Bill Barrett 10Q 2005 Q2 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 June 30, 2005


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

For the transition period from to

Commission file number 001-32367

BILL BARRETT CORPORATION

(Exact name of registrant as specified in its charter)


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

1099 18^th Street, Suite 2300 Denver, Colorado (Address of principal executive offices)		80202 (zip code)

(303) 293-9100
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yeso Noþ.

There were 43,419,136 shares of $.001 par value common stock outstanding on August 1, 2005.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS
(UNAUDITED)


	December 31,			June 30,
	2004			2005
	(in thousands, except share data)
Assets:
Current Assets:
Cash and cash equivalents	$	99,926		$	35,699
Accounts receivable		31,149			25,748
Prepayments and other current assets		4,625			4,975
Deferred income taxes		2,190			6,805

Total current assets		137,890			73,227
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		517,210			630,935
Unevaluated oil and gas properties, excluded from amortization		137,605			162,383
Furniture, equipment and other		4,964			6,347

		659,779			799,665
Accumulated depreciation, depletion, amortization, and impairment		(107,614	)		(182,433	)

Total property and equipment, net		552,165			617,232
Deferred Income Taxes		3,081			12,029
Deferred Financing Costs and Other Assets		3,022			2,428

Total	$	696,158		$	704,916

Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	37,392		$	39,953
Amounts payable to oil and gas property owners		5,390			6,866
Production taxes payable		15,437			23,043
Derivative liability and other		3,887			16,899

Total current liabilities		62,106			86,761
Asset Retirement Obligations		11,806			13,144
Other Noncurrent Liabilities		2,514			8,130
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 43,323,270 and 43,397,123 shares issued at December 31, 2004 and June 30, 2005 respectively, with 283,887 and 157,602 shares subject to restrictions, respectively		43			43
Additional paid-in capital		709,578			711,326
Accumulated deficit		(86,320	)		(99,137	)
Accumulated other comprehensive loss		(3,569	)		(15,351	)

Total stockholders’ equity		619,732			596,881

Total	$	696,158		$	704,916

See notes to consolidated financial statements.

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)


	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2005			2004*			2005
				(in thousands, except per share amounts)
Revenues:
Oil and gas production	$	40,450		$	53,962		$	76,442		$	104,647
Other		1,949			487			2,398			1,708

Total revenues		42,399			54,449			78,840			106,355
Operating Expenses:
Lease operating expense		4,174			4,413			7,187			8,894
Gathering and transportation expense		1,339			2,881			2,491			5,604
Production tax expense		5,189			6,419			9,565			13,029
Exploration expense		1,334			684			2,813			2,665
Impairment, dry hole costs and abandonment expense		278			38,990			281			43,675
Depreciation, depletion and amortization		18,580			19,177			31,002			38,954
General and administrative		5,532			6,656			10,808			13,033

Total operating expenses		36,426			79,220			64,147			125,854

Operating income (loss)		5,973			(24,771	)		14,693			(19,499	)
Other Income and Expense:
Interest income		67			502			128			1,041
Interest expense		(789	)		(496	)		(1,383	)		(1,002	)

Total other income and expense		(722	)		6			(1,255	)		39

Income (Loss) before Income Taxes		5,251			(24,765	)		13,438			(19,460	)
Provision for (Benefit from) Income Taxes		2,216			(8,894	)		5,666			(6,643	)

Net Income (Loss)		3,035			(15,871	)		7,772			(12,817	)
Less cumulative dividends on preferred stock		(4,805	)		—			(9,338	)		—

Net loss attributable to common stock	$	(1,770	)	$	(15,871	)	$	(1,566	)	$	(12,817	)


Net Loss Per Common Share, Basic and Diluted	$	(1.27	)	$	(0.37	)	$	(1.18	)	$	(0.30	)


Weighted Average Common Shares Outstanding, Basic and Diluted		1,397,796			43,186,922			1,325,686			43,136,115


*		As restated, see Note 10.

See notes to consolidated financial statements.

BILL BARRETT CORPORATION

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


													Accumulated
	Convertible						Additional						Other			Total
	Preferred			Common			Paid-In			Accumulated			Comprehensive			Stockholders’			Comprehensive
	Stock			Stock			Capital			Deficit			Loss			Equity			(Loss) Income
	(in thousands)
Balance — December 31, 2003	$	51		$	9		$	251,633		$	(8,966	)	$	(4,401	)	$	238,326

Issuance of Series B convertible preferred stock for cash		7			—			33,723			—			—			33,730			—
Exercise of options		—			—			52			—			—			52			—
Issuance of Series B convertible preferred stock for acquisition of mineral leasehold interests		—			—			322			—			—			322			—
Cancellation of Series A convertible preferred stock		—			—			(500	)		—			—			(500	)		—
Reverse stock split: 1-for-4.658		—			(7	)		7			—			—			0			—
Proceeds from initial public offering (net of underwriters’ discount of $26,445)		—			15			347,290			—			—			347,305			—
Conversion of convertible note payable into common stock		—			—			1,900			—			—			1,900			—
Conversion of issued and outstanding Series A convertible preferred stock into common stock upon initial public offering		(6	)		2			4			—			—			0			—
Conversion of issued and outstanding Series B convertible preferred stock into common stock upon initial public offering		(52	)		24			28			—			—			0			—
Recognition of 7% cumulative dividend on Series B convertible stock in common stock		—			—			35,745			(35,745	)		—			0			—
Recognition of deemed dividends related to the conversion of Series B convertible stock into common stock upon initial public offering		—			—			36,343			(36,343	)		—			0			—
Stock-based compensation		—			—			3,031			—			—			3,031			—
Comprehensive (loss) income:
Net loss		—			—			—			(5,266	)		—			(5,266	)		(5,266	)
Effect of derivative financial instruments, net of tax		—			—			—			—			832			832			832

Total comprehensive loss																			$	(4,434	)

Balance — December 31, 2004	$	0		$	43		$	709,578		$	(86,320	)	$	(3,569	)	$	619,732

Exercise of options		—			—			290			—			—			290			—
Stock-based compensation		—			—			1,478			—			—			1,478			—
Other		—			—			(20	)		—			—			(20	)		—
Comprehensive loss:
Net loss		—			—			—			(12,817	)		—			(12,817	)		(12,817	)
Effect of derivative financial instruments, net of tax		—			—			—			—			(11,782	)		(11,782	)		(11,782	)

Total comprehensive loss																			$	(24,599	)

Balance — June 30, 2005	$	0		$	43		$	711,326		$	(99,137	)	$	(15,351	)	$	596,881

See notes to consolidated financial statements.

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)


	Six Months Ended June 30,
	2004 *			2005
	(in thousands)
Operating Activities:
Net Income (Loss)	$	7,772		$	(12,817	)
Adjustments to reconcile to net cash provided by operations:

Depreciation, depletion and amortization		31,002			38,954
Deferred income taxes		5,666			(6,643	)
Impairment, dry hole costs and abandonment expense		281			43,675
Stock compensation and other non-cash charges		2,319			1,405
Amortization of deferred financing costs		207			563
Gain on sale of properties		(2,335	)		(1,465	)
Change in current assets and liabilities:
Accounts receivable		(6,476	)		5,401
Prepayments and other current assets		(1,398	)		(370	)
Accounts payable, accrued and other liabilities		(1,817	)		(3,112	)
Amounts payable to oil and gas property owners		1,404			1,476
Production taxes payable		6,221			7,606

Net cash provided by operating activities		42,846			74,673
Investing Activities:
Additions to oil and gas properties		(80,553	)		(144,315	)
Additions of furniture, equipment and other		(914	)		(1,405	)
Proceeds from sale of properties		7,206			6,580

Net cash used in investing activities		(74,261	)		(139,140	)
Financing Activities:
Proceeds from debt		45,000			—
Principal payments on debt		(37,000	)		—
Proceeds from sale of common and preferred stock		33,760			290
Deferred financing costs and other		(1,554	)		(50	)

Net cash provided by financing activities		40,206			240

Increase (Decrease) in Cash and Cash Equivalents		8,791			(64,227	)
Beginning Cash and Cash Equivalents		16,034			99,926

Ending Cash and Cash Equivalents	$	24,825		$	35,699


*		As restated, see Note 10.

See notes to consolidated financial statements.

