Bill Barrett (BBG) 10-Q 2007 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2007

OR

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

For the transition period from            to            

Commission file number 001-32367

BILL BARRETT CORPORATION

(Exact name of registrant as specified in its charter)

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

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

(303) 293-9100

(Registrant’s telephone number, including area code)

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

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

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

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

There were 44,653,522 shares of $0.001 par value common stock outstanding on August 6, 2007.

TABLE OF CONTENTS

PART I.		FINANCIAL INFORMATION	3
	Item 1.	Financial Statements	3
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	27
	Item 4.	Controls and Procedures	29
PART II.		OTHER INFORMATION	30
	Item 1.	Legal Proceedings	30
	Item 1A.	Risk Factors	30
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
	Item 3.	Defaults Upon Senior Securities	30
	Item 4.	Submission of Matters to a Vote of Security Holders	30
	Item 5.	Other Information	30
	Item 6.	Exhibits	31
SIGNATURES			33

2

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	December 31, 2006			June 30, 2007
	(in thousands, except share and per share data)
Assets:
Current Assets:
Cash and cash equivalents	$	41,322		$	28,128
Accounts receivable, net of allowance for doubtful accounts of $284 and $285 as of December 31, 2006 and June 30, 2007		56,280			31,521
Prepayments and other current assets		2,697			5,306
Derivative assets		38,208			37,089
Total current assets		138,507			102,044
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		1,114,536			1,240,605
Unevaluated oil and gas properties, excluded from amortization		202,946			250,093
Oil and gas properties held for sale, net, excluded from amortization		75,496			1,600
Furniture, equipment and other		14,696			13,700
		1,407,674			1,505,998
Accumulated depreciation, depletion, amortization and impairment		(369,079	)		(438,415	)
Total property and equipment, net		1,038,595			1,067,583
Deferred Financing Costs, Derivative Assets and Other		10,299			6,557
Total	$	1,187,401		$	1,176,184
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	69,519		$	71,554
Amounts payable to oil and gas property owners		13,933			15,656
Production taxes payable		22,348			26,828
Deferred income taxes and other current liabilities		13,995			13,551
Total current liabilities		119,795			127,589
Note Payable to Bank		188,000			132,000
Asset Retirement Obligations		29,224			30,986
Liabilities Associated with Assets Held for Sale		3,374			41
Deferred Income Taxes		89,730			101,513
Other Noncurrent Liabilities		881			878
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 44,141,453 and 44,654,271 shares issued and outstanding at December 31, 2006 and June 30, 2007, respectively, with 254,524 and 585,179 shares subject to restrictions, respectively		44			44
Additional paid-in capital		727,486			733,838
(Accumulated deficit) Retained earnings		(504	)		23,493
Accumulated other comprehensive income		29,371			25,802
Total stockholders’ equity		756,397			783,177
Total	$	1,187,401		$	1,176,184

See notes to condensed consolidated financial statements.

3

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2007			2006			2007
	(in thousands, except share and per share amounts)
Operating and Other Revenues:
Oil and gas production	$	78,213		$	89,096		$	175,711		$	185,978
Other		4,407			11,557			4,674			13,055
Total operating and other revenues		82,620			100,653			180,385			199,033
Operating Expenses:
Lease operating expense		7,371			14,246			14,193			23,086
Gathering and transportation expense		4,067			5,266			8,018			10,392
Production tax expense		6,525			5,139			14,779			10,696
Exploration expense		641			1,152			3,925			2,758
Impairment, dry hole costs and abandonment expense		6,944			3,274			7,088			6,872
Depreciation, depletion and amortization		33,041			42,785			63,808			81,858
General and administrative		8,416			10,178			16,910			19,346
Total operating expenses		67,005			82,040			128,721			155,008
Operating Income		15,615			18,613			51,664			44,025
Other Income and Expense:
Interest and other income		580			516			1,238			1,048
Interest expense		(2,884	)		(3,079	)		(4,355	)		(5,954	)
Total other income and expense		(2,304	)		(2,563	)		(3,117	)		(4,906	)
Income before Income Taxes		13,311			16,050			48,547			39,119
Provision for Income Taxes		5,101			6,192			18,203			15,077
Net Income	$	8,210		$	9,858		$	30,344		$	24,042
Net Income Per Common Share, Basic	$	0.19		$	0.22		$	0.70		$	0.55
Net Income Per Common Share, Diluted	$	0.19		$	0.22		$	0.69		$	0.54
Weighted Average Common Shares Outstanding, Basic		43,636,185			44,008,430			43,605,992			43,970,340
Weighted Average Common Shares Outstanding, Diluted		44,096,016			44,799,337			44,123,992			44,646,186

See notes to condensed consolidated financial statements.

4

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(UNAUDITED)

	Common Stock		Additional Paid-In Capital			Retained Earnings (Accumulated deficit)			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity			Comprehensive Income
	(in thousands)
Balance — December 31, 2005	$	44	$	721,145		$	(62,515	)	$	(5,180	)	$	(22,711	)	$	630,783
Exercise of options and shares exchanged for exercise and tax withholding		—		9,644			—			(5,059	)		—			4,585		$	—
Stock-based compensation		—		6,944			—			—			—			6,944			—
Retirement of treasury stock		—		(10,239	)		—			10,239			—			—			—
Other		—		(8	)		—			—			—			(8	)		—
Comprehensive income:
Net income		—		—			62,011			—			—			62,011			62,011
Effect of derivative financial instruments, net of tax		—		—			—			—			52,082			52,082			52,082
Total comprehensive income																		$	114,093
Balance — December 31, 2006	$	44	$	727,486		$	(504	)	$	—		$	29,371		$	756,397
Cumulative effect of adoption of Financial Accounting Standards Board Interpretation No. (FIN) 48		—		—			(45	)					—			(45	)		—
Exercise of options and shares exchanged for exercise and tax withholding		—		4,756			—			(3,187	)		—			1,569			—
Stock-based compensation		—		4,783			—			—			—			4,783			—
Retirement of treasury stock		—		(3,187	)		—			3,187			—			—			—
Comprehensive income:
Net income		—		—			24,042			—			—			24,042			24,042
Effect of derivative financial instruments, net of tax		—		—			—			—			(3,569	)		(3,569	)		(3,569	)
Total comprehensive income																		$	20,473
Balance — June 30, 2007	$	44	$	733,838		$	23,493		$	—		$	25,802		$	783,177

See notes to condensed consolidated financial statements.

5

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six Months Ended June 30,
	2006			2007
	(in thousands)
Operating Activities:
Net Income	$	30,344		$	24,042
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		63,808			81,858
Deferred income taxes		18,203			15,077
Impairment, dry hole costs and abandonment expense		7,088			6,872
Stock compensation and other non-cash charges		3,458			4,822
Amortization of deferred financing costs		334			233
Gain on sale of properties		(4,276	)		(11,996	)
Change in operating assets and liabilities:
Accounts receivable		18,415			24,759
Prepayments and other assets		1,336			(2,526	)
Accounts payable, accrued and other liabilities		(3,490	)		(1,311	)
Amounts payable to oil and gas property owners		(11,518	)		1,723
Production taxes payable		6,568			4,480
Net cash provided by operating activities		130,270			148,033
Investing Activities:
Additions to oil and gas properties, including acquisitions		(274,790	)		(188,125	)
Additions of furniture, equipment and other		(1,560	)		(2,114	)
Proceeds from sale of properties		6,863			82,844
Net cash used in investing activities		(269,487	)		(107,395	)
Financing Activities:
Proceeds from debt		128,000			22,000
Principal payments on debt		(15,495	)		(78,000	)
Proceeds from sale of common stock		1,652			2,252
Deferred financing costs and other		(1,120	)		(84	)
Net cash provided by (used in) financing activities		113,037			(53,832	)
Decrease in Cash and Cash Equivalents		(26,180	)		(13,194	)
Beginning Cash and Cash Equivalents		68,282			41,322
Ending Cash and Cash Equivalents	$	42,102		$	28,128

See notes to condensed consolidated financial statements.

6

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

June 30, 2007

1. Organization

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

2. Summary of Significant Accounting Policies

Basis of Presentation. The accompanying condensed 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 Securities and Exchange Commission (“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 condensed financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of June 30, 2007, our results of operations for the three and six months ended June 30, 2006 and 2007, and cash flows for the six months ended June 30, 2006 and 2007. Operating results for the three and six months ended June 30, 2007 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, the uncertainty of exploration and development drilling results, and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, these consolidated financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2006 previously filed with the SEC.

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

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

Oil and Gas Properties.The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and included within cash flows from investing activities in the Condensed Consolidated Statements of Cash Flows pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies. The costs of development wells are capitalized whether productive or nonproductive. Oil and gas lease acquisition costs also are capitalized. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use, and as a result, the Company had not capitalized any interest expense until the third quarter of 2006. The weighted average interest rate, including interest and commitment fees paid on the unused portion of our credit facility, amortization of deferred financing costs and the effects of interest rate hedges, used to capitalize interest for the three and six months ended June 30, 2007 was 7.2% and 7.1%, respectively. The Company capitalized interest costs of $0.5 million and $0.9 million, respectively, for the three and six months ended June 30, 2007.

