Bill Barrett (BBG) 10-Q 2008 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, 2008

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.    x  Yes    ¨  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x	Accelerated filer  ¨	Non-accelerated filer  ¨	Smaller reporting company  ¨
		(Do not check if a smaller reporting company)

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

There were 45,133,491 shares of $0.001 par value common stock outstanding on October 24, 2008.

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	20
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	37
Item 4.	Controls and Procedures	38
PART II. OTHER INFORMATION		39
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	41
Item 4.	Submission of Matters to a Vote of Security Holders	41
Item 5.	Other Information	41
Item 6.	Exhibits	42
SIGNATURES		44

2

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30, 2008			December 31, 2007
	(in thousands, except share and per share data)
Assets:
Current Assets:
Cash and cash equivalents	$	87,404		$	60,285
Accounts receivable, net of allowance for doubtful accounts of $394 for September 30, 2008 and $303 for December 31, 2007		50,859			50,380
Prepayments and other current assets		8,249			3,425
Derivative assets		112,957			17,337
Total current assets		259,469			131,427
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		1,788,048			1,472,834
Unevaluated oil and gas properties, excluded from amortization		328,661			231,521
Oil and gas properties held for sale, net, excluded from amortization		1,120			2,303
Furniture, equipment and other		18,177			16,113
		2,136,006			1,722,771
Accumulated depreciation, depletion, amortization and impairment		(670,904	)		(526,939	)
Total property and equipment, net		1,465,102			1,195,832
Derivative Assets		77,412			—
Deferred Financing Costs and Other Noncurrent Assets		5,875			2,428
Total	$	1,807,858		$	1,329,687
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	125,690		$	84,773
Amounts payable to oil and gas property owners		20,785			22,209
Production taxes payable		43,792			24,819
Derivative liability and other current liabilities		184			2,414
Deferred income taxes		40,508			5,353
Total current liabilities		230,959			139,568
Note Payable to Bank		174,000			274,000
Convertible Senior Notes		172,500			—
Asset Retirement Obligations		39,248			35,003
Liabilities Associated with Assets Held for Sale		—			45
Deferred Income Taxes		189,407			99,149
Derivatives and Other Noncurrent Liabilities		1,127			8,411
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 45,100,858 and 44,760,955 and shares issued and outstanding at September 30, 2008 and December 31, 2007, respectively, with 584,048 and 564,100 shares subject to restrictions, respectively		45			44
Additional paid-in capital		756,882			742,492
Retained earnings		126,960			26,205
Treasury stock, at cost: zero shares at September 30, 2008 and December 31, 2007		—			—
Accumulated other comprehensive income		116,730			4,770
Total stockholders’ equity		1,000,617			773,511
Total	$	1,807,858		$	1,329,687

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,
	2008			2007			2008			2007
	(in thousands, except share and per share amounts)
Operating and Other Revenues:
Oil and gas production	$	155,050		$	82,216		$	463,759		$	268,194
Commodity derivative gain		8,490			—			3,647			—
Other		875			39			3,730			13,094
Total operating and other revenues		164,415			82,255			471,136			281,288
Operating Expenses:
Lease operating expense		12,548			9,846			32,391			32,932
Gathering and transportation expense		10,103			4,873			29,746			15,265
Production tax expense		13,519			4,220			37,405			14,916
Exploration expense		1,010			4,004			2,935			6,762
Impairment, dry hole costs and abandonment expense		463			3,609			5,618			10,481
Depreciation, depletion and amortization		49,681			43,070			149,798			124,928
General and administrative expense		13,654			10,071			42,220			29,417
Total operating expenses		100,978			79,693			300,113			234,701
Operating Income		63,437			2,562			171,023			46,587
Other Income and Expense:
Interest and other income		805			676			1,672			1,724
Interest expense		(3,846	)		(2,739	)		(11,407	)		(8,693	)
Total other income and expense		(3,041	)		(2,063	)		(9,735	)		(6,969	)
Income before Income Taxes		60,396			499			161,288			39,618
Provision for Income Taxes		24,331			266			60,533			15,343
Net Income	$	36,065		$	233		$	100,755		$	24,275
Net Income Per Common Share, Basic	$	0.81		$	0.01		$	2.27		$	0.55
Net Income Per Common Share, Diluted	$	0.80		$	0.01		$	2.23		$	0.55
Weighted Average Common Shares Outstanding, Basic		44,492,723			44,085,365			44,399,343			44,009,103
Weighted Average Common Shares Outstanding, Diluted		45,056,084			44,562,152			45,183,913			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			Total Stockholders’ Equity			Comprehensive Income
	(in thousands)
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, vesting of restricted stock and shares exchanged for exercise and tax withholding		—		7,602			—			(3,319	)		—			4,283
Stock-based compensation		—		10,723			—			—			—			10,723
Retirement of treasury stock		—		(3,319	)		—			3,319			—			—
Comprehensive income:
Net income		—		—			26,754			—			—			26,754		$	26,754
Effect of derivative financial instruments, net of $14,604 of taxes		—		—			—			—			(24,601	)		(24,601	)		(24,601	)
Total comprehensive income																		$	2,153
Balance — December 31, 2007	$	44	$	742,492		$	26,205		$	—		$	4,770		$	773,511
Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding		1		4,604			—			(3,051	)		—			1,554
Stock-based compensation		—		12,837			—			—			—			12,837
Retirement of treasury stock		—		(3,051	)		—			3,051			—			—
Comprehensive income:
Net income		—		—			100,755			—			—			100,755		$	100,755
Effect of derivative financial instruments, net of $(65,843) of taxes		—		—			—			—			111,960			111,960			111,960
Total comprehensive income																		$	212,715
Balance — September 30, 2008	$	45	$	756,882		$	126,960		$	—		$	116,730		$	1,000,617