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

June 30, 2005

1. Organization

Bill Barrett Corporation (the “Company”, “we”, or “us”), a Delaware corporation, is an independent oil and gas company engaged in the acquisition, exploration, development and production of natural gas and crude oil. Since its inception on January 7, 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States. On December 9, 2004, our Registration Statements on Form S-1 (SEC File Nos. 333-114554, 333-121128 and 333-121142) concerning our initial public offering (“IPO”) were declared effective by the Securities and Exchange Commission (the “SEC”). The offering was completed on December 15, 2004 and the underwriters purchased a total of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. We received net proceeds of $347 million after deducting underwriting fees and other offering costs.

2. Summary of Significant Accounting Policies

Basis of Presentation.The accompanying unaudited consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information. Pursuant to the rules and regulations of the SEC, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of June 30, 2005, the results of operations for the six and three months ended June 30, 2004 and 2005, and cash flows for the six months ended June 30, 2004 and 2005. Operating results for the six and three months ended June 30, 2005 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, these consolidated financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2004 previously filed with the SEC.

In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

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

Oil and Gas Properties.The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. Generally, if an exploratory well does not find proved reserves within one year following completion of drilling, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Consolidated Statements of Cash Flows pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs also are capitalized. Interest cost is capitalized as a component of property cost for exploration and development projects that require greater than six months to be readied for their intended use. To date, the Company has not capitalized any interest expense.

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

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

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 are summarized as follows (in thousands):


	As of			As of
	December 31, 2004			June 30, 2005
Proved properties	$	258,387		$	270,391
Wells and related equipment and facilities		216,335			299,924
Support equipment and facilities		38,890			53,258
Materials and supplies		3,598			7,362

Total proved oil and gas properties		517,210			630,935
Accumulated depreciation, depletion, amortization and impairment		(105,633	)		(179,686	)

Total proved oil and gas properties, net	$	411,577		$	451,249

Unevaluated properties	$	97,099		$	95,904
Wells and equipment in progress		40,506			66,479

Total unevaluated oil and gas properties, excluded from amortization	$	137,605		$	162,383

The following table reflects the net changes in capitalized exploratory well costs for the six months ended June 30, 2005 (in thousands):


Beginning of period	$	19,940
Additions to capitalized exploratory well costs pending the determination of proved reserves		81,649
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(41,761	)
Exploratory well costs charged to impairment, dry hole costs and abandonment expense		(6,444	)

End of period	$	53,384

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

During the quarter ended June 30, 2005, the Company recognized non-cash impairment charges of $36.3 million related to its proved oil and gas properties in the Wind River Basin. This was primarily a result of production from existing and recently drilled wells in the Cooper Reservoir field declining more rapidly than anticipated due to interference caused

by infill drilling. Additionally, in the Talon field, production from exploratory wells was at a rate that did not justify the capital investment in those wells. The carrying amount of these properties was adjusted to fair value, which was determined based upon the present value of future cash flows, net of operating and development costs, discounted at various rates consistent with current market conditions at which similar types of properties are being traded.

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

Stock-Based Compensation.In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (revised 2004),Share-Based Payment(“SFAS No. 123R”), which revises SFAS No. 123,Accounting for Stock-Based Compensation,and supersedes Accounting Principles Board (“APB”) Opinion No. 25,Accounting for Stock Issued to Employees.SFAS No. 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods and services, focusing primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. It also addresses transactions in which an entity incurs liabilities in exchange for goods and services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. We early adopted the provisions of the new standard effective October 1, 2004. Prior to the adoption of SFAS No. 123R, we used the intrinsic value method in accordance with APB Opinion No. 25 and the disclosure provisions of SFAS No. 123.

For awards granted while we were a nonpublic company (those granted prior to April 16, 2004, the date of which is defined by SFAS No. 123R as the date we became a public company as a result of making a filing with a regulatory agency in preparation for the sale of equity securities in a public market), we adopted SFAS No. 123R using the prospective transition method. Under the prospective transition method, we continue to account for awards granted prior to becoming a public company using the minimum value method described under APB Opinion No. 25. Accordingly, zero compensation expense was recorded upon adoption of SFAS No. 123R for those awards. Additionally, the calculated fair value of those awards using the minimum value method is not comparable to those options granted subsequent to April 16, 2004, for which a fair-value-based method was used.

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

During the six months ended June 30, 2005, the Company granted 169,500 options to purchase shares of common stock with a weighted average exercise price of $30.18 per share and 5,352 nonvested equity shares of common stock. For the three months ended June 30, 2005, the Company granted 114,000 options to purchase shares of common stock with a weighted average exercise price of $29.37 per share. Included within general and administrative expense is non-cash stock based compensation related to option and nonvested equity share awards of $2.2 million and $1.5 million for the six months ended June 30, 2004 and 2005, respectively, and $1.0 million and $0.8 million for the three months ended June 30, 2004 and 2005, respectively.

Reclassifications.The Company reclassified $2.8 million related to geologic, geophysical and other exploration costs from cash used in investing activities to cash used in operating activities in the statements of cash flows for the six months ended June 30, 2004 to conform to the current year presentation.

The Company reclassified $0.3 million and $0.3 million from exploration expense to impairment, dry hole costs and abandonment expense in the statements of operations for the three and six months ended June 30, 2004, respectively, to conform to the current year presentation.

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

On April 4, 2005, the FASB issued FASB Staff Position (“FSP”) FAS 19-1Accounting for Suspended Well Costs. This staff position amends SFAS No. 19 and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires the annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The guidance in this FSP is required to be applied to the first reporting period beginning after April 4, 2005 on a prospective basis to existing and newly capitalized exploratory well costs. The Company provided the disclosure requirements of this FSP in its Annual Report on Form 10-K for the year ended December 31, 2004 and will continue to provide the disclosures required by the FSP in future filings with the SEC.

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

3. Per Share Data and Earnings Per Share

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

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

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

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

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


	Three months ended June 30,						Six months ended June 30,
	2004			2005			2004			2005
Net income (loss)	$	3,035		$	(15,871	)	$	7,772		$	(12,817	)
Less cumulative dividends on preferred stock		(4,805	)		n/a			(9,338	)		n/a

Net income to be allocated		(1,770	)		(15,871	)		(1,566	)		(12,817	)
Less allocation of undistributed earnings to participating preferred stock		—			n/a			—			n/a

Net income attributable to common stock		(1,770	)		(15,871	)		(1,566	)		(12,817	)
Adjustments to net income for dilution		—			—			—			—

Net income adjusted for the effect of dilution	$	(1,770	)	$	(15,871	)	$	(1,566	)	$	(12,817	)

Basic weighted-average common shares outstanding in period		1,398			43,187			1,326			43,136
Add dilutive effects of stock options		—			—			—			—
Add dilutive effects of common stock subject to restrictions		—			—			—			—

Diluted weighted-average common shares outstanding in period		1,398			43,187			1,326			43,136

Basic loss per common share	$	(1.27	)	$	(0.37	)	$	(1.18	)	$	(0.30	)

Diluted loss per common share	$	(1.27	)	$	(0.37	)	$	(1.18	)	$	(0.30	)

4. Supplemental Disclosures of Cash Flow Information:

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


	Six Months Ended June 30,
	2004			2005
Cash paid for interest	$	1,175		$	401
Supplemental disclosures of noncash investing and financing activities:
Preferred stock issued for payment of oil and gas properties		322			—
Preferred stock returned in settlement to terminate an exploration agreement		(500	)		—
Changes in current assets and liabilities that are reflected in investing activities		(3,165	)		5,753
Net change in asset retirement obligations		1,244			866

5. Derivative Instruments and Hedging Activities.

The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its natural gas and oil production by reducing its exposure to price fluctuations. The Company accounts for such activities pursuant to SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the Consolidated Balance Sheets as assets or liabilities.

