, warrants and debt securities under an effective shelf registration filed with the SEC in January 2006. Our primary use of capital has been for the exploration, development, and acquisition of natural gas and oil properties. As we pursue

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reserve and production growth, we continually monitor our portfolio and 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 also actively review acquisition and divestiture opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash or increase the pace of development, we may need to obtain additional equity or debt financing.

Cash Flow from Operating Activities

Net cash provided by operating activities was $110.7 million and $197.5 million for the nine months ended September 30, 2005 and 2006, respectively. The increase in net cash provided by operating activities was 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 $3.5 million and $18.6 for the nine months ended September 30, 2005 and 2006, respectively.

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 political and economic activities, weather, transportation 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 fix the floor and ceiling prices we receive for a portion of our natural gas and oil production. At November 3, 2006, we had in place natural gas and crude oil collars covering portions of our 2006, 2007 and 2008 production. Our natural gas and oil derivative financial instruments have been designated as cash flow hedges in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities,and are classified as current and noncurrent assets in our Consolidated Balance Sheets based on scheduled delivery of the underlying production.

At November 3, 2006, the Company had the following swap contracts and cashless collars (purchased put options and written call options) in order to hedge a portion of our 2006, 2007 and 2008 natural gas and oil production. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas production.

Product	Volume Per Day	Quantity Type	Weighted Average Floor Pricing		Weighted Average Ceiling Pricing		Fixed Price		Index Price (1)	Contract Period
Cashless Collars:
Natural gas	35,000	MMBtu	$	4.82	$	6.72		n/a	NORRM	1/1/2006 — 12/31/2006
Natural gas	24,000	MMBtu	$	7.54	$	13.68		n/a	CIGRM	1/1/2006 — 12/31/2006
Natural gas	15,000	MMBtu	$	7.50	$	12.25		n/a	CIGRM	11/1/2006 — 3/31/2007
Oil	750	Bbls	$	42.53	$	52.26		n/a	WTI	1/1/2006 — 12/31/2006
Natural gas	64,000	MMBtu	$	6.07	$	9.61		n/a	CIGRM	1/1/2007 — 12/31/2007
Oil	800	Bbls	$	55.00	$	79.85		n/a	WTI	1/1/2007 — 12/31/2007
Natural gas	35,000	MMBtu	$	6.50	$	10.00		n/a	CIGRM	1/1/2008 — 12/31/2008
Oil	500	Bbls	$	70.00	$	80.15		n/a	WTI	1/1/2008 — 12/31/2008
Swap Contracts:
Natural gas	15,000	MMBtu		n/a		n/a	$	6.52	CIGRM	9/1/2006 — 10/31/2006

(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.

By removing or limiting the price volatility from a portion of our natural gas and oil production for 2006, 2007 and 2008, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are creditworthy, major financial institutions deemed by management as competent and competitive market makers.

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At September 30, 2006, the estimated fair value of contracts designated and qualifying as cash flow hedges under SFAS No. 133 was a net asset of $38.8 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 income as of September 30, 2006 to be reclassified from accumulated other comprehensive income to net income in the next twelve months would be $14.0 million. The Company anticipates that all originally forecasted transactions will occur by the end of the originally specified time periods.

Capital Expenditures

Our capital expenditures were $240.4 million and $428.6 million for the nine months ended September 30, 2005 and 2006, respectively. The total for the nine month period of 2005 consists of $18.9 million for acquisitions 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 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 $1.8 million for furniture, fixtures and equipment. The total capital expenditures for the nine month period of 2006 consists of $155.0 million for the acquisition of both proved and unevaluated properties (including $37.2 million of a non-cash deferred tax liability associated with the difference between the tax basis of the properties acquired in the CH4 acquisition and the book basis attributed to the properties under the purchase method of accounting), $253.7 million for drilling, development, exploration and exploitation of natural gas and oil properties, $18.2 million for geologic and geophysical costs, which are expensed under successful efforts accounting as exploration expense and impairment, dry hole costs and abandonment expense, and $1.7 million for furniture, fixtures and equipment.

