Bill Barrett (BBG) 10-Q 2007 Q3 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 September 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 44,744,492 shares of $0.001 par value common stock outstanding on November 2, 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	28
PART II. OTHER INFORMATION			29
	Item 1.	Legal Proceedings	29
	Item 1A.	Risk Factors	29
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29
	Item 3.	Defaults Upon Senior Securities	29
	Item 4.	Submission of Matters to a Vote of Security Holders	29
	Item 5.	Other Information	29
	Item 6.	Exhibits	30
SIGNATURES			32

2

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	December 31, 2006			September 30, 2007
	(in thousands, except share and per share data)
Assets:
Current Assets:
Cash and cash equivalents	$	41,322		$	51,986
Accounts receivable, net of allowance for doubtful accounts of $284 and $298 as of December 31, 2006 and September 30, 2007, respectively		56,280			25,393
Prepayments and other current assets		2,697			3,861
Derivative assets		38,208			47,667
Total current assets		138,507			128,907
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		1,114,536			1,351,257
Unevaluated oil and gas properties, excluded from amortization		202,946			254,409
Oil and gas properties held for sale, net, excluded from amortization		75,496			2,549
Furniture, equipment and other		14,696			14,985
		1,407,674			1,623,200
Accumulated depreciation, depletion, amortization and impairment		(369,079	)		(480,858	)
Total property and equipment, net		1,038,595			1,142,342
Deferred Financing Costs, Derivative Assets and Other		10,299			6,889
Total	$	1,187,401		$	1,278,138
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	69,519		$	75,282
Amounts payable to oil and gas property owners		13,933			18,729
Production taxes payable		22,348			29,129
Deferred income taxes and other current liabilities		13,995			17,557
Total current liabilities		119,795			140,697
Note Payable to Bank		188,000			207,000
Asset Retirement Obligations		29,224			33,309
Liabilities Associated with Assets Held for Sale		3,374			43
Deferred Income Taxes		89,730			102,101
Other Noncurrent Liabilities		881			1,321
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 44,141,453 and 44,683,552 shares issued and outstanding at December 31, 2006 and September 30, 2007, respectively, with 254,524 and 568,250 shares subject to restrictions, respectively		44			44
Additional paid-in capital		727,486			737,311
(Accumulated deficit) Retained earnings		(504	)		23,726
Accumulated other comprehensive income		29,371			32,586
Total stockholders’ equity		756,397			793,667
Total	$	1,187,401		$	1,278,138

See notes to unaudited condensed consolidated financial statements.

3

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended September 30,						Nine months Ended September 30,
	2006			2007			2006			2007
	(in thousands, except share and per share amounts)
Operating and Other Revenues:
Oil and gas production	$	80,468		$	82,216		$	256,179		$	268,194
Other		23,944			39			28,618			13,094
Total operating and other revenues		104,412			82,255			284,797			281,288
Operating Expenses:
Lease operating expense		7,329			9,846			21,522			32,932
Gathering and transportation expense		3,510			4,873			11,528			15,265
Production tax expense		6,473			4,220			21,252			14,916
Exploration expense		3,333			4,004			7,258			6,762
Impairment, dry hole costs and abandonment expense		5,099			3,609			12,187			10,481
Depreciation, depletion and amortization		34,506			43,070			98,314			124,928
General and administrative		8,585			10,071			25,495			29,417
Total operating expenses		68,835			79,693			197,556			234,701
Operating Income		35,577			2,562			87,241			46,587
Other Income and Expense:
Interest and other income		650			676			1,888			1,724
Interest expense		(3,153	)		(2,739	)		(7,508	)		(8,693	)
Total other income and expense		(2,503	)		(2,063	)		(5,620	)		(6,969	)
Income before Income Taxes		33,074			499			81,621			39,618
Provision for Income Taxes		12,373			266			30,576			15,343
Net Income	$	20,701		$	233		$	51,045		$	24,275
Net Income Per Common Share, Basic	$	0.47		$	0.01		$	1.17		$	0.55
Net Income Per Common Share, Diluted	$	0.47		$	0.01		$	1.16		$	0.55
Weighted Average Common Shares Outstanding, Basic		43,730,199			44,085,365			43,647,850			44,009,103
Weighted Average Common Shares Outstanding, Diluted		44,007,475			44,562,152			44,176,225			44,498,700

See notes to unaudited 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 $30,775 of taxes		—		—			—			—			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		—		5,735			—			(3,292	)		—			2,443			—
Stock-based compensation		—		7,382			—			—			—			7,382			—
Retirement of treasury stock		—		(3,292	)		—			3,292			—			—			—
Comprehensive income:
Net income		—		—			24,275			—			—			24,275			24,275
Effect of derivative financial instruments, net of $1,908 of taxes		—		—			—			—			3,215			3,215			3,215
Total comprehensive income																		$	27,490
Balance — September 30, 2007	$	44	$	737,311		$	23,726		$	—		$	32,586		$	793,667

See notes to unaudited condensed consolidated financial statements.

5

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine months Ended September 30,
	2006			2007
	(in thousands)
Operating Activities:
Net Income	$	51,045		$	24,275
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		98,314			124,928
Deferred income taxes		30,576			15,343
Impairment, dry hole costs and abandonment expense		12,187			10,481
Stock compensation and other non-cash charges		5,165			7,789
Amortization of deferred financing costs		442			352
Gain on sale of properties		(18,875	)		(11,537	)
Change in operating assets and liabilities:
Accounts receivable		19,970			30,887
Prepayments and other assets		2,119			(943	)
Accounts payable, accrued and other liabilities		(759	)		(14,948	)
Amounts payable to oil and gas property owners		(12,683	)		4,796
Production taxes payable		9,997			6,781
Net cash provided by operating activities		197,498			198,204
Investing Activities:
Additions to oil and gas properties, including acquisitions		(376,456	)		(288,788	)
Additions of furniture, equipment and other		(2,285	)		(3,702	)
Proceeds from sale of properties		68,875			82,800
Net cash used in investing activities		(309,866	)		(209,690	)
Financing Activities:
Proceeds from debt		143,000			97,000
Principal payments on debt		(50,495	)		(78,000	)
Proceeds from sale of common stock		2,760			3,232
Deferred financing costs and other		(886	)		(82	)
Net cash provided by financing activities		94,379			22,150
(Decrease) Increase in Cash and Cash Equivalents		(17,989	)		10,664
Beginning Cash and Cash Equivalents		68,282			41,322
Ending Cash and Cash Equivalents	$	50,293		$	51,986

See notes to unaudited condensed consolidated financial statements.

6

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

September 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 unaudited condensed 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 condensed consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of September 30, 2007, our results of operations for the three and nine months ended September 30, 2006 and 2007, and cash flows for the nine months ended September 30, 2006 and 2007. Operating results for the three and nine months ended September 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 unaudited condensed consolidated financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2006 previously filed with the SEC.

In the course of preparing the unaudited 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 Unaudited 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 was 7.2% for the three and nine months ended September 30, 2006 and 7.2% and 7.1% for the three and nine months ended September 30, 2007, respectively. The Company capitalized interest costs of $0.5 million for the three and nine months ended September 30, 2006 and $0.4 million and $1.3 million for the three and nine months ended September 30, 2007, respectively.