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

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

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

The Company was a party to various swap contracts for natural gas based on Northwest Pipeline Rocky Mountains (“NORRM”) and Colorado Interstate Gas Rocky Mountains (“CIGRM”) indexes during the six months ended June 30, 2004 and 2005. As a result, the Company recognized a reduction of natural gas production revenues related to these contracts of $2.5 million and $1.5 million for the quarters ended June 30, 2004 and 2005, respectively, and $4.8 million and $2.2 million for the six months ended June 30, 2004 and 2005, respectively. The Company was a party to various swap contracts for oil based on a West Texas Intermediate (“WTI”) index recognizing a reduction to oil production revenues related to these contracts of $0.7 million in the three months ended June 30, 2005 and $1.2 million in the six month ended June 30, 2005. There were no swap contract settlements for oil during the six months ended June 30, 2004. As the underlying prices in the Company’s hedge contracts were consistent with the indices used to sell its natural gas and oil, no ineffectiveness was recognized related to its hedge contracts for the three and six months ended June 30, 2004 and 2005.

As of August 1, 2005, we had the following commodity swap contracts in place to hedge cash flow and reduce the impact of natural gas and oil price fluctuations:

Average

Volume

Quantity

Fixed

Index

Contract

Product

Per Day

Type

Price

Price(1)

Period

Natural gas

10,000

MMBtu

5.05

NORRM

1/1/2005 — 12/31/2005

Natural gas

10,000

MMBtu

5.27

NORRM

1/1/2005 — 12/31/2005

Oil

100

Bbls

32.96

WTI

1/1/2005 — 12/31/2005

Oil

100

Bbls

34.05

WTI

1/1/2005 — 12/31/2005

Oil

100

Bbls

36.12

WTI

1/1/2005 — 12/31/2005

Oil

100

Bbls

36.00

WTI

1/1/2005 — 12/31/2005


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

As of August 1, 2005, we had the following cashless collars (purchased put options and written call options) in order to hedge a portion of our 2005, 2006, and 2007 natural gas and oil production. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production.

Average

Volume

Quantity

Floor-Ceiling

Index

Contract

Product

Per Day

Type

Pricing

Price(1)

Period

Natural gas

10,000

MMBtu

4.75-7.00

NORRM

1/1/2005-12/31/2005

Natural gas

5,000

MMBtu

4.75-6.75

NORRM

1/1/2005-12/31/2005

Natural gas

10,000

MMBtu

4.75-7.10

NORRM

1/1/2005-12/31/2005

Natural gas

5,000

MMBtu

5.00-6.46

CIGRM

4/1/2005-10/31/2005

Natural gas

5,000

MMBtu

5.25-10.60

CIGRM

8/1/2005-12/31/2005

Oil

400

Bbls

45.00-55.25

WTI

4/1/2005-12/31/2005

Natural gas

5,000

MMBtu

4.75-6.05

NORRM

1/1/2006-12/31/2006

Natural gas

5,000

MMBtu

4.75-6.18

NORRM

1/1/2006-12/31/2006

Natural gas

15,000

MMBtu

4.75-6.21

NORRM

1/1/2006-12/31/2006

Natural gas

10,000

MMBtu

5.00-8.10

NORRM

1/1/2006-12/31/2006

Natural gas

4,000

MMBtu

5.25-12.05

CIGRM

1/1/2006-12/31/2006

Oil

700

Bbls

42.00-50.20

WTI

1/1/2006-12/31/2006

Oil

Bbls

50.00-81.10

WTI

1/1/2006-12/31/2006

Oil

600

Bbls

50.00-78.15

WTI

1/1/2007-12/31/2007

Natural gas

29,000

MMBtu

5.25-10.22

CIGRM

1/1/2007-12/31/2007

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

At June 30, 2005, the estimated fair value of contracts designated and qualifying as cash flow hedges under SFAS No. 133 was a liability of $24.4 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 prices, the net amount of existing unrealized after-tax loss as of June 30, 2005 to be reclassified from accumulated other comprehensive loss to net income (loss) in the next twelve months would be $10.6 million. Of this amount, $4.3 million pertains to swap contracts, and $6.3 million pertains to collar contracts. In regards to the collar contracts, no amounts will be reclassified if actual prices received fall between the floor and ceiling prices as set forth in the contracts. The Company anticipates that all original forecasted transactions will occur by the end of the originally specified time periods.

6. Asset Retirement Obligations

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


Beginning of period	$	11,806
Liabilities incurred		930
Liabilities settled		(30	)
Accretion expense		472
Revisions to estimate		(34	)

End of period	$	13,144

7. Income Taxes

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return

consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates.

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

At June 30, 2005, the Company’s balance sheet reflected net deferred tax assets of $18.8 million, of which $9.0 million pertains to the tax effects of derivative instruments reflected in other comprehensive (loss) income. The Company has not recognized a valuation allowance against its net deferred tax assets because it believes that it is more likely than not that the net deferred tax assets will be realized on future income tax returns, primarily from the generation of future taxable income.

8. Stockholders’ Equity

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

The Company’s authorized capital structure consists of 75,000,000 shares of $0.001 par value preferred stock and 150,000,000 shares of $0.001 par value common stock. In October 2004, 150,000 shares of $0.001 par value preferred stock were designated as Series A Junior Participating Preferred Stock. At June 30, 2005, the Series A Junior Participating Preferred Stock was the Company’s only designated preferred stock, the remainder of authorized preferred stock being undesignated.

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

As of June 30, 2005, of the 1,800,548 common shares issued to founding management and employees, 100% were dollar vested and 1,647,686 shares were time vested. The remaining time vesting will occur ratably through January 2006.

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

9.Accumulated Other Comprehensive Loss

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


				Tax			Net of
	Gross			Effect			Tax
				(in thousands)
Accumulated other comprehensive loss — December 31, 2004	$	(5,665	)	$	2,096		$	(3,569	)
Change in fair value of hedges		(22,117	)		8,183			(13,934	)
Reclassification adjustment for realized losses on hedges included in net loss		3,415			(1,263	)		2,152

Accumulated other comprehensive loss — June 30, 2005	$	(24,367	)	$	9,016		$	(15,351	)

10. Restatement of Consolidated Financial Statements

Subsequent to filing the Company’s amendment to its Registration Statement on Form S-1/A on August 31, 2004, management determined that, for financial reporting purposes, the amount of stock-based compensation expense related to restricted common stock issued to management during the year ended 2002 at the formation of the Company (“Management Stock”), Series B preferred stock purchased by employees during the years ended 2003 and 2004 at less than fair value for financial reporting purposes, and options granted in years ended 2002, 2003 and 2004 under our 2002 Stock Option Plan and 2003 Stock Option Plan should be adjusted to reflect an increase in intrinsic value received as a result of upward adjustments to the estimated fair value of our common stock. As a result, the Company’s consolidated financial statements for the six months ended June 30, 2004 have been restated from the amounts previously reported in the Registration Statement on Form S-1/A to reflect the changes in stock-based compensation expense. A summary of the significant effects of the restatement is as follows:


	For the Six Months
	Ended June 30, 2004
	(as previously		(as restated)
	reported)
STATEMENT OF OPERATIONS
General and administrative expense	$	8,975	$	10,808
Operating income		16,526		14,693
Income before Income Taxes		15,271		13,438
Net Income		9,605		7,772
Net Income (Loss) Attributable to Common Stock		24		(1,566	)
Basic Net Income per Common Share		0.00		(1.18	)
Diluted Net Income per Common Share		0.00		(1.18	)

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

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

Overview

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

Results of Operations

The financial information with respect to the six and three months ended June 30, 2004 and 2005 that is discussed below is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2005


	Six Months Ended				Increase (Decrease)
	June 30,
	2004		2005		Amount			Percent
	(in thousands)
Operating Results:
Revenues
Oil and gas production revenues	$	76,442	$	104,647	$	28,205			37	%
Other income		2,398		1,708		(690	)		(29	%)
Operating Expenses
Lease operating expense		7,187		8,894		1,707			24	%
Gathering and transportation expense		2,491		5,604		3,113			125	%
Production tax expense		9,565		13,029		3,464			36	%
Exploration expense		2,813		2,665		(148	)		(5	%)
Impairment, dry hole costs and abandonment expense		281		43,675		43,394		nm		*
Depreciation, depletion and amortization		31,002		38,954		7,952			26	%
General and administrative		10,808		13,033		2,225			21	%

Total operating expenses	$	64,147	$	125,854	$	61,707			96	%
Production Data:
Natural gas (MMcf)		14,060		15,526		1,466			10	%
Oil (MBbls)		228		250		22			10	%
Combined volumes (MMcfe)		15,428		17,026		1,598			10	%
Daily combined volumes (Mmcfe/d)		85		94		9			11	%
Average Prices (includes effects of hedges):
Natural gas (per Mcf)	$	4.88	$	6.04	$	1.16			24	%
Oil (per Bbl)		34.53		43.70		9.17			27	%
Combined (per Mcfe)		4.95		6.15		1.20			24	%
Average Costs (per Mcfe):
Lease operating expense	$	0.47	$	0.52	$	0.05			11	%
Gathering and transportation expense		0.16		0.33		0.17			106	%
Production tax expense		0.62		0.77		0.15			24	%
Depreciation, depletion and amortization		2.01		2.29		0.28			14	%
General and administrative		0.70		0.77		0.07			10	%


*		Not meaningful.