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

7

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

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

The following table sets forth the net capitalized costs and associated accumulated depreciation, depletion and amortization, including impairments, relating to the Company’s natural gas and oil producing activities including net capitalized costs associated with properties held for sale as of June 30, 2007 of $0.6 million in total proved properties (excluded from amortization) and $1.0 million in total unevaluated properties, both of which are net of $2.5 million of accumulated depreciation, depletion, amortization and impairment (see Note 5 for further information on properties held for sale).

	As of December 31, 2006			As of June 30, 2007
	(in thousands)
Proved properties	$	346,619		$	343,217
Wells and related equipment and facilities		736,007			798,954
Support equipment and facilities		86,932			95,494
Materials and supplies		2,258			3,512
Total proved oil and gas properties		1,171,816			1,241,177
Accumulated depreciation, depletion, amortization and impairment		(363,587	)		(434,034	)
Total proved oil and gas properties, net	$	808,229		$	807,143
Unevaluated properties	$	139,689		$	132,307
Wells and equipment in progress		81,473			118,814
Total unevaluated oil and gas properties, excluded from amortization	$	221,162		$	251,121

Net changes in capitalized exploratory well costs for the six months ended June 30, 2007 are reflected in the following table (in thousands).

Beginning of period	$	69,596
Additions to capitalized exploratory well costs pending the determination of proved reserves		90,485
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(78,234	)
Exploratory well costs charged to dry hole costs and abandonment expense		(3,983	)
End of period	$	77,864

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

	June 30, 2007
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	59,585
Capitalized exploratory well costs that have been capitalized for a period greater than one year		18,279
End of period balance	$	77,864
Number of exploratory wells that have costs capitalized for a period greater than one year		168

As of June 30, 2007, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling include costs of $18.3 million. The majority of our exploratory wells that have been capitalized for a period greater than one year are located in the Powder River Basin. In this basin, we drill wells into various coal seams. In order to produce gas from the coal seams, a period of dewatering lasting from a few to 24 months, or in some cases longer, is required prior to obtaining sufficient gas production to justify capital expenditures for compression and gathering and to classify the reserves as proved.

In addition to our wells in the Powder River Basin, the Company has one well that has been capitalized for greater than one year in the Wind River Basin. This well could not be completed until the Bureau of Land Management (“BLM”) granted approval for the right of way to build a gathering line to an existing gas pipeline. The BLM has granted approval and the gathering line is currently in process.

8

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

With respect to the Company’s Tri-State exploration project in the DJ Basin, which we are currently in the process of selling and have classified as held-for-sale, the Company, based upon its fair value analysis, recognized a $2.3 million non-cash impairment charge in the current quarter.

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

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

For awards granted before we were a public company (i.e. 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 filing our Form S-1 registration statement with the SEC), we continue to use the minimum value method described under APB Opinion No. 25.

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

On May 9, 2007, the Compensation Committee of the Board of Directors of the Company approved a performance share program pursuant to the Company’s 2004 Stock Incentive Plan for the Company’s officers and other senior employees pursuant to which vesting of awards is contingent upon meeting various Company-wide performance goals. Upon commencement of the program and during each year of the program, the Compensation Committee will meet to approve target and stretch goals for certain operational or financial metrics that are selected by the Committee for the upcoming year and to determine whether metrics for the prior year have been met. These performance-based awards contingently vest over a period of one to four years, depending on the level at which the performance goals are achieved. Each year for four years, it is possible for between 25 percent and 50 percent of the original shares to vest based on meeting performance goals. Twenty five percent of the total grant will vest for metrics met at the target level. An additional 25 percent of the total grant will vest for performance met at the stretch level. If the actual results for a metric are between the target levels and the stretch levels, the vested number of shares will be adjusted on a linear basis of the actual results compared to the target and stretch goals. In any event, the total number of common shares that could become vested will not exceed the original number of performance shares granted. At the end of four years, any shares that have not vested will be forfeited. A total of 250,000 shares under the 2004 Stock Incentive Plan were set aside for this program.

For the year ending December 31, 2007, the performance goals include annual production growth (weighted at 30%), additions to our natural gas and oil reserves (weighted at 30%), finding and development costs (weighted at 30%), and general and administrative expenses (weighted at 10%). The weighting is determined by the Compensation Committee. Each metric is independent so that vesting can occur for one or more metrics even if the goals are not achieved for other metrics. Also for the year ending December 31, 2007, the Compensation Committee requires that a hurdle level for finding and development costs be met before any of the performance shares will vest. In future years of the program, the Compensation Committee may impose hurdle levels based on this or other metrics.

9

On May 9, 2007, the Company granted 226,300 performance-based nonvested equity shares of common stock at a grant date fair value of $37.21 per share pursuant to the performance share program. Compensation cost is recognized based upon the probability that the performance goals will be met. If such goals are not met, no compensation cost is recognized and any previously recognized compensation cost is reversed.

During the six months ended June 30, 2007, the Company granted 775,000 options to purchase shares of common stock with a weighted average exercise price of $30.99 per share, 174,000 nonvested equity shares of common stock and 226,300 performance-based nonvested equity shares of common stock. During the three months ended June 30, 2007, the Company granted 68,500 options to purchase shares of common stock with a weighted average exercise price of $35.46 per share, 15,000 nonvested equity shares of common stock and 226,300 performance-based nonvested equity shares of common stock. We recorded non-cash stock-based compensation related to option, nonvested equity share, and performance-based nonvested equity share awards of $1.5 million and $2.5 million for the three months ended June 30, 2006 and 2007, respectively, and $3.2 million and $4.4 million for the six months ended June 30, 2006 and 2007, respectively, including $0.6 million associated with the newly approved and granted performance-based nonvested equity shares. As of June 30, 2007, there were $25.2 million of total compensation costs related to grants of nonvested stock options and nonvested equity shares of common stock grants that are expected to be recognized over a weighted-average period of 2.8 years.

Beginning with the quarter ended June 30, 2007, directors may elect to receive their annual retainer and meeting fees in the form of our common stock issued pursuant to the Company’s 2004 Stock Incentive Plan. After each quarter, shares with a value equal to the fees payable for that quarter, calculated using the closing price on the last trading day before the end of the quarter, will be delivered to each outside director who elected before that quarter to receive shares in payment of the director fees. For the three months ended June 30, 2007, the Company issued 1,320 shares of common stock for payment of the director fees and recognized $0.05 million of non-cash stock-based compensation associated with those shares.

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

3. Per Share Data and Earnings Per Share

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

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

	Three months ended June 30,				Six months ended June 30,
	2006		2007		2006		2007
Net income	$	8,210	$	9,858	$	30,344	$	24,042
Adjustments to net income for dilution		—		—		—		—
Net income adjusted for the effect of dilution	$	8,210	$	9,858	$	30,344	$	24,042
Basic weighted-average common shares outstanding in period		43,636		44,008		43,606		43,970
Add dilutive effects of stock options and nonvested equity shares of common stock		460		791		518		676
Diluted weighted-average common shares outstanding in period		44,096		44,799		44,124		44,646
Basic income per common share	$	0.19	$	0.22	$	0.70	$	0.55
Diluted income per common share	$	0.19	$	0.22	$	0.69	$	0.54

10

4. Supplemental Disclosures of Cash Flow Information

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

	For six months ended June 30,
	2006			2007
Cash paid for interest	$	3,806		$	6,352
Cash paid for income taxes		—			152
Supplemental disclosures of non-cash investing and financing activities:
Retirement of treasury stock		(10,066	)		(3,187	)
Exchange of oil and gas properties for equipment and other properties		105			—
Adjustment of deferred tax liability – Powder River Basin properties acquisition purchase price allocation		—			1,635
Changes in current assets and liabilities that are reflected in investing activities		1,154			2,201
Net change in asset retirement obligations		4,475			(2,650	)
Treasury stock acquired from employee stock option exercises		4,886			3,187

5. Acquisitions, Dispositions and Property Held for Sale

Acquisitions

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

The CH4 acquisition was recorded using the purchase method of accounting, and the results of operations from the acquisition are included with the results of the Company from the date of closing. The total purchase price of the transaction was allocated to the assets acquired and the liabilities assumed based on fair values at the acquisition date. The Company finalized the purchase price allocation during the quarter ended June 30, 2007 as all amounts related to receivables and payables were determined with certainty. The table below summarizes the allocation, which has been revised in the current quarter based on updated information (in thousands):

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

Property Held for Sale

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

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

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The following table presents the assets and liabilities associated with the oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment, held for sale in the DJ Basin as of June 30, 2007 (in thousands):

Proved oil and gas properties	$	572
Unevaluated oil and gas properties	$	1,028
Noncurrent liabilities	$	41

For the six months ended June 30, 2007, total production volumes associated with the properties held for sale were 11.3 MMcfe.

Dispositions

On June 22, 2007, the Company completed the sale of its oil and gas properties in the Williston Basin. This transaction had an effective date of May 1, 2007. The Company received approximately $81.5 million in cash proceeds and recognized an $11.0 million pre-tax gain, which is included in other operating revenues in the Condensed Consolidated Statement of Operations.