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 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 September 30, 2007 of $0.3 million in total proved properties (excluded from amortization) and $2.2 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 September 30, 2007
	(in thousands)
Proved properties	$	346,619		$	350,575
Wells and related equipment and facilities		736,007			882,762
Support equipment and facilities		86,932			111,638
Materials and supplies		2,258			6,601
Total proved oil and gas properties		1,171,816			1,351,576
Accumulated depreciation, depletion, amortization and impairment		(363,587	)		(476,087	)
Total proved oil and gas properties, net	$	808,229		$	875,489
Unevaluated properties	$	139,689		$	132,265
Wells and facilities in progress		81,473			124,374
Total unevaluated oil and gas properties, excluded from amortization	$	221,162		$	256,639

Net changes in capitalized exploratory well costs for the nine months ended September 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		156,514
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(128,651	)
Exploratory well costs charged to dry hole costs and abandonment expense		(7,179	)
End of period	$	90,280

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. The capitalized exploratory well costs that have been capitalized for a period of one year or less also include $6.8 million of exploratory wells in progress for which drilling had not been completed as of September 30, 2007.

	September 30, 2007
	(in thousands)
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	74,872
Capitalized exploratory well costs that have been capitalized for a period greater than one year		15,408
End of period balance	$	90,280
Number of exploratory wells that have costs capitalized for a period greater than one year		156

As of September 30, 2007, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling include costs of $15.4 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 granted approval during the second quarter of 2007, and the gathering line is still 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 quarter ended June 30, 2007. No impairment expense was taken in the current quarter for any of the Company’s oil and gas properties.

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, 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 prorated 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 consist of 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 an initial threshold 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 initial threshold 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. During the three months ended September 30, 2007, the Company granted an additional 1,500 performance-based nonvested equity shares at a grant date fair value of $37.74 per share. However, new goals are established each year, which creates a new grant date and a new fair value for financial reporting purposes for those shares that could potentially vest in the upcoming year. 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 nine months ended September 30, 2007, the Company granted 887,500 options to purchase shares of common stock with a weighted average exercise price of $31.79 per share, 175,000 nonvested equity shares of common stock and 227,800 performance-based nonvested equity shares of common stock. During the three months ended September 30, 2007, the Company granted 112,500 options to purchase shares of common stock with a weighted average exercise price of $37.29 per share, 1,000 nonvested equity shares of common stock and 1,500 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 $4.8 million and $6.8 million for the nine months ended September 30, 2006 and 2007, respectively, including $0.9 million associated with the performance-based nonvested equity shares. For the three months ended September 30, 2006 and 2007, we recorded non-cash stock-based compensation of $1.6 million and $2.4 million, respectively, including $0.3 million associated with the performance-based nonvested equity shares. As of September 30, 2007, there were $22.8 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 2.7 years. This amount includes $0.9 million related to the performance-based nonvested equity shares that is expected to be recognized ratably over the next five months.

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 for payment of the director fees. For the three and nine months ended September 30, 2007, the Company issued 1,421 and 2,741 shares, respectively, of common stock for payment of the director fees and recognized $0.06 million and $0.1 million, respectively, 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.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. This statement expands the use of fair value measurement and applies to entities that elect the fair value option. The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. This statement is effective for fiscal years beginning after November 15, 2007. The adoption of SFAS No. 159 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 September 30,				Nine months ended September 30,
	2006		2007		2006		2007
Net income	$	20,701	$	233	$	51,045	$	24,275
Adjustments to net income for dilution		—		—		—		—
Net income adjusted for the effect of dilution	$	20,701	$	233	$	51,045	$	24,275
Basic weighted-average common shares outstanding in period		43,730		44,085		43,648		44,009
Add dilutive effects of stock options and nonvested equity shares of common stock		277		477		528		490
Diluted weighted-average common shares outstanding in period		44,007		44,562		44,176		44,499
Basic income per common share	$	0.47	$	0.01	$	1.17	$	0.55
Diluted income per common share	$	0.47	$	0.01	$	1.16	$	0.55

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4. Supplemental Disclosures of Cash Flow Information

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

	For nine months ended September 30,
	2006			2007
Cash paid for interest	$	6,888		$	9,510
Cash paid for income taxes, net of refunds received		—			64
Supplemental disclosures of non-cash investing and financing activities:
Retirement of treasury stock		(10,071	)		(3,292	)
Exchange of oil and gas properties for equipment and other properties		9,304			—
Assumption of debt and deferred tax liability – Powder River Basin properties acquisition purchase price allocation		43,660			—
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		(310	)		19,009
Net change in asset retirement obligations		4,849			(591	)
Treasury stock acquired from employee stock option exercises		4,891			3,292

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 final allocation (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 addition, the Company began actively marketing its Hingeline Prospect in the Uinta Basin during the quarter ended September 30, 2007. 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 Unaudited Condensed Consolidated

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Balance Sheet. Any liabilities related to those properties were also reclassified to liabilities associated with oil and gas properties held for sale on the Unaudited Condensed Consolidated Balance Sheet. Under Emerging Issues Task Force (“EITF”) Issue No. 03-13, we determined that these sales do not qualify for discontinued operations reporting.

The following table presents the assets and liabilities associated with the oil and gas properties held for sale in the DJ Basin and Hingeline Prospect as of September 30, 2007 (in thousands):

Proved oil and gas properties	$	319
Unevaluated oil and gas properties	$	2,230
Noncurrent liabilities	$	43

For the nine months ended September 30, 2007, total production volumes associated with the DJ Basin properties currently held for sale were 15.0 MMcfe. There are no producing properties within the Hingeline Prospect.

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 a $10.5 million pre-tax gain after various purchase price adjustments incurred in the normal course of business, which is included in other operating revenues in the Unaudited Condensed Consolidated Statement of Operations. Through the closing date of the sale on June 22, 2007, total production volumes associated with the Williston Basin properties of 1.2 Bcfe were included in the Company’s financial statements.

6. Note Payable to Bank

On March 17, 2006, the Company amended its credit facility (the “Amended Credit Facility”). The Amended Credit Facility had commitments of $400.0 million, which were expanded to $545.0 million as of November 6, 2007, and had an initial borrowing base of $280.0 million. Based on mid-year 2007 reserves, the borrowing base was increased to $385.0 million on November 6, 2007. 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 September 30, 2007, borrowings outstanding under the Amended Credit Facility totaled $207.0 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 nine months ended September 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		2,837
Liabilities settled		(3,537	)
Accretion expense		2,233
Revisions to estimate		22
End of period	$	34,153
Less: current asset retirement obligations		801
Long-term asset retirement obligations	$	33,352

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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.

Oil and Gas Commodity Hedges

The Company periodically uses financial derivative 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 financial commodity swap and collar contracts to fix the floor and ceiling prices we receive for a portion of our natural gas and oil production. The Company does not enter into derivative instruments for speculative or trading purposes. Our natural gas and oil derivative financial instruments are accounted for in accordance with SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.As of September 30, 2007, the Company has hedge contracts in place through 2009 for a total of 585,800 Bbls of crude oil and 50,905,500 MMBtu of natural gas anticipated production.