Unevaluated properties increased to $252.6 million at September 30, 2006 from $168.3 million at December 31, 2005, principally from increases in leasehold, including the CH4 acquisition, and wells in progress from increased drilling activity during the nine months ended September 30, 2006.

Through the first nine months of 2006, we had incurred capital expenditures of $313.3 million, excluding $37.2 million allocated to oil and gas properties due to the deferred tax liability assumed through the CH4 acquisition and excluding $9.3 million related to the fair value of properties received in lieu of cash. Total capital expenditures of $313.3 million is net of proceeds received of $68.8 million related to joint exploration agreements entered into and other property sales, including $31 million related to Powder River properties sold in August 2006. Our full year capital budget is currently set at $350 million plus $80 million for our CH4 acquisition. This budget is net of proceeds received from the sale of interests in oil and gas properties and divestitures. The Company expects its net capital expenditures will be approximately $350 million as it has increased activity in the Piceance and Uinta Basins in the fourth quarter based on improved results. However, the Company will spend $31 million less than the $80 million budgeted for the CH4 acquisition due to the divestiture of a portion of the properties. Of the $430 million capital budget, which does not include the $37 million non-cash deferred tax liability related to the CH4 acquisition, we allocated to spend approximately $80 million related to the acquisition of CH4, up to $275 million for development activities and up to $70 million for exploration activities, net of an estimated $60 million in joint exploration proceeds, with the remaining $5 million allocated to other activities. We are projecting that cash on hand, cash available from operating activities, borrowings under our credit facility, and proceeds from selling down a portion of our interests in certain properties will be sufficient to fund our remaining 2006 capital budget. Certain activities contemplated by our capital budget, as well as additional activities, are subject to our entering into joint exploration agreements with industry partners, which would involve a sale of a portion of our working interests in a number of exploration projects.

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 or costs increase to levels above our acceptable levels, we could choose to further defer a portion of planned capital expenditures until later periods or eliminate planned activities to achieve the desired balance between sources and uses of liquidity by prioritizing capital projects. 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 the remainder of 2006 and 2007 and our hedged production, we anticipate that operating cash flow, proceeds, and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for 2006 and into 2007. However, future cash flows in subsequent years are subject to a number of variables, including the level of natural gas and oil production and prices. We can provide no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain our desired levels of capital expenditures.

Financing Activities

Credit Facility.On March 17, 2006, the Company amended its credit facility, referred to herein as the Amended Credit Facility. The Amended Credit Facility has an increased face value of $400 million, expandable up to $600 million and had an initial borrowing base of $280 million. Based upon 2006 mid-year reserves, the borrowing base was increased to $310 million on October 6, 2006.

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Future borrowing bases will be computed based on proved natural gas and oil reserves. The Amended Credit Facility matures on March 17, 2011 and bears interest, based on the borrowing base usage, at the applicable LIBOR plus applicable margins ranging from 1.0% to 1.75%, or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 0.25%. The Company pays commitment fees ranging from 0.25% to 0.375% of the unused borrowing base. This facility is secured by our natural gas and oil properties representing at least 80% of the value of the Company’s proved reserves and the pledge of all of the stock of our subsidiaries.

At September 30, 2006, the outstanding balance under our Amended Credit Facility was $185 million.

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 Annual Report on Form 10-K for the year ended December 31, 2005. There were no material changes to our contractual obligations since December 31, 2005.

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, 2005 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, 2006, our income before income taxes, including hedge settlements, would have changed by $1.9 million for each $0.10 per Mcf change in natural gas prices and $0.3 million for each $1.00 per Bbl change in crude oil prices.