6. Note Payable to Bank

On March 17, 2006, the Company amended its credit facility (the “Amended Credit Facility”). The Amended Credit Facility has a borrowing capacity of $400.0 million, expandable up to $600.0 million, and had an initial borrowing base of $280.0 million. Based on year-end 2006 reserves, the borrowing base was increased to $365.0 million on March 30, 2007. After selling our Williston properties on June 22, 2007, the borrowing base was reduced to $340.0 million. Future borrowing bases will be computed based on proved natural gas and oil reserves. The Amended Credit Facility matures on March 17, 2011 and bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 1.0% to 1.75% or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 0.25%. The Company pays annual commitment fees ranging from 0.25% to 0.375% of the unused borrowing base. The Amended Credit Facility is secured by natural gas and oil properties representing at least 80% of the value of the Company’s proved reserves and the pledge of all of the stock of our subsidiaries.

As of June 30, 2007, borrowings outstanding under the Amended Credit Facility totaled $132.0 million. The Amended Credit Facility also contains certain financial covenants. We have complied with all financial covenants for all periods.

7. Asset Retirement Obligations

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

A reconciliation of our asset retirement obligations for the six months ended June 30, 2007, which includes $0.04 million associated with oil and gas properties held for sale, is as follows (in thousands):

Beginning of period	$	32,598
Liabilities incurred		917
Liabilities settled		(3,676	)
Accretion expense		1,516
Revisions to estimate		22
End of period	$	31,377
Less: current asset retirement obligations		350
Long-term asset retirement obligations	$	31,027

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8. Fair Value of Derivatives and Other Financial Instruments

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

Oil and Gas Commodity Hedges

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

The Company was a party to various swap and collar contracts for natural gas based on the Colorado Interstate Gas Rocky Mountains (“CIGRM”) index during the six months ended June 30, 2006 and 2007. As a result, the Company recognized an increase of natural gas production revenues related to these contracts of $5.0 million and $21.0 million in the three months ended June 30, 2006 and 2007, respectively, and $4.3 million and $28.3 million in the six months ended June 30, 2006 and 2007, respectively. The Company also was a party to various collar contracts for oil based on a West Texas Intermediate (“WTI”) index recognizing a reduction to oil production revenues related to these contracts of $1.3 million and an increase of $0.09 million in the three months ended June 30, 2006 and 2007, respectively, and a reduction of $2.1 million and an increase of $0.3 million in the six months ended June 30, 2006 and 2007, respectively. As the underlying prices in the Company’s hedge contracts were consistent with the indices used to sell its natural gas and oil, no ineffectiveness was recognized related to its hedge contracts for the three and six months ended June 30, 2006 and 2007.

At August 1, 2007, the Company had the following swap contracts and cashless collars (purchased put options and written call options) in order to hedge a portion of our 2007, 2008 and 2009 natural gas and oil production. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas production.

Product	Deliveries Per Day	Quantity Type	Weighted Average Floor Pricing		Weighted Average Ceiling Pricing		Weighted Average Fixed Price		Index Price (1)	Contract Period
Cashless Collars:
Natural gas	64,000	MMBtu	$	6.07	$	9.61		n/a	CIGRM	1/1/2007 — 12/31/2007
Oil	800	Bbls	$	55.00	$	79.85		n/a	WTI	1/1/2007 — 12/31/2007
Natural gas	35,000	MMBtu	$	6.50	$	10.00		n/a	CIGRM	1/1/2008 — 12/31/2008
Oil	500	Bbls	$	70.00	$	80.15		n/a	WTI	1/1/2008 — 12/31/2008
Swap Contracts:
Natural gas	5,000	MMBtu		n/a		n/a	$	5.21	CIGRM	2/1/2007 — 10/31/2007
Natural gas	45,000	MMBtu		n/a		n/a	$	5.47	CIGRM	4/1/2007 — 10/31/2007
Natural gas	5,000	MMBtu		n/a		n/a	$	5.14	CIGRM	5/1/2007 — 5/31/2007
Natural gas	55,000	MMBtu		n/a		n/a	$	6.90	CIGRM	11/1/2007 — 3/31/2008
Natural gas	10,000	MMBtu		n/a		n/a	$	8.00	CIGRM	1/1/2008 — 3/31/2008
Natural gas	10,000	MMBtu		n/a		n/a	$	6.75	CIGRM	1/1/2008 — 12/31/2008
Natural gas	15,000	MMBtu		n/a		n/a	$	6.86	CIGRM	4/1/2008 — 10/31/2008
Natural gas	15,000	MMBtu		n/a		n/a	$	8.28	CIGRM	11/1/2008 — 3/31/2009

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

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

At June 30, 2007, the estimated fair value of contracts designated and qualifying as cash flow hedges under SFAS No. 133 was a net asset of $40.9 million. The Company will reclassify the appropriate amount to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of June 30, 2007 to be reclassified from accumulated other comprehensive income to net income in the next 12 months would be approximately $20.9 million. The Company anticipates that all originally forecasted transactions will occur by the end of the originally specified time periods.

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Interest Rate Derivative Contracts

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

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

As of June 30, 2007, the Company had received an insignificant amount in settlement payments, which were deducted from interest expense during the six month period ended June 30, 2007. The Company anticipates that all originally forecasted transactions will occur by the end of the originally specified time periods and, based on current projected interest rates, the net amount of existing unrealized after-tax income as of June 30, 2007 to be reclassified from accumulated other comprehensive income to net income in the next 12 months would be approximately $0.09 million. At June 30, 2007, the estimated fair value of the interest rate derivatives was a net asset of $0.2 million.

9. Income Taxes

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

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in our income tax provision. As of the date of adoption of FIN No. 48, we did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the quarter.

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

At June 30, 2007, the Company’s balance sheet reflected a net deferred tax liability of $115.1 million, of which $15.3 million pertains to a net deferred tax liability of derivative instruments reflected in accumulated other comprehensive income and $24.8 million pertains to the deferred tax liability assumed through the CH4 acquisition.

Income tax expense for the three months ended June 30, 2006 and 2007 differs from the amounts that would be provided by applying the U.S. federal income tax rate to income before income taxes principally due to state income taxes, stock-based compensation not deductible for income tax purposes, and other permanent differences.

10. Stockholders’ Equity

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

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The Company’s authorized capital structure consists of 75,000,000 shares of $0.001 per share par value preferred stock and 150,000,000 shares of $0.001 per share par value common stock. In October 2004, 150,000 shares of $0.001 per share par value preferred stock were designated as Series A Junior Participating Preferred Stock, none of which are outstanding. At June 30, 2007, the Series A Junior Participating Preferred Stock was the Company’s only designated preferred stock, and the remainder of the authorized preferred stock is undesignated.

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

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

The Company may occasionally acquire treasury stock in connection with the vesting and exercise of share-based awards, which is recorded at cost. As of June 30, 2007, all treasury stock held by the Company was retired.

11. Accumulated Other Comprehensive Income

The components of accumulated other comprehensive income and related tax effects for the six months ended June 30, 2007 were as follows:

	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated other comprehensive income—December 31, 2006	$	46,807		$	(17,436	)	$	29,371
Change in fair value of hedges		(29,055	)		10,823			(18,232	)
Reclassification adjustment for realized gains on hedges included in net income		23,367			(8,704	)		14,663
Accumulated other comprehensive income—June 30, 2007	$	41,119		$	(15,317	)	$	25,802

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 exploration or development projects, capital expenditures and other uncertainties, as well as those factors discussed below (including in Part II, Item 1A) and in our Annual Report on Form 10-K for the year ended December 31, 2006 under the “Cautionary Note Regarding Forward-Looking Statements” section and the “Risk Factors” section, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. The Company does not undertake any obligation to publicly update any forward looking statements.

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

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gas and oil operations in March 2002 upon the acquisition of properties in the Wind River Basin of Wyoming. Also in 2002, we completed two additional acquisitions of properties in the Uinta (Utah), Wind River (Wyoming), Powder River (Wyoming) and Williston (North Dakota, South Dakota and Montana) Basins. In early 2003, we completed an acquisition of largely undeveloped coalbed methane properties located in the Powder River Basin. In September 2004, we acquired properties in and around the Gibson Gulch field in the Piceance Basin of Colorado. In December 2004, we completed our Initial Public Offering (“IPO”) of 14,950,000 shares of our common stock at a price to the public of $25.00 per share. We received net proceeds of $347.3 million after deducting underwriting fees and other offering costs. We completed an acquisition in May 2006 in which we acquired additional coalbed methane properties located in the Powder River Basin. In June 2007, we completed the sale of our Williston properties.