In addition to financial transactions, the Company is a party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas revenues at the time of settlement, which in turn affects average realized natural gas prices.

All derivative instruments, other than those that meet the normal purchase and sales exceptions as mentioned above, are recorded at fair market value and included in the Unaudited Condensed Consolidated Balance Sheets as assets or liabilities. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Realized gains and losses on cash flow hedges are transferred from comprehensive income and recognized in earnings and included within oil and gas production revenues in the Unaudited Condensed Consolidated Statements of Operations as the associated production occurs. Unrealized gains and losses from the change in the fair value and realized gains and losses of derivative instruments that do not qualify as cash flow hedges, as well as the ineffective portion of hedge derivatives are reported in earnings in the Unaudited Condensed Consolidated Statements of Operations.

At September 30, 2007, the estimated fair value of all of our derivative instruments was a net asset of $52.0 million comprised of current and noncurrent assets and liabilities. The Company will reclassify the appropriate amounts to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of September 30, 2007 to be reclassified from other comprehensive income to net income in the next 12 months would be approximately $25.6 million for our cash flow hedges. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. The Company anticipates that all originally forecasted transactions related to our cash flow hedges will occur by the end of the originally specified time periods. Ineffectiveness related to our derivative instruments was de minimis.

The Company was a party to various swap and collar contracts for natural gas based on Colorado Interstate Gas Rocky Mountains (“CIGRM”) and Northwest Pipeline Rocky Mountains (“NORRM”) indices that settled during the nine months ended September 30, 2006 and 2007. As a result, the Company recognized an increase of natural gas production revenues related to these contracts of $5.9 million and $29.6 million in the three months ended September 30, 2006 and 2007, respectively, and $10.2 million and $57.8 million in the nine months ended September 30, 2006 and 2007, respectively. The Company also was a party to various collar contracts for oil based on a WTI index recognizing a reduction to oil production revenues related to these contracts of $1.3 million and $0.03 million in the three months ended September 30, 2006 and 2007, respectively, and a reduction of $3.5 million and an increase of $0.3 million in the nine months ended September 30, 2006 and 2007, respectively.

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. Changes in fair value of the interest rate swaps or collars are reported in other comprehensive income, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. The derivatives were structured to mirror the critical terms of the hedged debt instruments; therefore, no ineffectiveness has been recorded in earnings.

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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 September 30, 2007, the Company had received $0.08 million in settlement payments, which were deducted from interest expense during the nine months ended September 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 September 30, 2007 to be reclassified from other comprehensive income to net income in the next 12 months would be approximately $0.02 million. At September 30, 2007, the estimated fair value of the interest rate derivatives was a net asset of $0.05 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 Unaudited 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 September 30, 2007, the Company’s balance sheet reflected a net deferred tax liability of $119.6 million, of which $19.3 million pertains to a net deferred tax liability of derivative instruments reflected in other comprehensive income.

Income tax expense for the three months ended September 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 its common stock 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 the Company’s credit facility and a bridge loan.

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 September 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.

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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 September 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 nine months ended September 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
Unrealized change in fair value of hedges		(53,101	)		19,780			(33,321	)
Reclassification adjustment for realized gains on hedges included in net income		58,224			(21,688	)		36,536
Accumulated other comprehensive income—September 30, 2007	$	51,930		$	(19,344	)	$	32,586

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, changes in 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 and in our Annual Report on Form 10-K for the year ended December 31, 2006 under the “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” sections, 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 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 Basin properties.

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Results of Operations

The financial information for the nine and three months ended September 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.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2007

	Nine months Ended September 30,				Increase (Decrease)
	2006		2007		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil and gas production revenues	$	256,179	$	268,194	$	12,015		5	%
Other		28,618		13,094		(15,524	)	(54	)%
Operating Expenses
Lease operating expense		21,522		32,932		11,410		53	%
Gathering and transportation expense		11,528		15,265		3,737		32	%
Production tax expense		21,252		14,916		(6,336	)	(30	)%
Exploration expense		7,258		6,762		(496	)	(7	)%
Impairment, dry hole costs and abandonment expense		12,187		10,481		(1,706	)	(14	)%
Depreciation, depletion and amortization expense		98,314		124,928		26,614		27	%
General and administrative expense (1)		20,695		22,475		1,780		9	%
Non-cash stock-based compensation (1)		4,800		6,942		2,142		45	%
Total operating expenses	$	197,556	$	234,701	$	37,145		19	%
Production Data:
Natural gas (MMcf)		34,955		41,181		6,226		18	%
Oil (MBbls)		498		463		(35	)	(7	)%
Combined volumes (MMcfe)		37,943		43,959		6,016		16	%
Daily combined volumes (MMcfe/d)		139		161		22		16	%
Average Prices (includes effects of realized hedges) (2):
Natural gas (per Mcf)	$	6.55	$	5.86	$	(0.69	)	(11	)%
Oil (per Bbl)		54.89		58.08		3.19		6	%
Combined (per Mcfe)		6.75		6.10		(0.65	)	(10	)%
Average Costs (per Mcfe):
Lease operating expense	$	0.57	$	0.75	$	0.18		32	%
Gathering and transportation expense		0.30		0.35		0.05		17	%
Production tax expense		0.56		0.34		(0.22	)	(39	)%
Depreciation, depletion and amortization (3)		2.60		2.91		0.31		12	%
General and administrative (4)		0.55		0.51		(0.04	)	(7	)%

(1) Non-cash stock-based compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $25.5 million and $29.4 million for the nine months ended September 30, 2006 and 2007, respectively, in the Unaudited 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 realized hedging transactions. As a result of our realized hedging transactions, natural gas and oil production revenues were increased by $6.7 million and $58.1 million for the nine months ended September 30, 2006 and 2007, respectively. Before the effect of hedging contracts, the average price we received for natural gas and oil for the nine months ended September 30, 2006 was $6.26 per Mcf and $61.83 per Bbl, respectively, compared with $4.45 per Mcf and $57.48 per Bbl, respectively, for the nine months ended September 30, 2007.

(3) The depreciation, depletion and amortization expense (“DD&A”) per Mcfe as calculated based on the DD&A expense and MMcfe production data presented in the table for the nine months ended September 30, 2007 is $2.84. However, the DD&A rate

16

per Mcfe for the nine months ended September 30, 2007 of $2.91, as presented, excludes production of 1,195 MMcfe associated with our properties that were classified as held for sale in the Williston Basin and the properties that remain 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 Unaudited Condensed Consolidated Statement of Operations, were $0.67 for the nine months ended September 30, 2006 and 2007.