Production Revenues.Production revenues increased from $76.4 million for the six months ended June 30, 2004 to $104.6 million for the current year period due to both an increase in production and increases in natural gas and oil prices. Price increases added approximately $18.4 million of production revenues and production increases from the development of existing properties added approximately $9.8 million of production revenues, after natural production declines so that our new production more than offset natural production declines.

On a mcf equivalent basis, total production volumes for the six months ended June 30, 2005 increased 10% from total production for the prior year period. Additional information concerning production is in the following table.


	Six Months Ended June 30, 2004						Six Months Ended June 30, 2005
	Oil		Natural Gas		Total		Oil		Natural Gas		Total

	(MBbls)		(MMcf)		(MMcfe)		(MBbls)		(MMcf)		(MMcfe)
Wind River Basin		58		9,203		9,551		41		6,388		6,634
Uinta Basin		4		2,606		2,630		2		3,016		3,028
Powder River Basin		—		2,153		2,153		—		4,260		4,260
Piceance Basin*		n/a		n/a		n/a		17		1,779		1,881
Williston Basin		152		88		1,000		177		71		1,133
Other		14		10		94		13		12		90

Total		228		14,060		15,428		250		15,526		17,026


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

The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields that occurred in late 2004 and the first half of 2005, and on which the rate of exploration and development activities was reduced in late 2004. The production increase in the Uinta Basin is due to exploration and development activities in both the West Tavaputs and Hill Creek fields. The production increase in the Powder River Basin reflects the success of our development activities. The production increase in the Williston is principally due to continued exploration and development activities on our properties in this basin. The production increase in the Piceance Basin is a result of the acquisition made in September 2004. The 2005 production in the Piceance Basin includes 116 MMcf of a gas balancing settlement pertaining to production in the last quarter of 2004.

Hedging Activities.During the six months ended June 30, 2004, approximately 37% of our natural gas volumes and no oil volumes were hedged, resulting in a reduction in revenues of $4.8 million. During the six months ended June 30, 2005, approximately 52% of our natural gas volumes and 44% of our oil volumes were hedged, resulting in a reduction in revenues of $3.4 million.

Lease Operating Expense and Gathering and Transportation Expense.Our lease operating expense increased from $0.47 per Mcfe in the first six months of 2004 to $0.52 per Mcfe in the current year period, and our gathering and transportation expense increased from $0.16 per Mcfe in the first six months of 2004 to $0.33 per Mcfe in the current year period. The increase in lease operating expenses is primarily due to workovers of $0.5 million in the Hill Creek field in the Uinta Basin and Cave Gulch field in the Wind River Basin, equipment rentals and diesel fuel costs associated with a temporary electrical power supply for new wells in the Powder River Basin of $0.8 million and declining production in our Cave Gulch, Cooper Reservoir and Wallace Creek fields in the Wind River Basin without a corresponding decrease in fixed costs associated with operating these gas wells. The increase in gathering and transportation expense is principally attributable to an increase of $2.8 million for the CBM properties in the Powder River Basin relating to increased third party charges for compressor fuel, the relative increase in production in

the Powder River Basin, which is a higher gathering cost area, compared to the first half of 2004, and firm transportation fees we commenced incurring in the first quarter of 2005. We have entered into long-term firm transportation contracts to guarantee capacity on major pipelines to avoid production curtailments that may arise due to limited pipeline capacity. Generally, gathering contracts with third parties require we pay current market prices for compressor fuel consistent with the increase in realized prices on the gas we produce.

Production Tax Expense.Production taxes as a percentage of natural gas and oil sales before hedging losses of $4.8 million and $3.4 million were 11.8% and 12.1% for the six months ended June 30, 2004 and 2005, respectively. The slight increase in tax rate from the prior year period is the result of an increased estimate in the first quarter of 2005 related to the Ute Tribe Severance Tax on properties in the Uinta Basin. Production taxes are primarily based on the wellhead values of production and vary across the different areas that we operate. Total production taxes increased as a result of higher production revenues, primarily due to higher prices in the six months ended June 30, 2005 compared to the prior year period.

Exploration Expense.Exploration costs decreased from $2.8 million in the first six months of 2004 to $2.7 million in the current year period. The costs for the six months ended June 30, 2004 include $1.1 million and $0.9 million for seismic programs in the DJ Basin and Wind River Basins, respectively, along with $0.8 million for delay rentals and other costs. The costs for the six months ended June 30, 2005 include $1.9 million for seismic programs, principally in the Wind River Basin, and $0.8 million for delay rentals and other costs.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense increased from $0.3 million during the first six months of 2004 to $43.7 million during the current year period. For the six months ended June 30, 2004 dry hole costs were $0.1 million, abandonments were $0.2 million, and impairment expense was zero. For the six months ended June 30, 2005 dry hole costs were $6.4 million for dry holes in the Wind River, Green River, and Uinta Basins, abandonments were $1.0 million, and impairment expense was $36.3 million. Under successful efforts accounting, 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 through a charge to impairment expense. During the quarter ended June 30, 2005, production from existing and recently drilled infill wells in the Cooper Reservoir field declined more rapidly than anticipated indicating well interference and limited downspacing opportunities. In the Talon field, production from exploratory wells was at a rate that does not justify the capital investment. The impairment expense in the current year period is the result of a $29.5 million impairment charge in the Cooper Reservoir field and $6.8 million impairment charge in the Talon field, both of which are located in the Wind River Basin.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense was $39.0 million for the six months ended June 30, 2005 compared to $31.0 million for the prior year period. Of the increase, $3.2 million is due to the 10% increase in production and $4.8 million is due to an increased depletion rate for the first half of 2005 production. During the six months ended June 30, 2004, the weighted average depletion rate was $2.01 per Mcfe. In the six months ended June 30, 2005, the weighted average depletion rate was $2.29 per Mcfe. Under successful efforts accounting, depletion expense is separately computed for each producing area. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a depletion rate for current production. Between the six months ended June 30, 2004 and the current year period, the Company’s cost of finding oil and gas reserves in certain areas yielded an overall higher depletion rate for the first six months of 2005 compared to the prior year period. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

General and Administrative Expense.General and administrative expense increased $2.2 million from $10.8 million in the six months ended June 30, 2004 to $13.0 million in the current year period. This increase was primarily due to increased personnel required for our capital program and production levels. As of June 30, 2005, we had 118 full time employees in our corporate office compared to 88 as of June 30, 2004. General and administrative expense includes non-cash charges for stock based compensation, including $2.2 million in the first six months of 2004 and $1.5 million in the current year period. The decrease in charges for non-cash compensation was due to a stock based compensation charge related to the vesting of common stock in January and May of 2004. On a per unit production basis, general and

administrative expense increased from $0.70 per Mcfe in the first six months of 2004 to $0.77 per Mcfe in the current year period. Our capital budget relative to our production levels is high and requires an appropriate number of personnel and related costs to prudently manage our capital expenditure program. Until our capital expenditure program significantly increases our production levels, we expect general and administrative expense per unit of production to remain at current levels.

Interest Income.Interest income increased $0.9 million to $1.0 million during the six months ended June 30, 2005 from $0.1 million during the prior year period. This increase is a result of interest earned on an average cash and short-term investment balance of $75.7 million for the six months ended June 30, 2005 compared to an average balance of $21.5 million for the prior year period. The increased investment balance resulted primarily from the receipt of the net proceeds from our initial public offering in December 2004.