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 November 3, 2006, we had hedges in place for approximately 6,808,000 MMbtu, 24,710,000 MMbtu, and 12,810,000 MMbtu of natural gas production for the remaining portion of 2006 and in 2007 and 2008, respectively, and approximately 69 thousand barrels (“MBbls”), 292 MBbls, and 183 MBbls of oil production for the remaining portion of 2006 and in 2007 and 2008, respectively. These hedges are summarized in the table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities”.

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Price Swaps

Through a price swap, we have fixed the price we will receive on a portion of our natural gas production in 2006. 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 this arrangement as of November 3, 2006.

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 and oil production in 2006, 2007, and 2008. 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 for the remaining portion of 2006 is $4.82 per MMBtu for a NORRM price and $7.53, $6.15 and $6.50 per MMBtu for CIGRM price for the remaining portion of 2006 and 2007 and 2008, respectively. The weighted average maximum, or ceiling, price we will receive for the remaining portion of 2006 is $6.72 per MMBtu for a NORRM price and $13.26, $9.75 and $10.00 per MMBtu for a CIGRM price for the remaining portion of 2006 and 2007 and 2008, respectively. The weighted average floor price we will receive for the remaining portion of 2006 and in 2007 and 2008 is $42.53, $55.00 and $70.00 per Bbl for a WTI price, respectively, and a weighted average maximum price of $52.26, $79.85 and $80.15 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 November 3, 2006.

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, 2006, we had debt outstanding of $185 million, all of which bears interest at floating rates in accordance with our Amended Credit Facility. The average annualized interest rate incurred on this debt for the nine months ended September 30, 2006 was 5.9%, excluding debt commitment fees and amortization of deferred financing costs. A one hundred basis point (1.0%) increase in each of the average LIBOR rate and federal funds rate for the nine months ended September 30, 2006 would have resulted in an estimated $1.5 million increase in interest expense assuming a similar average debt level to the nine months ended September 30, 2006.

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Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the third fiscal quarter of 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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 1A. Risk Factors.

As of the date of this filing, except as noted below, there have been no material changes from the risk factors previously disclosed in our “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2005, referred to as our 2005 Annual Report. An investment in our securities involves various risks. When considering an investment in our company, you should consider carefully all of the risk factors described in our 2005 Annual Report. These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our company.

The following are new or modified risk factors that should be read in conjunction with the risk factors disclosed in our 2005 Annual Report:

Substantially all of our producing properties are located in the Rocky Mountains, making us vulnerable to risks associated with operating in one major geographic area.

Our operations are focused on the Rocky Mountain region, which means our producing properties are geographically concentrated in that area. In particular, a substantial portion of our proved oil and natural gas reserves are located in the Piceance, Wind River and Uinta Basins. Approximately 34% of our proved reserves at December 31, 2005 and approximately 19% of our December 2005 production were located in the Piceance Basin, approximately 25% of our proved reserves at December 31, 2005 and approximately 33% of our December 2005 production were located in the Wind River Basin, and approximately 24% of our proved reserves at December 31, 2005 and approximately 29% of our December 2005 production were located in the Uinta Basin. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, the availability and capacity of compression and gas processing facilities, curtailment of production or interruption of transportation of natural gas produced from the wells in these basins.

Risks Relating to Oil and Gas Reserves

Reserve Estimates are based on many uncertainties for which estimates are made based upon the best available data, including commodity prices and production profiles, and our properties may not produce as we originally forecast. For example, we reduced our reserve estimates, excluding price effects, by approximately 41 Bcfe at year end 2003, 32 Bcfe at year end 2004, and 25 Bcfe at year end 2005.

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

The following table contains information about our acquisitions of equity securities during the year ended December 31, 2005 and the nine months ended September 30, 2006.