Production Revenues.Production revenues increased from $256.2 million for the nine months ended September 30, 2006 to $268.2 million for the nine months ended September 30, 2007 primarily due to a 16% increase in production, offset by a decrease in natural gas prices after the effect of realized hedges. The net decrease in prices on a Mcfe basis lowered production revenues by approximately $24.7 million, while production increases added approximately $36.7 million of production revenues, after natural production declines, so that new production from our drilling program more than offset natural production declines. Production increased in the Uinta and Piceance Basins by 68% and 31%, respectively. These increases in production were partially offset by decreases in the Wind River Basin of 36%, the Powder River Basin of 20% and the Williston Basin of 34%. Unscheduled third party plant downtime, pipeline curtailments, compressor maintenance and intentional well shut-ins due to low gas daily prices in the Rocky Mountain region resulted in production volumes being an estimated 1.5 Bcf lower than well capacity for the nine months ended September 30, 2007. Additional information concerning production is in the following table:

	Nine Months Ended September 30, 2006			Nine Months Ended September 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	32	11,180	11,372	33	18,851	19,049	3	%	69	%	68	%
Piceance Basin	134	9,447	10,251	197	12,274	13,456	47	%	30	%	31	%
Wind River Basin	35	8,791	9,001	30	5,625	5,805	(14	)%	(36	)%	(36	)%
Powder River Basin	—	5,391	5,391	—	4,319	4,319	—		(20	)%	(20	)%
Williston Basin (1)	278	104	1,772	184	73	1,177	(34	)%	(30	)%	(34	)%
Other	19	42	156	19	39	153	—		(7	)%	(2	)%
Total	498	34,955	37,943	463	41,181	43,959	(7	)%	18	%	16	%

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

The production increase in the Uinta Basin reflects our continuing exploration and development activities in the West Tavaputs field. During the nine months ended September 30, 2007, we had initial sales on 26 new gross wells. The production increase in the Piceance Basin is the result of our continued development activities with initial sales on 48 new gross wells. 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 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. This was partially offset by initial sales on 98 new gross wells for the nine months ended September 30, 2007. As of September 30, 2007, we had 118 net operated coal bed methane wells in the dewatering stage with little or no production. Projects to expand gathering capacity in the Powder River Basin are expected to be completed in the fourth quarter of 2007.

Hedging Activities.During the nine months ended September 30, 2006, approximately 42% of our natural gas volumes and 41% of our oil volumes were hedged, resulting in an increase in revenues from realized hedges of $6.7 million. During the nine months ended September 30, 2007, approximately 64% of our natural gas volumes and 47% of our oil volumes were hedged, resulting in an increase in revenues from realized hedges of $58.1 million.

Other Operating Revenues.Other operating revenues decreased from $28.6 million for the nine months ended September 30, 2006 to $13.1 million for the nine months ended September 30, 2007. Other operating revenues for the first nine months of 2006 consisted of gains realized on joint exploration agreements entered into and other property sales in numerous properties, including the Powder River, Paradox, Williston, Wind River, Big Horn, Montana Overthrust and DJ Basins. Other operating revenues for the first nine months of 2007 primarily included a 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.The increase in lease operating expense from $0.57 per Mcfe for the nine months ended September 30, 2006 to $0.75 per Mcfe for the nine months ended September 30, 2007 is primarily the result of increased expenses in the Powder River, Wind River and Piceance Basins. Lease operating expense increased in the Powder River Basin from $1.00 per Mcfe for the nine months ended September 30, 2006 to $1.72 per Mcfe for the nine months ended September 30, 2007 due to substantially higher water handling charges on dewatering wells in new pilot areas that have no offsetting gas production as yet. Lease operating expenses in the Powder River Basin were also adversely affected by the basin-wide pipeline curtailments. As of September 30, 2007, we had 118 net operated coal bed methane wells in the dewatering stage. Lease operating expense increased in

17

the Wind River Basin from $0.54 per Mcfe for the nine months ended September 30, 2006 to $1.03 per Mcfe for the nine months ended September 30, 2007 due to the natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields, while actual lease operating expenses have remained relatively stable or increased. Lease operating expense increased in the Piceance Basin from $0.37 per Mcfe for the nine months ended September 30, 2006 to $0.64 per Mcfe for the nine months ended September 30, 2007 as a result of higher than expected water transportation and disposal costs. The following table displays the lease operating expense per Mcfe by basin:

	Nine months Ended September 30, 2006				Nine months Ended September 30, 2007				%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		(% per Mcfe)
Piceance Basin	$	3,796	$	0.37	$	8,628	$	0.64	73	%
Uinta Basin		4,071		0.36		7,562		0.40	11	%
Powder River Basin		5,402		1.00		7,446		1.72	72	%
Wind River Basin		4,881		0.54		5,963		1.03	91	%
Williston Basin		2,752		1.55		2,736		2.32	50	%
Other		620		3.95		597		3.91	(1	)%
Total	$	21,522		0.57	$	32,932		0.75	32	%

Gathering and Transportation Expense.Gathering and transportation expense increased from $0.30 per Mcfe for the nine months ended September 30, 2006 to $0.35 per Mcfe for the nine months ended September 30, 2007 due to additional long-term firm transportation and firm processing contracts entered into throughout 2007. 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. In addition, we have entered into long-term firm processing contracts on a portion of our production in the Uinta Basin to avoid possible production curtailments that may arise due to limited processing capacity. Included in gathering and transportation expense is $0.07 and $0.08 per Mcfe of transportation expense along with $0.01 and $0.06 per Mcfe of processing expense from long-term contracts for the nine months ended September 30, 2006 and 2007, respectively.

Production Tax Expense.Total production taxes decreased from $21.3 million for the nine months ended September 30, 2006 to $14.9 million for the nine months ended September 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, such as the Piceance and Uinta Basins as compared to the Wind River and Powder River Basins. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 8.5% for the nine months ended September 30, 2006 and 7.1% for the nine months ended September 30, 2007. Production taxes are primarily based on the wellhead values of production and the 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.

Exploration Expense.Exploration costs decreased from $7.3 million for the nine months ended September 30, 2006 to $6.8 million for the nine months ended September 30, 2007. Exploration costs for the nine months ended September 30, 2006 consisted of $6.3 million for seismic programs principally in the Wind River Basin, DJ Basin and Montana Overthrust, along with $1.0 million for delay rentals and other costs. Exploration costs for the nine months ended September 30, 2007 consisted of $5.6 million for seismic programs, principally in the Montana Overthrust, Paradox Basin, and Big Horn Basin, along with $1.2 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 $12.2 million during the nine months ended September 30, 2006 to $10.5 million during the nine months ended September 30, 2007. For the nine months ended September 30, 2006, impairments were $1.2 million, abandonments were $0.9 million and dry hole costs were $10.1 million for dry holes in the Williston and Uinta Basins. For the nine months ended September 30, 2007, impairments were $2.3 million, abandonments were $1.5 million and dry hole costs were $6.7 million for dry holes in the Wind River and Uinta Basins, along with the Draco 10-15 in the Montana Overthrust Area. The Draco 10-15 was tested and determined to be non-commercial in the zones from the Mission Canyon and below; thus, a proportionate share of the well cost in the amount of $1.9 million 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 nine months ended September 30, 2007. We are currently in the process of selling these properties.