See notes to unaudited condensed consolidated financial statements.

5

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended September 30,
	2008			2007
	(in thousands)
Operating Activities:
Net Income	$	100,755		$	24,275
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		149,798			124,928
Deferred income taxes		59,606			15,343
Impairment, dry hole costs and abandonment expense		5,618			10,481
Unrealized derivative gain		(4,610	)		—
Stock compensation and other non-cash charges		13,160			7,789
Amortization of deferred financing costs		1,186			352
Gain on sale of properties		(1,134	)		(11,537	)
Change in operating assets and liabilities:
Accounts receivable		(479	)		30,887
Prepayments and other assets		(4,633	)		(943	)
Accounts payable, accrued and other liabilities		3,372			(14,948	)
Amounts payable to oil and gas property owners		(1,424	)		4,796
Production taxes payable		18,973			6,781
Net cash provided by operating activities		340,188			198,204
Investing Activities:
Additions to oil and gas properties, including acquisitions		(384,775	)		(288,788	)
Additions of furniture, equipment and other		(1,957	)		(3,702	)
Proceeds from sale of properties		2,354			82,800
Net cash used in investing activities		(384,378	)		(209,690	)
Financing Activities:
Proceeds from debt		239,800			97,000
Principal payments on debt		(167,300	)		(78,000	)
Proceeds from sale of common stock		4,071			3,232
Deferred financing costs and other		(5,262	)		(82	)
Net cash provided by financing activities		71,309			22,150
Increase in Cash and Cash Equivalents		27,119			10,664
Beginning Cash and Cash Equivalents		60,285			41,322
Ending Cash and Cash Equivalents	$	87,404		$	51,986

See notes to unaudited condensed consolidated financial statements.

6

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

September 30, 2008

1. Organization

Bill Barrett Corporation (the “Company”), 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 in January 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States.

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 (“GAAP”) for interim financial information. Pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), they do not include all of the information and footnotes required by GAAP 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, 2008, our results of operations for the three and nine months ended September 30, 2008 and 2007 and cash flows for the nine months ended September 30, 2008 and 2007. Operating results for the three and nine months ended September 30, 2008 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, the 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, 2007 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 most 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 these 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 are also 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. The weighted average interest rates used to capitalize interest for the three and nine months ended September 30, 2008 were 5.1% and 5.3%, respectively, which include interest on both our 5% Convertible Senior Notes due 2028 (“Convertible Notes”) and our amended credit facility, commitment fees paid on the unused portion of our amended credit facility, amortization of deferred financing and debt issuance costs and the effects of interest rate hedges. The Company capitalized interest costs of $0.6 million and $1.4 million for the three and nine months ended September 30, 2008, 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 or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

7

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

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

The following table sets forth the net capitalized costs and associated accumulated depreciation, depletion and amortization, and impairments relating to the Company’s natural gas and oil producing activities, including net capitalized costs associated with properties held for sale of $1.1 million in unevaluated properties as of September 30, 2008 and $2.3 million ($0.3 million in total proved properties and $2.0 million in total unevaluated properties, net of $2.2 million of accumulated depreciation, depletion, amortization and impairment) as of December 31, 2007. See Note 5 for further information on properties held for sale.