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Results of Operations

The financial information for the six and three months ended June 30, 2006 and 2007 that is discussed below is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2007

	Six Months Ended June 30,				Increase (Decrease)
	2006		2007		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil and gas production revenues	$	175,711	$	185,978	$	10,267		6	%
Other		4,674		13,055		8,381		179	%
Operating Expenses
Lease operating expense		14,193		23,086		8,893		63	%
Gathering and transportation expense		8,018		10,392		2,374		30	%
Production tax expense		14,779		10,696		(4,083	)	(28	)%
Exploration expense		3,925		2,758		(1,167	)	(30	)%
Impairment, dry hole costs and abandonment expense		7,088		6,872		(216	)	(3	)%
Depreciation, depletion and amortization expense		63,808		81,858		18,050		28	%
General and administrative expense (1)		13,743		14,865		1,122		8	%
Non-cash stock-based compensation (1)		3,167		4,481		1,314		41	%
Total operating expenses	$	128,721	$	155,008	$	26,287		20	%
Production Data:
Natural gas (MMcf)		23,323		26,955		3,632		16	%
Oil (MBbls)		332		378		46		14	%
Combined volumes (MMcfe)		25,315		29,223		3,908		15	%
Daily combined volumes (Mmcfe/d)		140		161		21		15	%
Average Prices (includes effects of hedges) (2):
Natural gas (per Mcf)	$	6.77	$	6.12	$	(0.65	)	(10	)%
Oil (per Bbl)		53.31		55.33		2.02		4	%
Combined (per Mcfe)		6.94		6.36		(0.58	)	(8	)%
Average Costs (per Mcfe):
Lease operating expense	$	0.56	$	0.79	$	0.23		41	%
Gathering and transportation expense		0.32		0.36		0.04		13	%
Production tax expense		0.58		0.37		(0.21	)	(36	)%
Depreciation, depletion and amortization (3)		2.52		2.92		0.40		16	%
General and administrative (4)		0.54		0.51		(0.03	)	(6	)%

(1) Non-cash stock-based compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $16.9 million and $19.3 million for the six months ended June 30, 2006 and 2007, respectively, in the Condensed Consolidated Statements of Operations. This separate presentation is a non-GAAP financial measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows more accurate comparison to our peers, which may have higher or lower costs associated with equity grants.

(2) Average prices shown in the table are net of the effects of our hedging transactions. As a result of our hedging transactions, natural gas and oil production revenues were increased by $2.2 million and $28.6 million for the six months ended June 30, 2006 and 2007, respectively. Before the effect of hedging contracts, the average price we received for natural gas and oil for the six months ended June 30, 2006 was $6.59 per Mcf and $59.77 per Bbl, respectively, compared with $5.08 per Mcf and $54.53 per Bbl, respectively, for the six months ended June 30, 2007.

(3) The calculated depreciation, depletion and amortization expense (“DD&A”) per Mcfe based on the DD&A expense and MMcfe production data presented in the table for the six months ended June 30, 2007 is $2.80. However, the DD&A rate per Mcfe for

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the six months ended June 30, 2007 of $2.92, as presented, excludes production of 1,211 MMcfe associated with our properties that were classified as held for sale in the Williston Basin and the properties that are still held for sale in the DJ Basin, as these were not depleted throughout 2007.

(4) Excludes non-cash stock-based compensation as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation, as presented in the Condensed Consolidated Statement of Operations, were $0.67 for the six months ended June 30, 2006 and $0.66 for the six months ended June 30, 2007.

Production Revenues.Production revenues increased from $175.7 million for the six months ended June 30, 2006 to $186.0 million for the six months ended June 30, 2007 primarily due to a 15% increase in production, offset by a decrease in natural gas prices after the effect of hedges. The net decrease in prices on a Mcfe basis lowered production revenues by approximately $14.7 million, and the production increases added approximately $25.0 million of production revenues, after natural production declines, so that new production from our drilling program more than offset natural production declines.

On an Mcf equivalent basis, total production volumes for the six months ended June 30, 2007 increased 15% from total production for the prior year comparable period. Production increased in the Uinta and Piceance Basins by 53% and 44%, respectively. These increases in production were partially offset by decreases in the Wind River and Powder River Basins of 35% and 22%, respectively. Additional information concerning production is in the following table.

	Six Months Ended June 30, 2006			Six Months Ended June 30, 2007			% Increase (Decrease)
	Oil	Natural Gas	Total	Oil	Natural Gas	Total	Oil	Natural Gas	Total
	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MMcf)	(MMcfe)
Uinta Basin	24	7,873	8,016	22	12,098	12,230	(8)%	54 %	53 %
Piceance Basin	79	5,708	6,184	139	8,052	8,886	76 %	41 %	44 %
Wind River Basin	25	6,019	6,168	18	3,887	3,995	(28)%	(35)%	(35)%
Powder River Basin	—	3,620	3,620	—	2,821	2,821	—	(22)%	(22)%
Williston Basin (1)	191	73	1,221	187	78	1,200	(2)%	7 %	(2)%
Other	13	29	106	12	19	91	(8)%	(34)%	(14)%
Total	332	23,322	25,315	378	26,955	29,223	14 %	16 %	15 %

(1) Includes production from Williston Basin properties through the closing date of the sale on June 22, 2007.

The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields with no significant drilling or recompletion activities to offset these declines. The production increase in the Uinta Basin reflects our continuing exploration and development activities in the West Tavaputs field. The production increase in the Piceance Basin is the result of our continued development activities. As of June 30, 2007 we have hooked-up 27 gross wells to first sales. The production decrease in the Powder River Basin is due to natural production declines in our existing mature fields and the lag time between drilling of coal bed methane wells and production of natural gas while dewatering occurs As of June 30, 2007, we had 116 net operated coal bed methane wells in the dewatering stage with little or no production. The decrease in the Powder River Basin is partially offset by the initial production from the properties we acquired from CH4 in May 2006, however, the production from this area has been partially curtailed due to full gathering pipelines. Projects to expand gathering capacity in the Powder River Basin are expected to be completed beginning in early 2008.

Hedging Activities.During the six months ended June 30, 2006, approximately 42% of our natural gas volumes and 41% of our oil volumes were hedged, resulting in an increase in revenues of $2.2 million. During the six months ended June 30, 2007, approximately 62% of our natural gas volumes and 38% of our oil volumes were hedged, resulting in an increase in revenues of $28.6 million.

Other Operating Revenues. Other operating revenues increased from $4.7 million for the six months ended June 30, 2006 to $13.1 million for the six months ended June 30, 2007. The increase is primarily due to the $11.0 million gain realized on the sale of the Williston Basin properties, along with gains realized on joint exploration agreements entered into in the Paradox Basin.

Lease Operating Expense and Gathering and Transportation Expense.Our lease operating expense increased from $0.56 per Mcfe in the first six months of 2006 to $0.79 per Mcfe in the first six months of 2007, and our gathering and transportation expense increased from $0.32 per Mcfe in the first six months of 2006 to $0.36 per Mcfe in the first six months of 2007. The increase in lease operating expense is primarily due to an increase in the Powder River Basin from $0.94 per Mcfe for the six months ended June 30, 2006 to $1.71 per Mcfe for the six months ended June 30, 2007, the Wind River Basin from $0.54 per Mcfe for the six months ended June 30, 2006 to $1.04 per Mcfe for the six months ended June 30, 2007 and the Piceance Basin from $0.37 per Mcfe for the six months ended June 30, 2006 to $0.64 per Mcfe for the six months ended June 30, 2007. The increase on a per Mcfe basis in the Powder River Basin is substantially due to higher water handling charges on dewatering wells in new pilot areas that have no offsetting gas production as yet, along with the partial curtailment of production due to full gathering lines. As of June 30, 2007, we had 116 net operated coal bed methane wells in the dewatering stage. The increase on a per Mcfe basis in the Wind River Basin is due

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to the natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields, while lease operating expenses have stayed flat or increased. The increase on a per Mcfe basis in the Piceance Basin is a result of higher than expected water transportation and disposal costs. The Company expects these costs on a per Mcfe basis to decrease in the second half of the year due to efficiencies from water handling systems installed, fewer workovers, and increased production. In addition, lease operating expense also increased in the Williston Basin from $1.62 per Mcfe for the six months ended June 30, 2006 to $2.23 per Mcfe for the six months ended June 30, 2007. The following table displays the lease operating expense per Mcfe by basin:

	Six Months Ended June 30, 2006				Six Months Ended June 30, 2007				%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		(% per Mcfe)
Piceance Basin	$	2,302	$	0.37	$	5,696	$	0.64	73	%
Uinta Basin		2,754		0.34		5,333		0.44	29	%
Powder River Basin		3,416		0.94		4,811		1.71	82	%
Wind River Basin		3,322		0.54		4,153		1.04	93	%
Williston Basin		1,976		1.62		2,674		2.23	38	%
Other		423		3.99		419		4.60	15	%
Company Total	$	14,193		0.56	$	23,086		0.79	41	%

We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to avoid possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production from the Piceance and Uinta Basins where we expect to spend a significant portion of our capital expenditure program in future years. Included in gathering and transportation expense is $0.08 per Mcfe of transportation expense from long-term contracts for both of the six months ended June 30, 2006 and 2007.

Production Tax Expense.Total production taxes decreased from $14.8 million for the six months ended June 30, 2006 to $10.7 million for the six months ended June 30, 2007. Although our production volumes and production revenues increased, our overall production taxes decreased because a larger portion of our revenues came from areas with lower tax rates. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 8.5% for the six months ended June 30, 2006 and 6.8% for the six months ended June 30, 2007. Production taxes are primarily based on the wellhead values of production and tax rates that vary across the different areas in which we operate. As the proportion of our production changes from area to area, our production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect in each area.