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We account for oil and gas exploration and production activities using the successful efforts method under which we capitalize exploratory well costs until a determination is made as to whether or not the wells have found proved reserves. If proved reserves are not assigned to an exploratory well, the costs of drilling the well are charged to expense. Otherwise, the costs remain capitalized and are depleted as production occurs. The following table shows the costs of exploratory wells for which drilling was completed and which are included in unevaluated oil and gas properties as of September 30, 2007 pending determination of whether the wells will be assigned proved reserves. The following table does not include $6.8 million related to exploratory wells in progress for which drilling had not been completed at September 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	$	33,429	$	26,725	$	7,889	$	15,408	$	83,451

The majority of the $15.4 million of exploratory well costs 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.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense (“DD&A”) was $98.3 million for the nine months ended September 30, 2006 compared to $124.9 million for the nine months ended September 30, 2007. Of the increase, $12.7 million is due to an increase in production, excluding the properties held for sale in the Williston and DJ Basins, and $13.9 million is due to an increased DD&A rate for the nine months ended September 30, 2007. During the nine months ended September 30, 2006, the weighted average depletion rate was $2.60 per Mcfe. For the nine months ended September 30, 2007, the weighted average depletion rate was $2.91 per Mcfe. The DD&A rate for the nine months ended September 30, 2007 excludes production of 1,195 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 nine months ended September 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. General and administrative expense, excluding non-cash stock-based compensation increased from $20.7 million in the nine months ended September 30, 2006 to $22.5 million in the nine months ended September 30, 2007. This increase was primarily due to increased personnel required for our capital program and production levels. As of September 30, 2007, we had 153 full time employees in our corporate office compared to 134 as of September 30, 2006. However, on a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, decreased from $0.55 per Mcfe for the nine months ended September 30, 2006 to $0.51 per Mcfe for the nine months ended September 30, 2007 due to increased production.

Non-cash charges for stock-based compensation were $4.8 million for the nine months ended September 30, 2006 compared to $6.9 million for the nine months ended September 30, 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 nine months ended September 30, 2007.

Interest Expense.Interest expense increased to $8.7 million in the nine months ended September 30, 2007 from $7.5 million in the prior year period. The increase is due to higher debt levels in the nine month period ended September 30, 2007 to fund exploration and development activities. The weighted average outstanding balance under our credit facility for the nine months ended September 30, 2007 was $185.8 million compared to $150.4 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 nine months ended September 30, 2007 was 7.1%. We capitalized interest costs of $1.3 million for the nine months ended September 30, 2007.

Income Tax Expense.Our effective tax rates were 37.5% and 38.7% in the nine months ended September 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 Accounting Principles Bulletin (“APB”) Opinion No. 25,Accounting for Stock Issued to Employees, and SFAS No. 123 (revised 2004),Share-Based Payment(“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 only to the alternative minimum tax (“AMT”) in the next year. We have a significant deferred tax asset associated with net operating loss carryforwards (“NOLs”). It is more likely than not that we will use these NOLs to offset and minimize current tax liabilities, including AMT, in future years.

19

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

	Three Months Ended September 30,				Increase (Decrease)
	2006		2007		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil and gas production revenues	$	80,468	$	82,216	$	1,748		2	%
Other		23,944		39		(23,905	)	nm	*
Operating Expenses
Lease operating expense		7,329		9,846		2,517		34	%
Gathering and transportation expense		3,510		4,873		1,363		39	%
Production tax expense		6,473		4,220		(2,253	)	(35	)%
Exploration expense		3,333		4,004		671		20	%
Impairment, dry hole costs and abandonment expense		5,099		3,609		(1,490	)	(29	)%
Depreciation, depletion and amortization expense		34,506		43,070		8,564		25	%
General and administrative expense (1)		6,952		7,610		658		9	%
Non-cash stock-based compensation (1)		1,633		2,461		828		51	%
Total operating expenses	$	68,835	$	79,693	$	10,858		16	%
Production Data:
Natural gas (MMcf)		11,637		14,226		2,589		22	%
Oil (MBbls)		165		85		(80	)	(48	)%
Combined volumes (MMcfe)		12,627		14,736		2,109		17	%
Daily combined volumes (MMcfe/d)		137		160		23		17	%
Average Prices (includes effects of hedges) (2):
Natural gas (per Mcf)	$	6.09	$	5.36	$	(0.73	)	(12	)%
Oil (per Bbl)		58.05		70.26		12.21		21	%
Combined (per Mcfe)		6.37		5.58		(0.79	)	(12	)%
Average Costs (per Mcfe):
Lease operating expense	$	0.57	$	0.67	$	0.10		18	%
Gathering and transportation expense		0.28		0.33		0.05		18	%
Production tax expense		0.51		0.29		(0.22	)	(43	)%
Depreciation, depletion and amortization (3)		2.75		2.92		0.17		6	%
General and administrative (4)		0.55		0.52		(0.03	)	(5	)%

* Not meaningful

(1) Non-cash stock-based compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $8.6 million and $10.1 million for the three months ended September 30, 2006 and 2007, respectively, in the Unaudited 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 realized hedging transactions. As a result of our realized hedging transactions, natural gas and oil production revenues were increased by $4.6 million for the three months ended September 30, 2006 and were increased by $29.6 million for the three months ended September 30, 2007. Before the effect of hedging contracts, the average price we received for natural gas and oil for the three months ended September 30, 2006 was $5.58 per Mcf and $65.97 per Bbl, respectively, compared with $3.28 per Mcf and $70.57 per Bbl, respectively, for the three months ended September 30, 2007.

(3) DD&A rate per Mcfe excludes production of 3,718 Mcfe associated with our properties that were classified as held for sale in the DJ Basin, as these were not depleted throughout the third quarter of 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 Unaudited Condensed Consolidated Statement of Operations, were $0.68 for the three months ended September 30, 2006 and 2007.

20

Production Revenues.Production revenues increased from $80.5 million for the three months ended September 30, 2006 to $82.2 million for the three months ended September 30, 2007 primarily due to a 17% increase in production, offset by a decrease in natural gas prices after the effect of realized hedges. The net decrease in prices on a Mcfe basis lowered production revenues by approximately $10.0 million, while production increases added approximately $11.7 million of production revenues, after natural production declines, so that new production from our drilling program more than offset natural declines. Unscheduled third party plant downtime, pipeline curtailments, compressor maintenance and intentional well shut-ins due to low gas daily prices resulted in production volumes being an estimated 1.5 Bcf lower than well capacity for the three months ended September 30, 2007. Additional information concerning production is in the following table:

	Three Months Ended September 30, 2006			Three Months Ended September 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	8	3,308	3,356	11		6,753		6,819		38	%	104	%	103	%
Piceance Basin	54	3,742	4,066	58		4,220		4,568		7	%	13	%	12	%
Wind River Basin	10	2,772	2,832	11		1,741		1,807		10	%	(37	)%	(36	)%
Powder River Basin	—	1,771	1,771	—		1,498		1,498		—		(15	)%	(15	)%
Williston Basin	87	32	554	(2	)	(4	)	(16	)	(102	)%	(113	)%	(103	)%
Other	6	12	48	7		18		60		17	%	50	%	25	%
Total	165	11,637	12,627	85		14,226		14,736		(48	)%	22	%	17	%

The production increase in the Uinta Basin reflects our continuing exploration and development activities in the West Tavaputs. For the three months ended September 30, 2007 we had initial sales on 10 new gross wells. The production increase in the Piceance Basin is the result of our continued development activities with initial sales on 21 new gross wells. 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 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, along with pipeline curtailments across the basin. This production decrease was partially offset by initial sales on 28 new gross wells in the Powder River Basin for the three months ended September 30, 2007. As of September 30, 2007, we had 118 net operated coal bed methane wells in the dewatering stage with little or no production. Projects to expand gathering capacity in the Powder River Basin are expected to be completed in the fourth quarter of 2007.