Interest Expense.Interest expense decreased $0.4 million to $1.0 million in the six months ended June 30, 2005 from $1.4 million in the prior year period. Interest expense in the first half of 2005 is comprised primarily of amortization of deferred financing costs and payment of debt commitment fees. Interest expense in the first half of 2004 is comprised of interest of $1.0 million on a weighted average outstanding balance of $62.8 million under our credit facility and $0.4 million of amortization of deferred financing costs and payment of debt commitment fees. We had no outstanding indebtedness under our credit facility during the six months ended June 30, 2005 as a result of paying down our revolving credit facility with the net proceeds from our initial public offering in December 2004.

Income Tax Expense.Our effective tax rate was 42% and 34% in the six months ended June 30, 2004 and 2005, respectively. For both the 2004 and 2005 periods, the Company recorded stock-based compensation expense under APB 25 and FAS 123R that is not deductible for income tax purposes. Due to our net income position for the six months ended June 30, 2004, these permanent differences were not deductible for income tax purposes, thereby increasing our effective tax rate. However, for the six months ended June 30, 2005, the Company was in a net loss position and was not able to recognize the benefit of non-deductible stock-based compensation expense for tax purposes, thereby decreasing our effective tax rate. All of our income tax provisions and benefits are deferred. Due to the tax deductions being created by our drilling activities, we expect that we will not incur cash tax liabilities for at least the next year.

Net Income.We generated a net loss of $12.8 million in the six months ended June 30, 2005 compared to net income of $7.8 million in the prior year period. The primary reasons for the decrease in results were non-cash impairment charges of $36.3 million and an increase in dry hole costs and abandonments of $7.1 million. This increase in impairment, dry hole costs and abandonment expense was offset by an increase in operating income, excluding impairment, dry hole costs and abandonment expense, of $9.2 million, an increase in other income of $1.3 million, and an increase in income tax benefit of $12.3 million.

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


	Three Months Ended				Increase (Decrease)
	June 30,
	2004		2005		Amount			Percent
	(in thousands)
Operating Results:
Revenues
Oil and gas production revenues	$	40,450	$	53,962	$	13,512			33	%
Other income		1,949		487		(1,462	)		(75	%)
Operating Expenses
Lease operating expense		4,174		4,413		239			6	%
Gathering and transportation expense		1,339		2,881		1,542			115	%
Production tax expense		5,189		6,419		1,230			24	%
Exploration expense		1,334		684		(650	)		(49	%)
Impairment, dry hole costs and abandonment expense		278		38,990		38,712		nm*


	Three Months Ended				Increase (Decrease)
	June 30,
	2004		2005		Amount			Percent
	(in thousands)
Depreciation, depletion and amortization		18,580		19,177		597			3	%
General and administrative		5,532		6,656		1,124			20	%

Total operating expenses	$	36,426	$	79,220	$	42,794			117	%
Production Data:
Natural gas (MMcf)		7,360		7,813		453			6	%
Oil (MBbls)		119		124		5			4	%
Combined volumes (MMcfe)		8,074		8,557		483			6	%
Daily combined volumes (Mmcfe/d)		89		94		5			6	%

Average Prices (includes effects of hedges):
Natural gas (per Mcf)	$	4.91	$	6.20	$	1.29			26	%
Oil (per Bbl)		36.01		44.73		8.72			24	%
Combined (per Mcfe)		5.01		6.31		1.30			26	%
Average Costs (per Mcfe):
Lease operating expense	$	0.52	$	0.52	$	0.00			0	%
Gathering and transportation expense		0.17		0.34		0.17			100	%
Production tax expense		0.64		0.75		0.11			17	%
Depreciation, depletion and amortization		2.30		2.24		(0.06	)		(3	%)
General and administrative		0.69		0.78		0.09			13	%


*		Not meaningful.

Production Revenues.Production revenues increased from $40.5 million for the second quarter of 2004 to $54.0 million for the current year period due to both an increase in production and increases in natural gas and oil prices. Price increases added approximately $10.5 million of production revenues and production increases from the development of existing properties added approximately $3.0 million of production revenues, after natural production declines so that our new production more than offset natural production declines.

On a mcf equivalent basis, total production volumes for the second quarter of 2005 increased 6% from total production for the prior year period. Additional information concerning production is in the following table.


	Three Months Ended June 30, 2004						Three Months Ended June 30, 2005
	Oil		Natural Gas		Total		Oil		Natural Gas		Total

	(MBbls)		(MMcf)		(MMcfe)		(MBbls)		(MMcf)		(MMcfe)
Wind River Basin		29		4,661		4,835		20		3,112		3,232
Uinta Basin		2		1,505		1,517		1		1,520		1,526
Powder River Basin		—		1,144		1,144		—		2,183		2,183
Piceance Basin*		n/a		n/a		n/a		8		961		1,009
Williston Basin		81		45		531		88		34		562
Other		7		5		47		7		3		45

Total		119		7,360		8,074		124		7,813		8,557


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

The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields that occurred throughout 2004 and the first half of 2005, and on which the rate of development activities was reduced in late 2004. The production increase in the Powder River Basin reflects the success of our development activities. The production increase in the Piceance Basin is a result of the acquisition made in September 2004.

Hedging Activities.During the second quarter of 2004, we had approximately 35% of our natural gas volumes and no oil volumes hedged, incurring a reduction in revenues of $2.5 million. During the second quarter of 2005, we hedged approximately 55% of our natural gas volumes and 59% of our oil volumes, resulting in a reduction in revenues of $2.2 million.

Lease Operating Expense and Gathering and Transportation Expense.Our lease operating expense remained constant at $0.52 per Mcfe in the second quarter of 2005 as compared to the prior year period, and our gathering and transportation expense increased from $0.17 per Mcfe in the second quarter of 2004 to $0.34 per Mcfe in the current year period. The increase in gathering and transportation expense is principally attributable to an increase of $1.5 million for the CBM properties in the Powder River Basin relating to increased third party charges for compressor fuel, the relative increase in production in the Powder River Basin, which is a higher gathering cost area, compared to the second quarter of 2004, and firm transportation fees we commenced incurring in 2005. We have entered into long-term firm transportation contracts to guarantee capacity on major pipelines to avoid production curtailments that may arise due to limited pipeline capacity. Generally, gathering contracts with third parties require we pay current market prices for compressor fuel consistent with the increase in realized prices on the gas we produce.

Production Tax Expense.Production taxes as a percentage of natural gas and oil sales before hedging losses of $2.5 million and $2.2 million were 12.1% and 11.4% for the three months ended June 30, 2004 and 2005, respectively. Production taxes are primarily based on the wellhead values of production and vary across the different areas that we operate. The decrease in tax rate from the second quarter of 2004 to the current year period is primarily the result of increased production from our Piceance Basin properties in Colorado which has a lower tax rate than Wyoming, which is where most of our prior year production was located. Total production taxes increased as a result of higher production revenues, primarily due to higher prices in the second quarter of 2005 compared to the prior year period.

Exploration Expense.Exploration costs decreased from $1.3 million in the second quarter of 2004 to $0.7 million in the current year period. The costs for the second quarter of 2004 include $0.7 million for seismic programs in the Wind River Basin and $0.6 million for delay rentals and other costs. The costs for the second quarter of 2005 include $0.3 million for seismic programs and $0.4 million for delay rentals and other costs.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and impairment expense increased from $0.3 million during the second quarter of 2004 to $39.0 million during the current year period. For the second quarter of 2004 dry hole costs were $0.1 million, abandonments were $0.2 million, and impairment expense was zero. For the current year period dry hole costs were $2.0 million for dry holes in the Uinta Basin, abandonments were $0.7 million, and impairment expense was $36.3 million. Under successful efforts accounting, 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 through a charge to impairment expense. During the quarter ended June 30, 2005, production from existing and recently drilled infill wells in the Cooper Reservoir field declined more rapidly than anticipated indicating well interference and limited downspacing opportunities. In the Talon field, production from exploratory wells was at a rate that does not justify the capital investment. The impairment expense in the current year period is the result of a $29.5 million impairment charge in the Cooper Reservoir field and $6.8 million impairment charge in the Talon field both of which are located in the Wind River Basin.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense was $19.2 million for the second quarter of 2005 compared to $18.6 million for the prior year period. The increase of $0.6 million is the result of an increase of $1.1 million related to a 6% increase in production in the second quarter of 2005 as compared to the prior year period offset by a decrease of $0.5 million based on lower depletion rates. During the second quarter of 2004, the weighted average depletion rate was $2.30 per Mcfe compared to $2.24 per Mcfe for the current year period. Under successful efforts accounting, depletion expense is separately computed for each producing area. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a depletion rate for current production. Between the second quarter of 2004 and the current year period, the Company’s cost of finding oil and gas reserves in certain areas yielded an overall lower depletion rate for the second quarter of 2005 compared to the prior year period. The reduced depletion rate is principally due to production from the