Exploration Expense.Exploration costs decreased from $3.9 million in the first six months of 2006 to $2.8 million in the first six months of 2007. The costs for the six months ended June 30, 2006 consisted of $3.0 million for seismic programs principally in the Piceance, Uinta, Wind River and DJ Basins and Montana Overthrust, and $0.9 million for delay rentals and other costs. The costs for the six months ended June 30, 2007 consisted of $2.2 million for seismic programs, principally in the Montana Overthrust, Uinta Basin, Paradox Basin, and Big Horn Basin and $0.6 million for delay rentals and other exploration costs.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense decreased from $7.1 million during the first six months of 2006 to $6.9 million during the first six months of 2007. For the six months ended June 30, 2006, abandonments were $0.7 million and dry hole costs were $6.4 million for dry holes in the Williston and Uinta Basins. Included in the $6.4 million of dry hole costs for the six months ended June 30, 2006 is $3.5 million related to the #1DLB, an exploration well located in the Lake Canyon area of the Uinta Basin. This well, which was completed in late April 2006, was tested and determined to be commercial in the Wasatch formation and non-commercial in the zones below the Wasatch; thus, a proportionate share of the well cost was expensed. For the six months ended June 30, 2007, impairment expense was $2.3 million, dry hole costs were $3.6 million, and abandonment expense was $1.0 million. Dry hole costs for the six months ended June 30, 2007 were primarily attributable to the Cooper Deep #1, an exploration well located in the Wind River Basin, and the DLB 14-11-56, an exploration well located in the Lake Canyon area of the Uinta Basin. The Cooper Deep #1 well, which was completed in late November 2006, was tested and determined to be non-commercial in the zones below the Niobrara formation; thus, a proportionate share of the well cost was expensed. The DLB 14-11-56, which was completed in April 2007, was tested and determined to be non-commercial in the zones below the Green River formation; thus, a proportionate share of the well cost is being expensed.

The Company evaluates the impairment of its oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. If the carrying amount exceeds the properties’ estimated fair value, the Company will adjust the carrying amount of the properties to fair value through a charge to impairment expense. With respect to its Tri State properties within the DJ Basin, the Company, based upon its fair value analysis, recognized a $2.3 million non-cash impairment charge for the six months ended June 30, 2007. We are currently in the process of selling these properties.

We account for oil and gas exploration and production activities using the successful efforts method under which we capitalize

19

exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense. Otherwise, the costs remain capitalized and are depleted as production occurs. The following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and gas properties as of June 30, 2007 pending determination of whether the wells will be assigned proved reserves. The following table does not include $18.7 million related to exploratory wells in progress for which drilling had not been completed at June 30, 2007:

	Time Elapsed Since Drilling Completed
	0-3 Months		4-6 Months		7-12 Months		> 12 Months		Total
	(in thousands)
Wells for which drilling has been completed	$	20,094	$	16,586	$	4,234	$	18,279	$	59,193

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense was $63.8 million for the six months ended June 30, 2006 compared to $81.9 million for the six months ended June 30, 2007. Of the increase, $6.8 million is due to the 11% increase in production, excluding the Williston and DJ Basins, and $11.3 million is due to an increased DD&A rate for the six months ended June 30, 2007. During the six months ended June 30, 2006, the weighted average depletion rate was $2.52 per Mcfe. In the six months ended June 30, 2007, the weighted average depletion rate was $2.92 per Mcfe. The DD&A rate for the six months ended June 30, 2007 excludes production of 1,211 MMcfe associated with our properties held for sale in the Williston and DJ Basins. Under successful efforts accounting, depletion expense is separately computed for each producing area based on geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average depletion rate for current production. Our cost of finding oil and gas reserves in certain areas yielded an overall higher depletion rate for the six months ended June 30, 2007 compared to the prior year period. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

General and Administrative Expense. On a per unit of production basis general and administrative expense, excluding non-cash stock-based compensation, decreased from $0.54 per Mcfe in the first six months of 2006 to $0.51 per Mcfe in the first six months of 2007 due to increased production. The increased in general and administrative expense, excluding non-cash stock-based compensation, from $13.7 million in the six months ended June 30, 2006 to $14.9 million in the six months ended June 30, 2007 was primarily due to increased personnel required for our capital program and production levels. As of June 30, 2007, we had 147 full time employees in our corporate office compared to 137 as of June 30, 2006.

Non-cash charges for stock-based compensation were $3.2 million in the first six months of 2006 compared to $4.5 million in the first six months of 2007. The increase in charges for non-cash compensation is primarily due to the additional equity awards that were granted during the later part of 2006 and during the six months ended June 30, 2007.

Interest Expense.Interest expense increased to $6.0 million in the six months ended June 30, 2007 from $4.4 million in the prior year period. The increase is due to higher debt levels in the six month period ended June 30, 2007 to fund exploration and development activities. The weighted average outstanding balance under our credit facility for the six months ended June 30, 2007 was $193.4 million compared to $124.8 million in the prior year period.

Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use, and as a result, we had not capitalized any interest expense until the third quarter of 2006. The weighted average interest rate, including interest and commitment fees paid on the unused portion of our credit facility, amortization of deferred financing costs and the effects of interest rate hedges, used to capitalize interest for the six months ended June 30, 2007 was 7.1%. We capitalized interest costs of $0.9 million for the six months ended June 30, 2007.

Income Tax Expense.Our effective tax rates were 37.5% and 38.5% in the six months ended June 30, 2006 and 2007, respectively. For both the 2006 and 2007 periods, our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense under APB 25 and SFAS No. 123R that is not deductible for income tax purposes. All of our income tax liabilities and benefits are deferred. Due to the tax deductions being created by our drilling activities, we expect that we will incur cash income tax liabilities relating to the alternative minimum tax in the next year.

Net Income.We generated net income of $24.0 million in the six months ended June 30, 2007 compared to a net income of $30.3 million in the prior year period. The reasons for the decrease in net income include the decrease in natural gas prices, giving effect to hedges, increases in operating expenses and an increase in interest expense, as previously discussed in this section. Offsetting these was an increase in other operating revenues during the six month period ended June 30, 2007 as compared to the prior year period primarily due to the sale of the Williston Basin properties.

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Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2007

	Three Months Ended June 30,				Increase (Decrease)
	2006		2007		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil and gas production revenues	$	78,213	$	89,096	$	10,883		14 %
Other		4,407		11,557		7,150		162 %
Operating Expenses
Lease operating expense		7,371		14,246		6,875		93 %
Gathering and transportation expense		4,067		5,266		1,199		29 %
Production tax expense		6,525		5,139		(1,386	)	(21)%
Exploration expense		641		1,152		511		80 %
Impairment, dry hole costs and abandonment expense		6,944		3,274		(3,670	)	(53)%
Depreciation, depletion and amortization expense		33,041		42,785		9,744		29 %
General and administrative expense (1)		6,877		7,587		710		10 %
Non-cash stock-based compensation (1)		1,539		2,591		1,052		68 %
Total operating expenses	$	67,005	$	82,040	$	15,035		22 %
Production Data:
Natural gas (MMcf)		11,119		13,924		2,805		25 %
Oil (MBbls)		176		188		12		7 %
Combined volumes (MMcfe)		12,175		15,052		2,877		24 %
Daily combined volumes (Mmcfe/d)		134		165		31		23 %
Average Prices (includes effects of hedges) (2):
Natural gas (per Mcf)	$	6.15	$	5.60	$	(0.55	)	(9)%
Oil (per Bbl)		55.70		58.99		3.29		6 %
Combined (per Mcfe)		6.42		5.92		(0.50	)	(8)%
Average Costs (per Mcfe):
Lease operating expense	$	0.61	$	0.95	$	0.34		56 %
Gathering and transportation expense		0.33		0.35		0.02		6 %
Production tax expense		0.54		0.34		(0.20	)	(37)%
Depreciation, depletion and amortization (3)		2.71		2.95		0.24		9 %
General and administrative (4)		0.56		0.50		(0.06	)	(11)%

(1) Non-cash stock-based compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $8.4 million and $10.2 million for the three months ended June 30, 2006 and 2007, respectively, in the Condensed Consolidated Statements of Operations. This separate presentation is a non-GAAP financial measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows more accurate comparison to our peers, which may have higher or lower costs associated with equity grants.

(2) Average prices shown in the table are net of the effects of our hedging transactions. As a result of our hedging transactions, natural gas and oil production revenues were increased by $3.7 million for the three months ended June 30, 2006 and were increased by $21.1 million for the three months ended June 30, 2007. Before the effect of hedging contracts, the average price we received for natural gas and oil for the three months ended June 30, 2006 was $5.70 per Mcf and $63.12 per Bbl, respectively, compared with $4.09 per Mcf and $58.51 per Bbl, respectively, for the three months ended June 30, 2007.

(3) The calculated DD&A per Mcfe based on the DD&A expense and MMcfe production data presented in the table for the three months ended June 30, 2007 is $2.84. However, the DD&A rate per Mcfe for the three months ended June 30, 2007 of $2.95, as presented, excludes production of 558 MMcfe associated with our properties that were classified as held for sale in the Williston Basin and the properties that are still held for sale in the DJ Basin, as these were not depleted throughout the three months ended June 30, 2007.