Hedging Activities.During the three months ended September 30, 2006, approximately 42% of our natural gas and oil volumes were hedged, resulting in an increase in revenues from realized hedges of $4.6 million. During the three months ended September 30, 2007, approximately 69% of our natural gas volumes and 87% of our oil volumes were hedged, resulting in an increase in revenues from realized hedges of $29.6 million.

Other Operating Revenues. Other operating revenues decreased from $23.9 million for the three months ended September 30, 2006 to $0.04 million for the three months ended September 30, 2007. The decrease is primarily due to gains realized on joint exploration agreements entered into during the three months ended September 30, 2006, while there were no significant gains realized during the three months ended September 30, 2007.

Lease Operating Expense.The increase in lease operating expense from $0.57 per Mcfe in the third quarter of 2006 to $0.67 per Mcfe in the current year period is primarily the result of increases in the Powder River, Wind River and Piceance Basins. Lease operating expense increased in the Powder River Basin from $1.12 per Mcfe in the third quarter of 2006 to $1.76 per Mcfe in the current year period due to substantially higher water handling charges on dewatering wells in new pilot areas that have no offsetting gas production as yet. Lease operating expenses in the Powder River Basin were also adversely affected by the basin-wide pipeline curtailments. As of September 30, 2007, we had 118 net operated coal bed methane wells in the dewatering stage. Lease operating expense increased in the Wind River Basin from $0.55 per Mcfe in the third quarter of 2006 to $1.00 per Mcfe in the current year period due to the natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields, while actual lease operating expenses have remained stable or increased. Lease operating expense increased in the Piceance Basin from $0.37 per Mcfe in the third quarter of 2006 to $0.64 per Mcfe in the current year period as a result of higher than expected water transportation and disposal costs. Overall, lease operating expenses decreased from $0.95 per Mcfe in the second quarter of 2007 to $0.67 per Mcfe in the third quarter of 2007 due to efficiencies from water handling systems, fewer workovers, and increased production, primarily in the Piceance and Uinta Basins. The Company expects these costs on a per Mcfe basis to continue to decrease in the fourth quarter. The following table displays the lease operating expense per Mcfe by basin:

	Three Months Ended September 30, 2006				Three Months Ended September 30, 2007					%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)			(% per Mcfe)
Piceance Basin	$	1,494	$	0.37	$	2,932	$	0.64		73	%
Uinta Basin		1,316		0.39		2,228		0.33		(15	)%
Powder River Basin		1,986		1.12		2,636		1.76		57	%
Wind River Basin		1,559		0.55		1,810		1.00		82	%
Williston Basin		778		1.41		63		(3.84	)	(372	)%
Other		196		3.99		177		3.08		(23	)%
Total	$	7,329		0.57	$	9,846		0.67		18	%

21

Gathering and Transportation Expense.Gathering and transportation expense increased from $0.28 per Mcfe in the third quarter of 2006 to $0.33 per Mcfe in the current year period due to additional long-term firm transportation and firm processing contracts entered into throughout 2007. 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. In addition, we have entered into long-term firm processing contracts on a portion of our production in the Uinta Basin to avoid possible production curtailments that may arise due to limited processing capacity. Included in gathering and transportation expense is $0.07 and $0.09 per Mcfe of transportation expense along with $0.02 and $0.07 per Mcfe of processing expense from long-term contracts for the three months ended September 30, 2006 and 2007, respectively.

Production Tax Expense.Total production taxes decreased from $6.5 million for the three months ended September 30, 2006 to $4.2 million for the three months ended September 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, such as the Piceance and Uinta Basins as compared to the Wind River and Powder River Basins. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 8.5% in the third quarter of 2006 and 8.0% for the current year period. Production taxes are primarily based on the wellhead values of production and the 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.

Exploration Expense. Exploration costs increased from $3.3 million in the third quarter of 2006 to $4.0 million in the current year period. The costs for the three months ended September 30, 2006 include $3.0 million for seismic programs principally in the Wind River Basin and the Montana Overthrust along with $0.3 million for delay rentals and other costs. The costs for the three months ended September 30, 2007 consisted of $3.6 million for seismic programs, principally in the Montana Overthrust and Big Horn Basin and $0.4 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 $5.1 million during the third quarter of 2006 to $3.6 million during the current year period. For the three months ended September 30, 2006, impairments were $1.2 million, abandonments were $0.2 million and dry hole costs were $3.7 million for dry holes in the Williston and Uinta Basins. For the three months ended September 30, 2007, abandonments were $0.5 million and dry hole costs were $3.1 million for dry holes in the Wind River Basin, along with the Draco 10-15 in the Montana Overthrust Area. The Draco 10-15 was tested and determined to be non-commercial in the zones from the Mission Canyon and below; thus, a proportionate share of the well cost in the amount of $1.9 million 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 Cedar Camp properties within the Uinta Basin, the Company, based upon its fair value analysis, recognized a $1.2 million non-cash impairment charge for the three months ended September 30, 2006. The properties were subsequently sold in December 2006.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense was $34.5 million for the three months ended September 30, 2006 compared to $43.1 million for the three months ended September 30, 2007. Of the increase, $6.0 million is due to the increase in production, excluding the Williston and DJ Basins, and $2.6 million is due to an increased depletion rate for the three months ended September 30, 2007. During the three months ended September 30, 2006, the weighted average depletion rate was $2.75 per Mcfe. In the three months ended September 30, 2007, the weighted average depletion rate was $2.92 per Mcfe. Under successful efforts accounting, depletion expense is separately computed for each producing area based on geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average depletion rate for current production. For the three months ended September 30, 2007, the relationship of capital expenditures, proved reserves and production from certain producing areas yielded a higher weighted average depletion rate than the comparable prior year period. Future depletion rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

22

General and Administrative Expense.General and administrative expense, excluding non-cash stock-based compensation increased from $7.0 million in the three months ended September 30, 2006 to $7.6 million in the three months ended September 30, 2007. This increase was primarily due to increased personnel required for our capital program and production levels. As of September 30, 2007, we had 153 full time employees in our corporate office compared to 134 as of September 30, 2006. However, on a per unit of production basis, general and administrative expense, excluding non-cash stock-based compensation, decreased from $0.55 per Mcfe in the third quarter of 2006 to $0.52 per Mcfe in the current year period due to increases in production.

Non-cash charges for stock-based compensation were $1.6 million in the third quarter of 2006 compared to $2.5 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 2007.