Issuer Purchases of Equity Securities

Period	Total Number of Shares (1)	Weighted Average Price Paid Per Share		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
December 1 – 31, 2005	124,024	$	41.76	—	—
January 1 – 31, 2006	—		—	—	—
February 1 – 28, 2006	—		—	—	—
March 1 – 31, 2006	230	$	31.91	—	—
April 1 – 30, 2006	—		—	—	—
May 1 – 31, 2006	63,181	$	30.39	—	—
June 1 – 30, 2006	92,664	$	31.94	—	—
July 1 – 31, 2006	—		—	—	—
August 1 – 31, 2006	—		—	—	—
September 1 – 30, 2006	186	$	24.63	—	—
Total	280,285	$	35.93	—	—

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

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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.

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 333-114554).]
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. 333-114554).]
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. 333-114554).]
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	Second Amended and Restated Credit Agreement, dated March 17, 2006, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 22, 2006.]
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. 333-114554).]
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. 333-114554).]
10.2(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. 333-114554).]
10.2(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. 333-114554).]
10.3*	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. 333-114554).]

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10.4(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. 333-114554).]
10.4(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. 333-114554).]
10.5*	2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to the Company’s Registration Statement on Form S-1 (File No. 333-114554).]
10.6*	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. 333-114554).]
10.7	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. 333-114554).]
10.8	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. 333-114554).]
10.9	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. 333-114554).]
10.10	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. 333-114554).]
10.11*	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. 333-114554).]
10.12*	2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement on Form S-1 (File No. 333-114554).]
10.13*	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. 333-114554).]
10.14*	Severance Plan. [Incorporated by reference to Exhibit 10.23 to the Company’s Registration Statement on Form S-1 (File No. 333-114554).]
10.15	Stock Purchase Agreement dated April 13, 2006 between and among the Company, CH4 Holdings, LP, a Texas limited partnership, and CH4 Corporation, a Delaware corporation. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 14, 2006.]
31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
31.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
32.1	Section 1350 Certification of Chief Executive Officer
32.2	Section 1350 Certification of Chief Financial Officer

* Indicates a management contract or compensatory plan or arrangement.

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SIGNATURES

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

	BILL BARRETT CORPORATION
Date: November 6, 2006	By:	/s/ Fredrick J. Barrett
		Fredrick J. Barrett
		Chairman of the Board of Directors and Chief Executive Officer
		(Principal Executive Officer)
Date: November 6, 2006	By:	/s/ Thomas B. Tyree, Jr.
		Thomas B. Tyree, Jr.
		Chief Financial Officer
		(Principal Financial Officer)
Date: November 6, 2006	By:	/s/ David R. Macosko
		David R. Macosko
		Vice President, Accounting
		(Chief 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. 333-114554).]
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. 333-114554).]
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. 333-114554).]
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	Second Amended and Restated Credit Agreement, dated March 17, 2006, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 22, 2006.]
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. 333-114554).]
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. 333-114554).]
10.2(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. 333-114554).]
10.2(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. 333-114554).]
10.3*	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. 333-114554).]
10.4(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. 333-114554).]

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10.4(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. 333-114554).]
10.5*	2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to the Company’s Registration Statement on Form S-1 (File No. 333-114554).]
10.6*	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. 333-114554).]
10.7	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. 333-114554).]
10.8	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. 333-114554).]
10.9	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. 333-114554).]
10.10	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. 333-114554).]
10.11*	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. 333-114554).]
10.12*	2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement on Form S-1 (File No. 333-114554).]
10.13*	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. 333-114554).]
10.14*	Severance Plan. [Incorporated by reference to Exhibit 10.23 to the Company’s Registration Statement on Form S-1 (File No. 333-114554).]
10.15	Stock Purchase Agreement dated April 13, 2006 between and among the Company, CH4 Holdings, LP, a Texas limited partnership, and CH4 Corporation, a Delaware corporation. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 14, 2006.]
31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
31.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
32.1	Section 1350 Certification of Chief Executive Officer
32.2	Section 1350 Certification of Chief Financial Officer

* Indicates a management contract or compensatory plan or arrangement.

34