(4) Excludes non-cash stock-based compensation as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation, as presented in the Condensed Consolidated Statement of Operations, were $0.69 and $0.68 for the three months ended June 30, 2006 and three months ended June 30, 2007, respectively.

Production Revenues.Production revenues increased from $78.2 million for the three months ended June 30, 2006 to $89.1 million for the three months ended June 30, 2007 due to an increase in production, offset by both a decrease in gas price per Mcf and oil price per Bbl. The production increase of 24% increased production revenues by $17.0 million, offset by the decrease in price which decreased production revenues by $6.1 million.

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On an Mcf equivalent basis, total production volumes for the three months ended June 30, 2007 increased 24% from total production for the prior year period. Additional information concerning production is in the following table.

	Three Months Ended June 30, 2006			Three Months Ended June 30, 2007			% Increase (Decrease)
	Oil	Natural Gas	Total	Oil	Natural Gas	Total	Oil	Natural Gas	Total
	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MMcf)	(MMcfe)	(MBbls)	(MMcf)	(MMcfe)
Uinta Basin	14	3,421	3,505	13	6,357	6,435	(7)%	86 %	84 %
Piceance Basin	42	3,177	3,429	75	4,207	4,657	79 %	32 %	36 %
Wind River Basin	13	2,600	2,678	10	1,914	1,974	(23)%	(26)%	(26)%
Powder River Basin	—	1,872	1,872	—	1,388	1,388	—	(26)%	(26)%
Williston Basin (1)	100	37	637	84	44	548	(16)%	19 %	14 %
Other	7	12	54	6	14	50	(14)%	17 %	(7)%
Total	176	11,119	12,175	188	13,924	15,052	7 %	25 %	24 %

(1) Includes production from Williston Basin properties through the closing date of the sale on June 22, 2007.

The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch and Cooper Reservoir Fields with no significant drilling or recompletion activities to offset these declines. The production increase in the Uinta Basin reflects our continuing exploration and development activities in the West Tavaputs. The production increase in the Piceance Basin is the result of our continued development activities. The production decrease in the Powder River Basin is due to natural production declines in our existing mature fields and the lag time between drilling of coal bed methane wells and production of natural gas while dewatering occurs. As of June 30, 2007, we had 116 net operated coal bed methane wells in the dewatering stage with little or no production. The decrease in the Powder River Basin is partially offset by the initial production from the properties acquired from CH4 in May 2006, however, the production from this area has been partially curtailed due to full gathering pipelines. Projects to expand gathering capacity in the Powder River Basin are expected to be completed beginning in early 2008.

Hedging Activities.During the three months ended June 30, 2006, approximately 44% of our natural gas volumes and 39% of our oil volumes were hedged, resulting in an increase in revenues of $3.7 million. During the three months ended June 30, 2007, approximately 71% of our natural gas volumes and 39% of our oil volumes were hedged, resulting in an increase in revenues of $21.1 million.

Other Operating Revenues. Other operating revenues increased from $4.4 million for the three months ended June 30, 2006 to $11.6 million for the three months ended June 30, 2007. The increase is primarily due to the $11.0 million gain realized on the sale of the Williston Basin properties.

Lease Operating Expense and Gathering and Transportation Expense.Our lease operating expense increased from $0.61 per Mcfe in the second quarter of 2006 to $0.95 per Mcfe in the current year period, and our gathering and transportation expense increased slightly from $0.33 per Mcfe in the second quarter of 2006 to $0.35 per Mcfe in the current year period. The increase in lease operating expense is primarily due to an increase in the Powder River Basin from $1.07 per Mcfe in the second quarter of 2006 to $1.99 per Mcfe in the current year period, the Wind River Basin from $0.56 per Mcfe in the second quarter of 2006 to $1.11 per Mcfe in the current year period and the Piceance Basin from $0.37 per Mcfe in the second quarter of 2006 to $0.87 per Mcfe in the current year period. The increase on a per Mcfe basis in the Powder River Basin is substantially due to higher water handling charges on dewatering wells in new pilot areas that have no offsetting gas production as yet, along with the partial curtailment of production due to full gathering lines. As of June 30, 2007, we had 116 net operated coal bed methane wells in the dewatering stage. The increase on a per Mcfe basis in the Wind River Basin is due to the natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields, while lease operating expenses have stayed flat or increased. The increase on a per Mcfe basis in the Piceance Basin is a result of higher than expected water transportation and disposal costs. The Company expects these costs on a per Mcfe basis to decrease in the second half of the year due to efficiencies from water handling systems installed, fewer workovers, and increased production. The following table displays the lease operating expense per Mcfe by basin:

22

	Three Months Ended June 30, 2006				Three Months Ended June 30, 2007				%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		(% per Mcfe)
Piceance Basin	$	1,268	$	0.37	$	4,073	$	0.87	135	%
Uinta Basin		1,251		0.36		3,257		0.51	42	%
Powder River Basin		1,998		1.07		2,767		1.99	86	%
Wind River Basin		1,504		0.56		2,189		1.11	98	%
Williston Basin		1,151		1.81		1,752		3.20	77	%
Other		423		3.69		208		4.16	13	%
Company Total	$	7,371		0.61	$	14,246		0.95	56	%

In addition to the above, lease operating expense also increased in the Williston Basin from $1.81 per Mcfe for the three months ended June 30, 2006 to $3.20 per Mcfe for the three months ended June 30, 2007. The increase was the result of the Company’s well maintenance program to facilitate the sale of these properties.

We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to avoid possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production from the Piceance and Uinta Basins where we expect to spend a significant portion of our capital expenditure program in future years. Included in gathering and transportation expense is $0.07 per Mcfe and $0.09 per Mcfe of transportation expense from long-term contracts for the three months ended June 30, 2006 and 2007, respectively.

Production Tax Expense.Total production taxes decreased from $6.5 million for the three months ended June 30, 2006 to $5.1 million for the three months ended June 30, 2007. Although our production volumes increased and our production revenues increased, our overall production taxes decreased, as a larger portion of our revenues came from areas with lower tax rates. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 8.7% in the second quarter of 2006 and 7.6% for the current year period. Production taxes are primarily based on the wellhead values of production and tax rates that vary across the different areas in which we operate. As the proportion of our production changes from area to area, our production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect in each area.

Exploration Expense. Exploration costs increased from $0.6 million in the second quarter of 2006 to $1.2 million in the current year period. The costs for the three months ended June 30, 2006 include $0.1 million for seismic programs principally in the DJ Basin along with $0.5 million for delay rentals and other costs. The costs for the three months ended June 30, 2007 consisted of $0.7 million for seismic programs, principally in the Montana Overthrust, Uinta Basin, Paradox Basin, and Big Horn Basin and $0.5 million for delay rentals and other exploration costs.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense decreased from $6.9 million during the second quarter of 2006 to $3.3 million during the current year period. For the three months ended June 30, 2006, impairment expense was zero, dry hole costs were $6.4 million for dry holes in the Williston and Uinta Basins, and abandonment expense was $0.5 million. Included in the $6.4 million of dry hole costs is $3.5 million related to the #1DLB, an exploration well located in the Lake Canyon area of the Uinta Basin. This well, which was completed in late April 2006, was tested and determined to be commercial in the Wasatch formation and non-commercial in the zones below the Wasatch; thus, a proportionate share of the well cost was expensed. For the three months ended June 30, 2007, impairment expense was $2.3 million, dry hole costs were $0.5 million, and abandonment expense was $0.5 million. Dry hole costs for the second quarter of 2007 were primarily attributable to the DLB 14-11-56, an exploration well located in the Lake Canyon area of the Uinta Basin. The DLB 14-11-56, which was completed in April 2007, was tested and determined to be non-commercial in the zones below the Green River formation; thus, a proportionate share of the well cost is being expensed.

The Company evaluates the impairment of its oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. If the carrying amount exceeds the properties’ estimated fair value, the Company will adjust the carrying amount of the properties to fair value through a charge to impairment expense. With respect to its Tri State properties within the DJ Basin, the Company, based upon its fair value analysis, recognized a $2.3 million non-cash impairment charge for the three months ended June 30, 2007. We are currently in the process of selling these properties.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense was $33.0 million for the three months ended June 30, 2006 compared to $42.8 million for the three months ended June 30, 2007. Of the increase, $6.3 million is due to the 19% increase in production, excluding the Williston and DJ Basins, and $3.5 million is due to an increased depletion rate for the three months ended June 30, 2007. During the three months ended June 30, 2006, the weighted average depletion rate was $2.71

23

per Mcfe. In the three months ended June 30, 2007, the weighted average depletion rate was $2.95 per Mcfe. Under successful efforts accounting, depletion expense is separately computed for each producing area based on geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average depletion rate for current production. For the three months ended June 30, 2007, the relationship of capital expenditures, proved reserves and production from certain producing areas yielded a higher weighted average depletion rate as the comparable prior year period. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

General and Administrative Expense.General and administrative expense on a per unit of production basis, excluding non-cash stock-based compensation, decreased from $0.56 per Mcfe in the second quarter of 2006 to $0.50 per Mcfe in the current year period due to increases in production. The increase in general and administrative expense, excluding non-cash stock-based compensation, from $6.9 million in the three months ended June 30, 2006 to $7.6 million in the three months ended June 30, 2007 was primarily due to increased personnel required for our capital program and production levels. As of June 30, 2007, we had 147 full time employees in our corporate office compared to 137 as of June 30, 2006.