Interest Expense.Interest expense decreased to $2.7 million in the three months ended September 30, 2007 from $3.2 million in the prior year period. The decrease was due to higher debt levels during the three month period ended September 30, 2006 to fund exploration and development activities. The weighted average outstanding balance under our credit facility for the three months ended September 30, 2006 was $201.5 million compared to $170.7 million in the current year period. This reduction in the weighted average outstanding balance is primarily attributable to a principal payment made on our credit facility from the proceeds received from the sale of our Williston Basin properties.

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. 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 September 30, 2006 and 2007 was 7.2%. We capitalized interest costs of $0.5 million and $0.4 million for the three months ended September 30, 2006 and 2007, respectively.

Income Tax Expense.Our effective tax rates were 38.3% and 40.3% in the three months ended September 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 Opinion No. 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 only to the AMT in the next year. We have a significant deferred tax asset associated with net operating loss NOLs. It is more likely than not that we will use these NOLs to offset and minimize current tax liabilities, including AMT, in future years.

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 September 30, 2007, our balance sheet reflected a cash balance of $52.0 million with a balance of $207.0 million outstanding on our credit facility. At September 30, 2007, the borrowing base under our credit facility was $340.0 million. The borrowing base was increased to $385.0 million on November 6, 2007.

Cash Flow from Operating Activities

Net cash provided by operating activities was $197.5 million and $198.2 million for the nine months ended September 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 $18.6 million and $26.6 million for the nine months ended September 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.

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To mitigate some of the potential negative impact on cash flow caused by changes in natural gas and oil prices, we have entered into financial commodity swap and collar contracts to receive fixed prices for a portion of our natural gas and oil production. At September 30, 2007, we had in place natural gas and crude oil financial collars and swaps covering portions of our 2007, 2008 and 2009 production. Our natural gas and oil derivative financial instruments are accounted for in accordance with SFAS No. 133.

In addition to financial transactions, the Company is a party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas revenues at the time of settlement, which in turn affects average realized natural gas prices.

All derivative instruments, other than those that meet the normal purchase and sales exceptions as mentioned above, are recorded at fair market value and included in the Unaudited Condensed Consolidated Balance Sheets as assets or liabilities. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the forecasted transaction occurs. Realized gains and losses on cash flow hedges are transferred from comprehensive income and recognized in earnings and included within oil and gas production revenues in the Unaudited Condensed Consolidated Statements of Operations as the associated production occurs. Unrealized gains and losses from the change in the fair value and realized gains and losses of derivative instruments that do not qualify as cash flow hedges, as well as the ineffective portion of hedge derivatives are reported in earnings in the Unaudited Condensed Consolidated Statements of Operations.

At September 30, 2007, the estimated fair value of all of our derivative instruments was a net asset of $52.0 million comprised of current and noncurrent assets and liabilities. The Company will reclassify the appropriate amounts to gains or losses included in natural gas and oil production operating revenues as the hedged production quantity is produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of September 30, 2007 to be reclassified from other comprehensive income to net income in the next 12 months would be approximately $25.6 million for our cash flow hedges. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. The Company anticipates that all originally forecasted transactions related to our cash flow hedges will occur by the end of the originally specified time periods. Ineffectiveness related to our derivative instruments was de minimis.

The Company has in place the following swap contracts and cashless collars (purchased put options and written call options) as of September 30, 2007 in order to hedge a portion of our natural gas and oil production for the fourth quarter of 2007, and for the years 2008 and 2009. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas production.

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Pricing		Weighted Average Ceiling Pricing		Weighted Average Fixed Price		Index Price (1)	Fair Market Value, in thousands
Cashless Collars:
2007
Natural gas	5,888,000	MMBtu	$	6.07	$	9.61		n/a	CIGRM	$	17,906
Oil	73,600	Bbls	$	55.00	$	79.85		n/a	WTI	$	(229	)
2008
Natural gas	12,810,000	MMBtu	$	6.50	$	10.00		n/a	CIGRM	$	9,550
Oil	183,000	Bbls	$	70.00	$	80.15		n/a	WTI	$	(114	)
Swap Contracts:
2007
Natural gas	5,447,500	MMBtu		n/a		n/a	$	6.20	CIGRM	$	11,753
Oil	18,400	Bbls		n/a		n/a	$	76.83	WTI	$	(62	)
2008
Natural gas	16,290,000	MMBtu		n/a		n/a	$	6.95	CIGRM	$	11,825
Natural gas	4,280,000	MMBtu		n/a		n/a	$	6.74	PEPL	$	814
Oil	201,300	Bbls		n/a		n/a	$	73.48	WTI	$	(574	)
2009
Natural gas	6,190,000	MMBtu		n/a		n/a	$	7.26	CIGRM	$	1,090
Oil	109,500	Bbls		n/a		n/a	$	73.83	WTI	$	27

(1) CIGRM refers to Colorado Interstate Gas Rocky Mountains and PEPL refers to Panhandle Eastern Pipe Line Company 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.

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The following table includes all hedges entered into subsequent to September 30, 2007 through November 1, 2007.

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Pricing	Weighted Average Ceiling Pricing	Weighted Average Fixed Price		Index Price
Swap Contracts:
2008
Natural gas	16,350,000	MMBtu	n/a	n/a	$	6.58	CIGRM
Natural gas	2,880,000	MMBtu	n/a	n/a	$	6.89	PEPL
Oil	9,150	Bbls	n/a	n/a	$	81.75	WTI
2009
Natural gas	3,040,000	MMBtu	n/a	n/a	$	6.88	CIGRM
Oil	27,375	Bbls	n/a	n/a	$	76.72	WTI

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.

Capital Expenditures

Our capital expenditures were $428.6 million and $316.4 million for the nine months ended September 30, 2006 and 2007, respectively. Total capital expenditures for the nine months ended September 30, 2006 include $155.0 million for the acquisition of both proved and unevaluated properties (including $37.2 million of a non-cash deferred tax liability associated with the difference between the tax basis of the properties acquired in the CH4 acquisition and the book basis attributed to the properties under the purchase method of accounting), $253.7 million for drilling, development, exploration and exploitation of natural gas and oil properties, $18.2 million for geologic and geophysical costs, which are expensed under successful efforts accounting as exploration expense, impairment, dry hole costs and abandonment expense, and $1.7 million for furniture, fixtures and equipment. Total capital expenditures for the nine months ended September 30, 2007 consist of $21.0 million for acquisitions of properties, $277.1 million for drilling, development, exploration and exploitation of natural gas and oil properties, $14.9 million for geologic and geophysical costs and exploratory dry holes and abandonment costs and $3.4 million for furniture, fixtures and equipment.

Unevaluated properties increased $35.4 million to $256.6 million at September 30, 2007, including $2.2 million related to unevaluated properties in the DJ Basin and Hingeline Prospect that are currently classified as held for sale at September 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 nine months ended September 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 $325.0 to $335.0 million for development drilling and facilities, $70.0 to $80.0 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, $170.0 to $175.0 million in the Uinta, $30.0 million in the Powder River, $10.0 million in the Wind River, and $25.0 to $50.0 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 and available borrowing capacity under our credit facility will be sufficient to fund our capital expenditures at current levels for the next twelve months. 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 capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity by prioritizing

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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.On March 17, 2006, the Company amended its credit facility (the “Amended Credit Facility”). The Amended Credit Facility, which matures on March 17, 2011, had commitments of $400.0 million, which were expanded to $545.0 million as of November 6, 2007 with the addition of new lenders, and had an initial borrowing base of $280.0 million. Based on mid-year 2007 reserves and our hedge position, the borrowing base was increased to $385.0 million on November 6, 2007. Future borrowing bases will be computed based on proved natural gas and oil reserves and estimated future cash flows from those 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 September 30, 2007, borrowings outstanding under the Amended Credit Facility totaled $207.0 million. The Amended Credit Facility also contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants for all periods.