	As of September 30, 2008			As of December 31, 2007
	(in thousands)
Proved properties	$	386,237		$	369,976
Wells and related equipment and facilities		1,238,395			974,005
Support equipment and facilities		150,980			123,020
Materials and supplies		12,436			6,132
Total proved oil and gas properties		1,788,048			1,473,133
Accumulated depreciation, depletion, amortization and impairment		(664,008	)		(521,691	)
Total proved oil and gas properties, net	$	1,124,040		$	951,442
Unevaluated properties	$	112,619		$	106,996
Wells and facilities in progress		217,162			126,529
Total unevaluated oil and gas properties, excluded from amortization	$	329,781		$	233,525

Net changes in capitalized exploratory well costs for the nine months ended September 30, 2008 are reflected in the following table (in thousands):

Beginning of period	$	82,214
Additions to capitalized exploratory well costs pending the determination of proved reserves		233,355
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(195,190	)
Exploratory well costs charged to dry hole costs and abandonment expense (1)		(5,018	)
End of period	$	115,361

(1) Excludes expired leasehold abandonment expense of $0.6 million.

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.

	September 30, 2008
	(in thousands)
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	80,247
Capitalized exploratory well costs that have been capitalized for a period greater than one year		35,114
End of period balance	$	115,361
Number of exploratory wells that have costs capitalized for a period greater than one year		162

As of September 30, 2008, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling are $35.1 million. Nearly all 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, the Company drills wells into various coal seams. In order to produce gas from the coal seams, a period of dewatering lasting up 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 its wells in the Powder River Basin, the Company has six wells that have been capitalized for greater than one year located in the Montana Overthrust area, and in the Paradox, Big Horn and Uinta Basins. The two wells located in the Montana Overthrust area and the two wells located in the Paradox Basin are under economic evaluation for possible development.

8

The Company is assessing and conducting appraisal operations to determine whether economic reserves can be attributed to the respective areas. The well located in the Big Horn Basin is pending upgrades of production, gathering and processing facilities. The well located in the Uinta Basin requires the Company to evaluate gas processing options.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that 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.

During the nine months ended September 30, 2008, the Company did not recognize any non-cash impairment charges. During the corresponding period of the prior year, the Company recognized a $2.3 million non-cash impairment charge with respect to its Tri-State properties within the DJ Basin, which the Company divested in early 2008.

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

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 revised SFAS No. 123,Accounting for Stock-Based Compensation,and superseded 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 the Company became a public company (i.e. those granted prior to April 16, 2004, which is defined by SFAS No. 123R as the date the Company became a public company as a result of the filing of the Company’s Form S-1 registration statement with the SEC), the Company continues to use the minimum value method described under APB Opinion No. 25. For awards granted subsequent to April 16, 2004 and for new, modified, repurchased or cancelled awards on or subsequent to the Company’s adoption of SFAS No. 123R on October 1, 2004, the Company recognized share-based employee compensation cost based on the fair value as computed under SFAS No. 123R. The Company continues to account for certain stock options under the original provisions of APB Opinion No. 25 because those options were issued prior to April 16, 2004, when the Company was considered a nonpublic entity as defined by 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 (the “2004 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 subsequent 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 Compensation 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 up 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 the achievement of the performance goals. Twenty-five percent of the total grant will vest for metrics met at the target level, and 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 vest 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 Incentive Plan were set aside for this program.

For the year ended December 31, 2007, the performance goals consisted 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 was 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 ended December 31, 2007, the Compensation Committee required that an initial threshold level for finding and development costs be met before any of the performance shares would vest. In future years of the program, the Compensation Committee may impose initial threshold levels based on this or other metrics. Based upon Company performance in 2007, 30% of the performance shares granted in 2007 vested in February 2008, and the Company recognized $0.5 million of compensation costs related to these awards through February 2008.

9

As new goals are established each year, a new grant date and a new fair value are created 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.

In February 2008, the Compensation Committee approved the performance metrics for vesting of the performance shares based on 2008 performance. For the year ending December 31, 2008, 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 lease operating expenses (weighted at 10%). Also for the year ending December 31, 2008, 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 February 2008, 159,460 performance-based nonvested equity shares of common stock, which represents the remaining unvested performance shares that were granted in 2007, along with 11,200 newly granted performance-based nonvested equity shares of common stock, were subject to the new grant date and the fair value was remeasured at a weighted-average price of $42.83 per share. An additional 2,200 performance-based nonvested shares were granted in April 2008 at a weighted average fair value of $52.86 per share and 2,450 were granted in September 2008 at a weighted average fair value of $32.80 per share. Of those performance-based nonvested equity shares, 125,221 could potentially vest if all performance goals are met at the stretch level. Based upon the number of shares expected to vest through February 2009, the Company recognized $0.9 million and $2.7 million of non-cash stock-based compensation cost associated with these shares for the three and nine months ended September 30, 2008, respectively.