Non-cash charges for stock-based compensation were $1.5 million in the second quarter of 2006 compared to $2.6 million in the current year period. The increase in charges for non-cash compensation is primarily due to the increased number of equity awards that were granted throughout 2006 and during the six months ended June 30, 2007.

Interest Expense.Interest expense increased to $3.1 million in the three months ended June 30, 2007 from $2.9 million in the prior year period. The increase was due to higher debt levels during the three month period ended June 30, 2007 to fund exploration and development activities. The weighted average outstanding balance under our credit facility for the three months ended June 30, 2007 was $197.4 million compared to $161.9 million in the prior year period.

Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use, and as a result, we had not capitalized any interest expense until the third quarter of 2006. The weighted average interest rate, including interest and commitment fees paid on the unused portion of our credit facility, amortization of deferred financing costs and the effects of interest rate hedges, used to capitalize interest for the three months ended June 30, 2007 was 7.2%. We capitalized interest costs of $0.5 million for the three months ended June 30, 2007.

Income Tax Expense.Our effective tax rates were 38.3% and 38.6% in the three months ended June 30, 2006 and 2007, respectively. For both the 2006 and 2007 periods, our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense under APB 25 and SFAS No. 123R that is not deductible for income tax purposes. All of our income tax liabilities and benefits are deferred. Due to the tax deductions being created by our drilling activities, we expect that we will incur cash income tax liabilities relating to the alternative minimum tax in the next year.

Net Income.We generated net income of $9.9 million in the three months ended June 30, 2007 compared to $8.2 million in the prior year period. The primary reason for the increase in net income is the increase in production, which increased production revenues by $10.9 million. In addition, other operating revenues increased by $7.2 million primarily due to the sale of the Williston Basin properties. Offsetting the increase in operating revenues were increases in operating expenses and interest expense during the three months ended June 30, 2007 compared to the prior year period.

Capital Resources and Liquidity

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

At June 30, 2007, our balance sheet reflected a cash balance of $28.1 million with a balance of $132.0 million outstanding on our credit facility.

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Cash Flow from Operating Activities

Net cash provided by operating activities was $130.3 million and $148.0 million for the six months ended June 30, 2006 and 2007, respectively. The increase in net cash provided by operating activities was primarily due to an increase in the changes in current assets and liabilities, which was offset by increased expenses as discussed above in “Results of Operations.” Changes in current assets and liabilities increased cash flow from operations by $11.3 million and $27.1 million for the six months ended June 30, 2006 and 2007, respectively.

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

To mitigate some of the potential negative impact on cash flow caused by changes in natural gas and oil prices, we have entered into commodity swap and collar contracts to receive fixed prices for a portion of our natural gas and oil production. At June 30, 2007, we had in place natural gas and crude oil collars and swaps covering portions of our 2007, 2008 and 2009 production. Our natural gas and oil derivative financial instruments have been designated as cash flow hedges in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities,and are classified as either current or noncurrent assets in our Condensed Consolidated Balance Sheets based on scheduled delivery of the underlying production.

As of August 1, 2007, we had hedges in place for approximately 17,747,000 MMbtu, 26,510,000 MMbtu and 1,350,000 MMbtu of natural gas production for the remaining portion of 2007 and for the years 2008 and 2009, respectively, and approximately 122 thousand barrels (“MBbls”) and 183 MBbls of oil production for the remaining portion of 2007 and for the year 2008, respectively.

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

Product	Deliveries Per Day	Quantity Type	Weighted Average Floor Pricing		Weighted Average Ceiling Pricing		Weighted Average Fixed Price		Index Price (1)	Contract Period
Cashless Collars:
Natural gas	64,000	MMBtu	$	6.07	$	9.61		n/a	CIGRM	1/1/2007 — 12/31/2007
Oil	800	Bbls	$	55.00	$	79.85		n/a	WTI	1/1/2007 — 12/31/2007
Natural gas	35,000	MMBtu	$	6.50	$	10.00		n/a	CIGRM	1/1/2008 — 12/31/2008
Oil	500	Bbls	$	70.00	$	80.15		n/a	WTI	1/1/2008 — 12/31/2008
Swap Contracts:
Natural gas	5,000	MMBtu		n/a		n/a	$	5.21	CIGRM	2/1/2007 — 10/31/2007
Natural gas	45,000	MMBtu		n/a		n/a	$	5.47	CIGRM	4/1/2007 — 10/31/2007
Natural gas	5,000	MMBtu		n/a		n/a	$	5.14	CIGRM	5/1/2007 — 5/31/2007
Natural gas	55,000	MMBtu		n/a		n/a	$	6.90	CIGRM	11/1/2007 — 3/31/2008
Natural gas	10,000	MMBtu		n/a		n/a	$	8.00	CIGRM	1/1/2008 — 3/31/2008
Natural gas	10,000	MMBtu		n/a		n/a	$	6.75	CIGRM	1/1/2008 — 12/31/2008
Natural gas	15,000	MMBtu		n/a		n/a	$	6.86	CIGRM	4/1/2008 — 10/31/2008
Natural gas	15,000	MMBtu		n/a		n/a	$	8.28	CIGRM	11/1/2008 — 3/31/2009

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

By removing the price volatility from a portion of our natural gas and oil production for 2007, 2008 and 2009, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers.

Based on hedging contracts outstanding on June 30, 2007, our cash flow hedge positions from natural gas and oil derivatives had an estimated net pre-tax asset of $40.9 million recorded as both current and non-current assets, as appropriate. We will reclassify this amount to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of June 30, 2007 to be reclassified from accumulated other comprehensive income to net income in the next 12 months would be $20.9 million. We anticipate that all original forecasted transactions will occur by the end of the originally specified time periods.

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Capital Expenditures

Our capital expenditures were $328.3 million and $193.3 million for the six months ended June 30, 2006 and 2007, respectively. The total capital expenditures for the six month period of 2006 includes $145.7 million for the acquisition of both proved and unevaluated properties (including $40.7 million of a non-cash deferred tax liability associated with the difference between the tax basis of the properties acquired in the CH4 acquisition and the book basis attributed to the properties under the purchase method of accounting), $170.4 million for drilling, development, exploration and exploitation of natural gas and oil properties, $11.0 million for geologic and geophysical costs, which are expensed under successful efforts accounting as exploration expense, impairment, dry hole costs and abandonment expense, and $1.2 million for furniture, fixtures and equipment. Total capital expenditures for the six months ended June 30, 2007 consist of $15.6 million for acquisitions of properties, $168.3 million for drilling, development, exploration and exploitation of natural gas and oil properties, $7.3 million for geologic and geophysical costs and exploratory dry holes and abandonment costs and $2.1 million for furniture, fixtures and equipment.

Unevaluated properties increased $29.9 million to $251.1 million at June 30, 2007, including $1.0 million related to unevaluated properties in the DJ Basin that is currently classified as held for sale at June 30, 2007, from $221.2 million at December 31, 2006, including $18.2 million related to unevaluated properties in the Williston and DJ Basins that were classified as held for sale. The increase is principally from increases in leasehold acquisitions and wells in progress resulting from increased development and exploratory drilling activity during the six months ended June 30, 2007.

Excluding material acquisitions, our current capital budget for 2007 is $425.0 to $450.0 million, of which we plan to spend approximately $315.0 to $325.0 million for development drilling and facilities, $78.0 to $88.0 million on exploration drilling, $20.0 to $25.0 million for leasehold acquisitions, $8.0 million on geologic and geophysical costs, and $4.0 million for equipment and other costs. While we may reallocate capital among our areas of activity, our approved budget provides that we will spend $190.0 to $195.0 million in the Piceance, $165.0 to $175.0 million in the Uinta, $30.0 to $35.0 million in the Powder River, $20.0 million in the Wind River, and $20.0 to $25.0 million in other areas. Based upon our current natural gas and oil price expectations and our hedge position for 2007, we anticipate that our operating cash flow, available borrowing capacity under our credit facility, and the proceeds from the sale of our Williston Basin properties will be sufficient to fund our planned capital expenditures and other cash requirements for the remainder of 2007 and into 2008. We also may seek to issue other debt instruments to repay amounts outstanding under our credit facility. However, future cash flows are subject to a number of variables, including the level of natural gas and oil production, commodity prices, and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts to maintain planned levels of capital expenditures.

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

Financing Activities

Credit Facility.Our current bank line of credit has a borrowing capacity of $400.0 million. The credit facility matures on March 17, 2011 and, as of March 30, 2007, had a borrowing base of $365.0 million. After selling our Williston Basin properties on June 22, 2007, the conforming borrowing base was reduced to $340.0 million. Future borrowing bases will be computed based on proved natural gas and oil reserves. The credit facility bears interest, based on the borrowing base usage, at the applicable LIBOR plus applicable margins ranging from 1.0% to 1.75%, or an alternate base rate, based upon the greater of the prime rate or the federal funds effective rate plus applicable margins ranging from 0% to 0.25%. We pay annual commitment fees ranging from 0.25% to 0.375% of the unused borrowing base. This facility is secured by our natural gas and oil properties representing at least 80% of the value of our proved reserves and the pledge of all of the stock of our subsidiaries. At June 30, 2007, the outstanding balance under our credit facility was $132.0 million.