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 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. Changes in fair value of the interest rate swaps or collars are reported in other comprehensive income, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. The derivatives were structured to mirror the critical terms of the hedged debt instruments; therefore, no ineffectiveness has been recorded in earnings.

As of September 30, 2007, the Company had received $0.08 million in settlement payments, which were deducted from interest expense throughout the first nine months of 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 September 30, 2007 to be reclassified from other comprehensive income to net income in the next 12 months would be approximately $0.02 million. At September 30, 2007, the estimated fair value of the interest rate derivatives was a net asset of $0.05 million.

Contractual Obligations.A summary of our contractual obligations as of, and subsequent to, September 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)	$	—	$	—	$	—	$	207,000	$	—	$	—	$	207,000
Other commitments for developing oil and gas properties		13,954		—		—		—		—		—		13,954
Office and office equipment leases and other		2,060		1,681		1,694		771		116		—		6,322
Firm transportation and processing agreements		18,489		22,272		23,194		23,450		23,567		132,410		243,382
Asset Retirement Obligations (2)(3)		801		9,033		1,591		769		1,166		20,793		34,153
Total	$	35,304	$	32,986	$	26,479	$	231,990	$	24,849	$	153,203	$	504,811

(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.

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(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 processing rights and firm transportation capacity 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 September 30, 2007 for a total of $5.0 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 unaudited 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.

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 nine months ended September 30, 2007, our income before income taxes, including hedge settlements, would have decreased by approximately $1.3 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 enter 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.

In addition to financial transactions, we are a party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. Under SFAS No. 133, these physical commodity contracts qualify for the normal purchases and normal sales exception and therefore, are not subject to hedge accounting or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas revenues at the time of settlement, which in turn affects average realized natural gas prices.

Through November 1, 2007, we entered into financial hedges for 11,335,500 MMBtu of natural gas production and approximately 92,000 Bbls of oil production for the fourth quarter of 2007. We also had hedges in place for 52,610,000 MMBtu and 9,230,000 MMBtu of natural gas production and 393,450 Bbls and 136,875 Bbls of oil production for the years 2008 and 2009, respectively. These hedges are summarized in the tables presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cash Flow from Operating Activities.”

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Commodity Hedges

Commodity Swaps

Through a price swap, we have fixed the price we will receive on a portion of our natural gas and oil production for the fourth quarter of 2007 and the years 2008 and 2009. The weighted average price we will receive for the fourth quarter of 2007 natural gas is $6.20 per MMBtu for a CIGRM price, $6.77 per MMBtu for 2008 and $7.14 per MMBtu for 2009. The weighted average price we will receive for a PEPL price for 2008 is $6.80 per MMBtu. The weighted average price we will receive for the fourth quarter of 2007 oil is $76.83 per Bbl for a WTI price, $73.84 per Bbl for 2008 and $74.41 per Bbl for 2009. The tables 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 through November 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 for the fourth quarter of 2007 and the years 2008 and 2009. The weighted average minimum, or floor, price we will receive for the fourth quarter 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 fourth quarter 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 quarter of 2007 and the year 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 tables 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 through November 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.

Interest Rate Risks

At September 30, 2007, we had debt outstanding of $207.0 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 nine months ended September 30, 2007 was 6.7%. A one hundred basis point (1.0%) increase in each of the average LIBOR rate and federal funds rate for the nine months ended September 30, 2007 would have resulted in an estimated $1.4 million increase in interest expense assuming a similar average debt level to the nine months ended September 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(e) and 15d-15(e), were, as of the end of the period covered by this report, effective.

Changes in Internal Control over Financial Reporting

During July 2007, the Company implemented new computer software designed to enhance the efficiency of oil and gas production accounting and reporting. There has been no other change in our internal control over financial reporting during the third fiscal quarter of 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

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

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

The following table contains information about our acquisitions of equity securities during the three months ended September 30, 2007.

Issuer Purchases of Equity Securities

Period	Total Number of Shares (1)	Weighted Average Price Paid Per Share		Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
July 1 – 31, 2007	2,779	$	37.94	—	—
August 1 – 31, 2007	—		—	—	—
September 1 – 30, 2007	—		—	—	—
Total	2,779	$	37.94	—	—

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

Item 3. Defaults upon Senior Securities.

Not applicable.

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

Not applicable.

Item 5. Other Information.

Not applicable.

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Item 6. Exhibits.

Exhibit Number	Description of Exhibits
3.1	Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.4 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]
3.2	Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.5 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]
4.1	Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 3.2 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.2	Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
4.3	Stockholders’ Agreement, dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
4.4	Form of Rights Agreement concerning Shareholder Rights Plan, which includes as Exhibit A thereto the Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, and as Exhibits B thereto the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.5	Form of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, included as Exhibit A to Exhibit 4.4 above.
4.6	Form of Right Certificate, included as Exhibit B to Exhibit 4.4 above.
10.1(a)	Amended and Restated Credit Agreement, dated February 4, 2004, among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1(a) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.1(b)	First Amendment to Amended and Restated Credit Agreement dated as of September 1, 2004 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1(b) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.1(c)	Second Amended and Restated Credit Agreement dated March 17, 2006 among Bill Barrett Corporation and the banks named therein. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K reporting on event occurring March 17, 2006 filed with the SEC on March 22, 2006.]
10.1(d)	First Amendment to Second Amended and Restated Credit Agreement dated November 6, 2007 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 November 6, 2007 filed with the SEC on November 7, 2007.]
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).]

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10.5(b)*	Form of Tranche B Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(b) to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.6*	2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.7*	Form of Stock Option Agreement for 2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.15 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.8	Form of Management Rights Agreement between Bill Barrett Corporation and certain investors. [Incorporated by reference to Exhibit 10.16 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.9	Regulatory sideletter, dated March 28, 2002, between J.P. Morgan Partners (BHCA), L.P. and Bill Barrett Corporation. [Incorporated by reference to Exhibit 10.17 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.10*	Form of Change in Control Severance Protection Agreement revised as of November 16, 2006 for named executive officers. [Incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.]
10.11*	2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
10.12*	Revised Form of Stock Option Agreement for 2004 Stock Option Plan. [Incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.]
10.13*	Severance Plan. [Incorporated by reference to Exhibit 10.23 to the Company’s Registration Statement on Form S-1 (File No. 333-115445).]
31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32.1	Section 1350 Certification of Chief Executive Officer.
32.2	Section 1350 Certification of Chief Financial Officer.

* Indicates a management contract or compensatory plan or arrangement.

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SIGNATURES

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

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

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