Piceance basin that is at a lower rate than other major producing areas. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

General and Administrative Expense.General and administrative expense increased $1.1 million from $5.5 million in the second quarter of 2004 to $6.6 million in the current year period. The increase was primarily due to increased personnel required for our capital program and production levels. As of June 30, 2005, we had 118 full time employees in our corporate office compared to 88 as of June 30, 2004. General and administrative expense includes non-cash charges for stock based compensation, including $1.0 million in the second quarter of 2004 and $0.8 million in the current year period. The decrease in charges for non-cash compensation was due to stock based compensation charges related to the vesting of common stock in May 2004. On a per unit produced basis, general and administrative expense increased from $0.69 per Mcfe in the second quarter of 2004 to $0.78 per Mcfe in the second quarter of 2005. Our capital budget relative to our production levels is high and requires an appropriate number of personnel and related costs to prudently manage our capital expenditure program. Until our capital expenditure program significantly increases our production levels, we expect general and administrative expense per unit of production to remain at current levels.

Interest Expense.Interest expense decreased $0.3 million to $0.5 million in the three months ended June 30, 2005 from $0.8 million in the three months ended June 30, 2004. Interest expense in the 2005 first quarter is primarily comprised of amortization of deferred financing costs and payment of debt commitment fees. Interest expense in the first quarter of 2004 is comprised of interest of $0.6 million on a weighted average outstanding balance of $34.6 million under our credit facility and $0.2 million of amortization of deferred financing costs and payment of debt commitment fees and in that quarter period. We had no outstanding indebtedness under our credit facility during the second quarter of 2005.

Income Tax Expense.Our effective tax rate was 42% and 36% in the three months ended June 30, 2004 and 2005. For both the 2004 and 2005 periods, the Company recorded stock-based compensation expense under APB 25 and FAS 123R that is not deductible for income tax purposes. Due to our net income position for the three months ended June 30, 2004, these permanent differences were not deductible for income tax purposes, thereby increasing our effective tax rate. However, for the three months ended June 30, 2005, the Company was in a net loss position and was not able to recognize the benefit of non-deductible stock-based compensation expense for tax purposes, thereby decreasing our effective tax rate. All of our income tax provisions are deferred. Due to the tax deductions being created by our drilling activities, we expect that we will not incur cash tax liabilities for at least the next year.

Net Income.We generated a net loss of $15.9 million in the three months ended June 30, 2005 compared to net income of $3.0 million in the prior year period. The primary reasons for the decrease in results were non-cash impairment charges of $36.3 million and an increase in dry hole costs and abandonments of $2.4 million. The increase in impairment, dry hole costs and abandonment expense was offset by an increase in operating income, excluding impairment, dry hole costs and abandonment expense, of $8.0 million, an increase in other income of $0.7 million, and an increase in income tax benefit of $11.1 million.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been from sales and other issuances of securities, net cash provided by operating activities, a bank line of credit and a bridge loan to finance our September 2004 acquisition of properties in the Piceance Basin in Colorado. Our primary use of capital has been for the acquisition, development, and exploration of natural gas and oil properties. As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional acquisitions for cash, we may need to obtain additional equity or debt financing.

At June 30, 2005, our balance sheet reflected a cash balance of $35.7 million with no balance outstanding on our credit facility, principally as a result of completing our IPO on December 15, 2004, from which we received net proceeds of $347 million. On that date we repaid a $150 million bridge loan and paid down the outstanding balance of $123.2 million on our line of credit.

Cash Flow from Operating Activities

Net cash provided by operating activities was $42.8 million and $74.7 million for the six months ended June 30, 2004 and 2005, respectively. The increases 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 reduced cash flow from operations by $2.1 million for the six months ended June 30, 2004, but increased cash flow from operations by $11.0 million for the six months ended June 30, 2005.

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

To mitigate some of the potential negative impact on cash flow caused by changes in natural gas and oil prices and to comply with our credit agreement, we have entered into commodity swap and collar contracts to receive fixed prices for a portion of our natural gas and oil production. At August 1, 2005, we had in place natural gas and crude oil swap contracts and collars covering portions of our 2005, 2006, and 2007 production. Our natural gas and oil derivative financial instruments have been designated as cash flow hedges in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities,and are classified as either current or noncurrent liabilities in our Consolidated Balance Sheets based on scheduled delivery of the underlying production.

The table below provides the volumes associated with the swap contracts as of August 1, 2005.

Average

Volume

Quantity

Fixed

Index

Contract

Product

Per Day

Type

Price

Price (1)

Period

Natural gas

10,000

MMBtu

5.05

NORRM

1/1/2005-12/31/2005

Natural gas

10,000

MMBtu

5.27

NORRM

1/1/2005-12/31/2005

Oil

100

Bbls

32.96

WTI

1/1/2005-12/31/2005

Oil

100

Bbls

34.05

WTI

1/1/2005-12/31/2005

Oil

100

Bbls

36.12

WTI

1/1/2005-12/31/2005

Oil

100

Bbls

36.00

WTI

1/1/2005-12/31/2005

The table below provides the volumes associated with the collar contracts as of August 1, 2005.

Average

Volume

Quantity

Floor-Ceiling

Index

Contract

Product

Per Day

Type

Pricing

Price (1)

Period

Natural gas

10,000

MMBtu

4.75-7.00

NORRM

1/1/2005-12/31/2005

Natural gas

5,000

MMBtu

4.75-6.75

NORRM

1/1/2005-12/31/2005

Natural gas

10,000

MMBtu

4.75-7.10

NORRM

1/1/2005-12/31/2005

Natural gas

5,000

MMBtu

5.00-6.46

CIGRM

4/1/2005-10/31/2005

Natural gas

5,000

MMBtu

5.25-10.60

CIGRM

8/1/2005-12/31/2005

Oil

400

Bbls

45.00-55.25

WTI

4/1/2005-12/31/2005

Natural gas

5,000

MMBtu

4.75-6.05

NORRM

1/1/2006-12/31/2006

Natural gas

5,000

MMBtu

4.75-6.18

NORRM

1/1/2006-12/31/2006

Natural gas

15,000

MMBtu

4.75-6.21

NORRM

1/1/2006-12/31/2006

Natural gas

10,000

MMBtu

5.00-8.10

NORRM

1/1/2006-12/31/2006

Natural gas

4,000

MMBtu

5.25-12.05

CIGRM

1/1/2006-12/31/2006

Oil

700

Bbls

42.00-50.20

WTI

1/1/2006-12/31/2006

Oil

Bbls

50.00-81.10

WTI

1/1/2006-12/31/2006

Natural gas

29,000

MMBtu

5.25-10.22

CIGRM

1/1/2007-12/31/2007

Oil

600

Bbls

50.00-78.15

WTI

1/1/2007-12/31/2007


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

By removing the price volatility from a portion of our natural gas and oil production for 2005, 2006, and 2007 we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are creditworthy major financial institutions deemed by management as competent and competitive market makers.

Based on hedging contracts outstanding on June 30, 2005, our cash flow hedge positions from natural gas and oil derivatives had an estimated net pre-tax liability of $24.4 million recorded as both current and non-current liabilities, as appropriate. The Company will reclassify this amount to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected prices, the net amount of existing unrealized after-tax loss as of June 30, 2005 to be reclassified from accumulated other comprehensive loss to net income (loss) in the next twelve months would be $10.6 million. We anticipate that all original forecasted transactions will occur by the end of the originally specified time periods.