The amended credit facility contains certain financial covenants. As of June 30, 2007, we were in compliance with all of the financial covenants under the facility.

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

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

As of June 30, 2007, we had received an insignificant amount in settlement payments, which were deducted from interest expense throughout the first six months of 2007. We anticipate that all originally forecasted transactions will occur by the end of the originally specified time periods, and based on current projected interest rates, the net amount of existing unrealized after-tax income as of June 30, 2007 to be reclassified from accumulated other comprehensive income to net income in the next 12 months would be approximately $0.09 million. At June 30, 2007, the estimated fair value of the interest rate derivatives was a net asset of $0.2 million.

Contractual Obligations.A summary of our contractual obligations as of and subsequent to June 30, 2007 is provided in the following table (in thousands).

	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
Long-term debt (1)	$	—	$	—	$	—	$	132,000	$	—	$	—	$	132,000
Other commitments for developing oil and gas properties		13,856		—		—		—		—		—		13,856
Office and office equipment leases and other		1,592		1,586		1,625		1,054		232		—		6,089
Firm transportation and processing agreements		19,787		32,839		37,624		39,874		39,990		252,104		422,218
Asset Retirement Obligations (2)(3)		350		8,562		222		2,169		783		19,291		31,377
Total	$	35,585	$	42,987	$	39,471	$	175,097	$	41,004	$	271,395	$	605,540

(1) Amount does not include future commitment fees, interest expense, or other fees on our credit facility because the credit facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

(2) Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See “-Critical Accounting Policies and Estimates” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2006 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(3) Amount includes asset retirement obligations of $0.04 million associated with the DJ Basin, which is currently classified as held for sale.

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

In addition to the commitments above, we have commitments for the purchase of facilities equipment as of and subsequent to June 30, 2007 for a total of $7.4 million.

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2006 and the notes to the condensed consolidated financial statements included in Item 1 of this Form 10-Q for a description of critical accounting policies and estimates.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

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

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Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our price swap and collar contracts in place for the six months ended June 30, 2007, our income before income taxes, including hedge settlements, would have decreased by approximately $0.9 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.2 million for each $1.00 per barrel change in crude oil prices.

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

As of August 1, 2007, we had hedges in place for 17,747,000 MMbtu, 26,510,000 MMbtu and 1,350,000 MMbtu of natural gas production for the remaining portion of 2007 and for the years 2008 and 2009, respectively, and approximately 122 thousand barrels (“MBbls”) and 183 MBbls of oil production for the remaining portion of 2007 and for the year 2008, respectively. These hedges are summarized in the table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities.” Based on the pricing and contracts outstanding as of June 30, 2007, the estimated fair value of our hedge positions was an asset of $40.9 million due to us from the counterparties.

Commodity Hedges

Commodity Swaps

Through a price swap, we have fixed the price we will receive on a portion of our natural gas production in the remaining quarters of 2007 and 2008. The weighted average price we will receive for the remaining portion of 2007 is $6.02 per MMBtu for a CIGRM price, $7.01 per MMBtu for 2008 and $8.28 per MMBtu for 2009. The table presented under Item 2, “ Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities,” provides the deliveries associated with these arrangements as of August 1, 2007.

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

Commodity Collars

Through price collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas production in 2007 and the years 2008 and 2009. The weighted average minimum, or floor, price we will receive for the remaining portion of 2007 is $6.07 per MMBtu for a CIGRM price and $6.50 per MMBtu for a CIGRM price for 2008. The weighted average maximum, or ceiling, price we will receive for the remaining portion of 2007 is $9.61 per MMBtu for a CIGRM price and $10.00 per MMBtu for a CIGRM price for 2008. We have also fixed the minimum price we will receive on a portion of our oil production in the remaining quarters of 2007 and 2008, when the collars are settled, based on a weighted average floor price of $55.00 and $70.00 per Bbl for a WTI price, respectively, and a weighted average maximum price of $79.85 and $80.15 per Bbl for a WTI price, respectively. The price collars allow us to share in upward price movements up to the ceiling prices referenced in the contracts. The table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities,” provides the deliveries and floor and ceiling prices associated with these various arrangements as of August 1, 2007.

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.

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Interest Rate Risks

At June 30, 2007, we had debt outstanding of $132.0 million, which bears interest at floating rates in accordance with our revolving credit facility. The average annual interest rate incurred on this debt for the six months ended June 30, 2007 was 6.0%. A one hundred basis point (1.0%) increase in each of the average LIBOR rate and federal funds rate for the six months ended June 30, 2007 would have resulted in an estimated $1.0 million increase in interest expense assuming a similar average debt level to the six months ended June 30, 2007.

Interest Rate Hedges

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

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the second fiscal quarter of 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.

Item 1A. Risk Factors.

As of the date of this filing, there have been no material changes from the risk factors previously disclosed in our “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2006, referred to as our 2006 Annual Report. An investment in our securities involves various risks. When considering an investment in our company, you should carefully consider all of the risk factors described in our 2006 Annual Report. These risks and uncertainties are not the only ones facing us, and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our company.

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

We did not have any acquisitions of our equity securities during the three months ended June 30, 2007.

Item 3. Defaults Upon Senior Securities.

Not applicable.

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

The Company’s stockholders approved the following matters at the annual meeting of stockholders held on May 9, 2007. The results of the balloting were as follows:

Election of Class III Directors (to hold office until the 2010 annual meeting of stockholders)

Name of Nominee	Votes For	Votes Withheld
Randy A. Foutch	32,137,817	1,592,265
Joseph N. Jaggers	30,558,871	3,171,211
Philippe S.E. Schreiber	32,756,370	973,712

Ratification of Deloitte & Touche LLP as Independent Registered Public Accounting Firm

Votes For	Votes Against	Votes Abstaining	Shares Not Voted
33,568,861	14,979	146,242	10,596,898

Following the meeting, the following Class I and Class II directors continued in office:

Class I Directors (who hold office until the 2008 annual meeting of stockholders)

Fredrick J. Barrett

Michael E. Wiley

Class II Directors (who hold office until the 2009 annual meeting of stockholders)

James M. Fitzgibbons

Jeffrey A. Harris

Randy Stein

In addition, Jim W. Mogg was appointed by our Board of Directors to serve as a Class I director effective May 9, 2007.

Item 5. Other Information.

Not applicable.

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Item  6. Exhibits.

Exhibit Number	Description of Exhibits
3.1	Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.4 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]
3.2	Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.5 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]
4.1	Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 3.2 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.2	Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
4.3	Stockholders’ Agreement, dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
4.4	Form of Rights Agreement concerning Shareholder Rights Plan, which includes as Exhibit A thereto the Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, and as Exhibits B thereto the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.5	Form of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, included as Exhibit A to Exhibit 4.4 above.
4.6	Form of Right Certificate, included as Exhibit B to Exhibit 4.4 above.
10.1(a)	Amended and Restated Credit Agreement, dated February 4, 2004, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.1(b)	First Amendment to Amended and Restated Credit Agreement dated as of September 1, 2004 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1(b) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.1(c)	Second Amended and Restated Credit Agreement dated March 17, 2006 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K reporting on event occurring March 17, 2006 filed with the SEC on March 22, 2006.]
10.2	Stock Purchase Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 10.2 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.3(a)*	Form of Indemnification Agreement dated April 15, 2004, between Bill Barrett Corporation and each of the directors and certain executive officers. [Incorporated by reference to Exhibit 10.10(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.3(b)*	Schedule of officers and directors party to Indemnification Agreements dated April 15, 2004 with Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.10(b) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.4*	Amended and Restated 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.12 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.5(a)*	Form of Tranche A Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.5(b)*	Form of Tranche B Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(b)to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.6*	2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]

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10.7*	Form of Stock Option Agreement for 2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.8	Form of Management Rights Agreement between Bill Barrett Corporation and certain investors. [Incorporated by reference to Exhibit 10.16 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.9	Regulatory sideletter, dated March 28, 2002, between J.P. Morgan Partners (BHCA), L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.17 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.10*	Form of Change in Control Severance Protection Agreement revised as of November 16, 2006 for named executive officers. [Incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.]
10.11*	2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.12*	Revised Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.]
10.13*	Severance Plan. [Incorporated by reference to Exhibit 10.23 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32.1	Section 1350 Certification of Chief Executive Officer.
32.2	Section 1350 Certification of Chief Financial Officer.

* Indicates a management contract or compensatory plan or arrangement.

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SIGNATURES

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

	BILL BARRETT CORPORATION
Date: August 7, 2007	By:	/s/ Fredrick J. Barrett
		Fredrick J. Barrett
		Chairman of the Board of Directors and Chief Executive Officer
		(Principal Executive Officer)
Date: August 7, 2007	By:	/s/ Robert W. Howard
		Robert W. Howard
		Chief Financial Officer
		(Principal Financial Officer)

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