Capital Expenditures

Our capital expenditures were $83.4 million and $154.1 million for the six months ended June 30, 2004 and 2005, respectively. The total for the six month period of 2004 includes $10.9 million for acquisitions of properties, $68.5 million for drilling, development, exploration and exploitation (including related gathering and facilities, but excluding exploratory dry holes) of natural gas and oil properties, $3.1 million related to geologic and geophysical costs and exploratory dry holes, which are expensed under successful efforts accounting as exploration expense, and $0.9 million for furniture, fixtures and equipment. The total capital expenditures for the six month period of 2005 includes $15.0 million for the acquisition of properties, $127.7 million for drilling, development, exploration and exploitation (including related gathering and facilities, but excluding exploratory dry holes) of natural gas and oil properties, $10.0 million for geologic and geophysical costs and exploratory dry holes, and $1.4 million for furniture, fixtures and equipment.

Unevaluated properties increased $24.8 million to $162.4 million at June 30, 2005 from $137.6 million at December 31, 2004, principally from increases in uncompleted wells in progress resulting from increased development and exploratory drilling activity during the first half of 2005.

Our current capital budget, which is anticipated to change as the Company conducts activities throughout the year, is approximately $305 million for 2005, $149.0 million, net of costs recovered of $5.1 million related joint exploration agreements entered into, of which was incurred in the first six months of 2005. Of the $305 million capital budget, we plan to spend approximately $254 million for development activities, $49 million for exploration activities, with the remaining $2 million allocated to other activities. We are projecting that cash on hand, cash available from operating activities, borrowings from our credit facility, and proceeds from selling down a portion of our interests in certain properties will be sufficient to fund our 2005 capital budget. In addition to our 2005 capital budget, we plan to seek industry partners with whom we expect to enter into joint exploration agreements which would result in a reduction of approximately 30% to 60% of our working interest in a number of exploration projects principally in Wyoming, Montana and North Dakota. Proceeds from the joint exploration agreements will be used to accelerate and drill additional exploration wells not reflected in the 2005 capital budget. During the first half of 2005, we received proceeds of $6.6 million for sales of partial interests in three exploratory projects, one each in the DJ Basin, Wind River Basin and Williston Basin.

The amount and timing of capital expenditures is largely discretionary and within our control. If natural gas and oil prices decline to levels below our acceptable levels, we could choose to defer a portion of these planned 2005 capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and crews. Based upon current natural gas and oil price expectations for 2005, we anticipate that our operating cash flow and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for 2005. However, future cash flows are subject to a number of variables, including the level of natural gas and oil production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Financing Activities

Credit Facility.Our current bank line of credit provides a borrowing base of $200 million. This credit facility was entered into on February 4, 2004 and has a maturity of February 4, 2007. The credit facility was amended on September 1, 2004. The credit facility bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate, or LIBOR, plus applicable margins ranging from 1.25% to 3.75% or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 2.25%. We pay commitment fees ranging from 0.375% to 0.50% of the unused borrowing base. The credit facility is secured by natural gas and oil properties representing at least 85% of the value of our proved reserves and the pledge of all of the stock of our subsidiaries. The borrowing base includes a $25 million portion, referred to as the “Tranche B” portion, that allows the borrowing base to be greater than the typical borrowing base that would have been computed based on proved natural gas and oil reserves. The Tranche B portion of the borrowing base terminates on November 30, 2005. At June 30, 2005, there were no amounts outstanding under our revolving credit facility. On December 15, 2004, upon the completion of our IPO, we repaid the then outstanding balance of $123 million. None of the outstanding borrowings at the time of repayment were under the Tranche B portion of the borrowing base. For information concerning the effect of changes in interest rates on interest payments under this facility, see below, Item 3. “Quantitative and Qualitative Disclosure About Market Risk — Interest Rate Risks”.

The credit facility contains certain financial covenants, including a minimum current ratio and a minimum present value to total debt ratio. The credit facility also contains certain covenants that are based on what is defined in the credit facility as EBITDAX. The credit facility defines EBITDAX as our net income, subject to certain adjustments for the particular period plus the following expenses or charges to the extent deducted from net income during that period: interest, income taxes, depreciation, depletion, amortization, exploration and abandonment expenses and other similar non-cash charges and expenses, including stock based compensation and non-cash impairments of goodwill, minus all non-cash income added to net income, in each case, and without duplication, calculated after giving pro forma effect to acquisitions and dispositions during the period. These covenants require that our debt to EBITDAX ratio cannot exceed 4.0 to 1.0 until November 30, 2005 and 3.5 to 1.0 thereafter, and that our EBITDAX to interest ratio cannot be below 2.5 to 1.0. EBITDAX is not intended to represent net income (loss) as defined by generally accepted accounting principles in the United States, or GAAP, and such information should not be considered as an alternative to net income (loss), cash provided by operating activities or any other measure of performance prescribed by GAAP. The current ratio covenant states that our current ratio adjusted for the unused portion of the borrowing base and to eliminate certain non-cash assets and liabilities related to hedging activities must be greater than 1.0. The ratio of present value of natural gas and oil properties to total debt covenant states that the defined present value divided by the outstanding debt must not be less than 1.5. This ratio is calculated every six months based on engineering estimates calculated at commodity prices and present value factors determined by the lenders. We have complied with all financial covenants for all periods.

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

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

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2004 and the notes to the financial statements included in Item 1 of this Form 10-Q for a description of critical accounting policies and estimates.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. For the six months ended June 30, 2005, our income before income taxes would have changed by $1,085,000 for each $0.10 change in natural gas prices and $147,000 for each $1.00 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 August 1, 2005, we had hedges in place for approximately 18 Bcf, 14 Bcf, and 11 Bcf of natural gas production for 2005, 2006, and 2007 respectively, and approximately 256 thousand barrels (“MBbls”), 274 MBbls, and 219 MBbls of oil production for 2005, 2006, and 2007 respectively. These hedges are summarized in the table presented above under Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities”.

Price Swaps

Through various price swaps, we have fixed the price we will receive on a portion of our natural gas and oil production in 2005. The table presented above under Item 2. “ Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities” provides the volumes associated with these various arrangements as of August 1, 2005.

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

Price Collars

Through price collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas production in 2005, 2006, and 2007. The weighted average minimum, or floor, price we will receive in each of 2005 and 2006 is $4.75 and $4.82, respectively, per MMBtu for a Northwest Pipeline Corp. Rocky Mountain (“NORRM”) price and a $5.10 and $5.25 per MMBtu for a Colorado Interstate Gas Rocky Mountain price, respectively. The minimum price we will receive in 2007 is $5.25 per MMBtu for a Colorado Interstate Gas Rocky Mountain price. The weighted average maximum, or ceiling, price we will receive in each of 2005 and 2006 is $6.99 and $6.72 per MMBtu for a NORRM price, respectively, and $8.19 and $12.05 per MMBtu for a Colorado Interstate Gas Rocky Mountain price, respectively. We also have fixed a portion of our oil production in 2005, 2006, and 2007 based on a weighted average floor price of $45.00, $42.53, and $50.00 per Bbl for a West Texas Intermediate (“WTI”) price, respectively, and a weighted average maximum price of $55.25, $52.26, and $78.15 WTI, respectively. The price collars also allow us to share in upward price movements up to the ceiling prices referenced in the contracts. The table presented above under Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities” provides the volumes and floor and ceiling prices associated with these various arrangements as of August 1, 2005.

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

Interest Rate Risks

At June 30, 2005, we had no outstanding debt. Amounts drawn against our $200 million revolving credit facility will bear interest at floating rates as defined in the facility.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

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

Internal Control over Financial Reporting

In addition, the Company is continuously seeking to improve the efficiency and effectiveness of its internal controls. This results in periodic refinements to internal control processes throughout the Company. However, there has been no change in our internal controls over financial reporting that occurred during the quarter ended June 30, 2005 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

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

Use of Proceeds.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 were declared effective by the SEC. The offering was completed on December 15, 2004 and we received net offering proceeds of approximately $347.3 million. We used $149.3 million of the net proceeds of our initial public to repay the entire $150 million principal amount, net of refunds of certain fees, and accrued interest outstanding under our senior subordinated credit and guaranty agreement, or ‘‘bridge loan’’, and $123.2 million, including accrued interest, to repay the entire outstanding indebtedness under our revolving credit facility. The additional proceeds of approximately $77.1 million were used through the June 30, 2005 to fund general corporate purposes, including exploration and development activities, oil and gas reserve and leasehold acquisitions in the ordinary course of business, working capital and other general corporate purposes.

Item 3. Defaults Upon Senior Securities

Not applicable.

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

During the quarter ended June 30, 2005, the Company’s securities holders approved the election of directors at the annual meeting of stockholders held on May 19, 2005. The results of the balloting were as follows:


Name of Nominee	Votes For		Votes Withheld
Class I Directors (to hold office until the 2008 annual meeting of stockholders)
Fredrick J. Barrett		38,763,604		1,563,748
Henry Cornell		35,257,612		5,069,740
Michael E. Wiley		38,404,284		1,923,068

Class II Directors (to hold office until the 2006 annual meeting of stockholders)
James M. Fitzgibbons		38,593,359		1,733,993
Jeffrey A. Harris		38,563,840		1,763,512
Randy Stein		38,316,559		2,010,793

Class III Directors (to hold office until the 2007 annual meeting of stockholders)
William J. Barrett		38,684,492		1,642,860
Roger L. Jarvis		38,678,884		1,648,468
Philippe S.E. Schreiber		38,593,459		1,733,893

Item 5. Other Information

Not applicable.

Item 6. Exhibits and Reports on Form 8-K

Exhibits


Exhibit
Number		Description of Exhibits
3.1		Certificate of Incorporation of Bill Barrett Corporation, as amended to date. [Incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

3.2		Restated Certificate of Incorporation of Bill Barrett Corporation effective December 15, 2004. [Incorporated by reference to Exhibit 3.4 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]

3.3		Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.5 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]

3.4		Certificate of Designations of Series A Preferred Stock. [Incorporated by reference to Exhibit 3.2 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]

4.1		Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 3.2 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]

4.2		Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

4.3		Stockholders’ Agreement, dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

4.4		Rights Agreement dated as of December 15, 2004 by and between the Company and Mellon Investor Services LLC. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]

10.1(a)		Amended and Restated Credit Agreement, dated February 4, 2004, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.1(b)		First Amendment to Amended and Restated Credit Agreement dated as of September 1, 2004 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1(b) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.2		Stock Purchase Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 10.2 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.3		Purchase and Sale Agreement, dated March 27, 2002, between Williams Production RMT Company and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.4		Purchase and Sale Agreement, dated April 1, 2002, among Wasatch Oil & Gas, LLC, Wasatch Gas Gathering, LLC and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.4 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.5		Purchase and Sale Agreement, November 4, 2002, among, Intoil, Inc., Aratex Production Company and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.5 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.6		Purchase and Sale Agreement, dated January 1, 2003, among Independent Production Company, Inc., Sapphire Bay, LLC and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.6 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.7(a)*		Form of Indemnification Agreement dated April 15, 2004, between Bill Barrett Corporation and each of


Exhibit
Number		Description of Exhibits
		the directors and certain executive officers. [Incorporated by reference to Exhibit 10.10(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.7(b)*		Schedule of officers and directors party to Indemnification Agreements dated April 15, 2004 with Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.10(b) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.8*		Employment Letter Agreement, dated January 10, 2003, between Thomas B. Tyree, Jr. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.11 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.9*		Amended and Restated 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.12 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.10(a)*		Form of Tranche A Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.10(b)*		Form of Tranche B Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(b)to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.11*		2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.12*		Form of Stock Option Agreement for 2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.13		Form of Management Rights Agreement between Bill Barrett Corporation and certain investors. [Incorporated by reference to Exhibit 10.16 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.14		Regulatory sideletter, dated March 28, 2002, between J.P. Morgan Partners (BHCA), L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.17 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.15		Purchase and Sale Agreement effective July 1, 2004 among Calpine Corporation and Calpine Natural Gas, L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.18 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.16		Senior Subordinated Credit and Guaranty Agreement dated as of September 1, 2004 among Bill Barrett Corporation, as Borrower, Bill Barrett Properties Inc. and Bill Barrett Production Company, as Guarantors, various lenders, Goldman Sachs Credit Partners L.P., as sole lead arranger and Goldman Sachs Credit Partners L.P., as administrative agent. [Incorporated by reference to Exhibit 10.19 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.17*		Form of Change in Control Severance Protection Agreement for named executive officers. [Incorporated by reference to Exhibit 10.20 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.18*		2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.19*		Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.22 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.20*		Severance Plan. [Incorporated by reference to Exhibit 10.23 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

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

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


Exhibit
Number		Description of Exhibits
32.1		Section 1350 Certification of Chief Executive Officer

32.2		Section 1350 Certification of Chief Financial Officer


*		Indicates a management contract or compensatory plan or arrangement.

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: August 8, 2005	By:	/s/ William J. Barrett
		William J. Barrett
		Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)


Date: August 8, 2005	By:	/s/ Thomas B. Tyree, Jr.
		Thomas B. Tyree, Jr.
		Chief Financial Officer (Principal Financial Officer)


Date: August 8, 2005	By:	/s/ Robert W. Howard
		Robert W. Howard
		Executive Vice President-Finance and Investor Relations, and Treasurer (Principal Accounting Officer)

EXHIBIT INDEX


Exhibit
Number		Description of Exhibits
3.1		Certificate of Incorporation of Bill Barrett Corporation, as amended to date. [Incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

3.2		Restated Certificate of Incorporation of Bill Barrett Corporation effective December 15, 2004. [Incorporated by reference to Exhibit 3.4 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]

3.3		Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.5 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]

3.4		Certificate of Designations of Series A Preferred Stock. [Incorporated by reference to Exhibit 3.2 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]

4.1		Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 3.2 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]

4.2		Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

4.3		Stockholders’ Agreement, dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

4.4		Rights Agreement dated as of December 15, 2004 by and between the Company and Mellon Investor Services LLC. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]

10.1(a)		Amended and Restated Credit Agreement, dated February 4, 2004, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.1(b)		First Amendment to Amended and Restated Credit Agreement dated as of September 1, 2004 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1(b) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.2		Stock Purchase Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 10.2 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.3		Purchase and Sale Agreement, dated March 27, 2002, between Williams Production RMT Company and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.4		Purchase and Sale Agreement, dated April 1, 2002, among Wasatch Oil & Gas, LLC, Wasatch Gas Gathering, LLC and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.4 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.5		Purchase and Sale Agreement, November 4, 2002, among, Intoil, Inc., Aratex Production Company and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.5 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.6		Purchase and Sale Agreement, dated January 1, 2003, among Independent Production Company, Inc., Sapphire Bay, LLC and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.6 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.7(a)*		Form of Indemnification Agreement dated April 15, 2004, between Bill Barrett Corporation and each of


Exhibit
Number		Description of Exhibits
		the directors and certain executive officers. [Incorporated by reference to Exhibit 10.10(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.7(b)*		Schedule of officers and directors party to Indemnification Agreements dated April 15, 2004 with Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.10(b) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.8*		Employment Letter Agreement, dated January 10, 2003, between Thomas B. Tyree, Jr. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.11 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.9*		Amended and Restated 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.12 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.10(a)*		Form of Tranche A Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.10(b)*		Form of Tranche B Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(b)to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.11*		2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.12*		Form of Stock Option Agreement for 2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.13		Form of Management Rights Agreement between Bill Barrett Corporation and certain investors. [Incorporated by reference to Exhibit 10.16 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.14		Regulatory sideletter, dated March 28, 2002, between J.P. Morgan Partners (BHCA), L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.17 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.15		Purchase and Sale Agreement effective July 1, 2004 among Calpine Corporation and Calpine Natural Gas, L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.18 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.16		Senior Subordinated Credit and Guaranty Agreement dated as of September 1, 2004 among Bill Barrett Corporation, as Borrower, Bill Barrett Properties Inc. and Bill Barrett Production Company, as Guarantors, various lenders, Goldman Sachs Credit Partners L.P., as sole lead arranger and Goldman Sachs Credit Partners L.P., as administrative agent. [Incorporated by reference to Exhibit 10.19 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.17*		Form of Change in Control Severance Protection Agreement for named executive officers. [Incorporated by reference to Exhibit 10.20 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.18*		2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.19*		Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.22 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

10.20*		Severance Plan. [Incorporated by reference to Exhibit 10.23 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

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

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


Exhibit
Number		Description of Exhibits
32.1		Section 1350 Certification of Chief Executive Officer

32.2		Section 1350 Certification of Chief Financial Officer


*		Indicates a management contract or compensatory plan or arrangement.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Avg

Bill Barrett (BBG) Inactive 10-Q2005 Q2 Quarterly report

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