On May 13, 2008, at the Company’s annual meeting of stockholders, the Company’s stockholders approved the 2008 Stock Incentive Plan (the “2008 Incentive Plan”), which had been previously approved by the Company’s Board of Directors. The 2008 Incentive Plan was effective May 13, 2008. The types of awards that may be granted under the 2008 Incentive Plan include incentive and non-qualified stock options, stock appreciation rights, restricted stock, performance shares and other stock-based awards. The total number of shares of the Company’s common stock available for issuance under the 2008 Incentive Plan is 3,000,000, subject to adjustment for future stock splits, stock dividends and similar changes in the Company’s capitalization. The maximum number of shares that may be the subject of awards other than options and stock appreciation rights is 1,000,000, while the maximum number of shares that may be issued pursuant to stock options and stock appreciation rights is 3,000,000. The aggregate number of shares subject to options and/or stock appreciation rights granted during any calendar year to any one participant may not exceed 500,000. The aggregate number of shares subject to restricted stock and/or restricted stock unit awards granted during any calendar year to any one participant may not exceed 500,000. No awards have been granted under the 2008 Incentive Plan.

During the nine months ended September 30, 2008, the Company granted 770,400 options to purchase shares of common stock with a weighted average exercise price of $43.36 per share, 217,130 nonvested equity shares of common stock and 15,850 performance-based nonvested equity shares of common stock under the Company’s 2004 Incentive Plan. During the three months ended September 30, 2008, the Company granted 50,500 options to purchase shares of common stock with a weighted average exercise price of $43.49 per share, 19,930 nonvested equity shares of common stock and 2,450 performance-based nonvested equity shares of common stock. The Company recorded non-cash stock-based compensation cost related to option, nonvested equity share and performance-based nonvested equity share awards of $12.1 million and $6.8 million for the nine months ended September 30, 2008 and 2007, respectively, including $3.2 million and $0.9 million associated with the performance-based nonvested equity shares, respectively. The Company recorded non-cash stock-based compensation cost of $4.0 million and $2.4 million for the three months ended September 30, 2008 and 2007, respectively, including $0.9 million and $0.3 million associated with the performance-based nonvested equity shares, respectively. As of September 30, 2008, there were $28.5 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 2.6 years. This amount includes $1.4 million related to the performance-based nonvested equity shares that is expected to be recognized ratably during the four month period from October 2008 through January 2009 based on current expectations for 2008 performance.

The Company’s directors may elect to receive their annual retainer and meeting fees in the form of the Company’s common stock issued pursuant to the Company’s 2004 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 end to receive shares of the Company’s common stock for payment of the director fees. For the three and nine months ended September 30, 2008, the Company issued 1,774 and 4,011 shares, respectively, of common stock under the 2004 Incentive Plan for payment of the director’s fees and recognized $0.1 million and $0.2 million, respectively, of non-cash stock-based compensation cost associated with the issuance of those shares.

New Accounting Pronouncements.In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157,Fair Value Measurements(“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure requirements regarding fair value measurement. The Company partially adopted SFAS No. 157 as of

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January 1, 2008, pursuant to FASB Staff Position (“FSP”) No. FAS 157-2,Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008.

In accordance with FSP No. FAS 157-2, the Company did not apply SFAS No. 157 to nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities, including nonfinancial long-lived assets measured at fair value for an impairment assessment under SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, and asset retirement obligations initially measured at fair value under SFAS No. 143,Accounting for Asset Retirement Obligations. The Company is still required to apply SFAS No. 157 to recurring fair value measurements of financial and non-financial instruments, which affects the fair value disclosures of our financial derivatives within the scope of SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. See Note 8 for fair value disclosures.

In February 2007, the FASB issued SFAS No. 159,Fair Value Option for Financial Assets and Financial Liabilities, which 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 Company adopted this statement as of January 1, 2008; however, the Company did not elect the fair value option for any eligible financial instruments or other items.

In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations (“SFAS No. 141R”), which replaces FASB Statement No. 141,Business Combinations. This statement requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions specified in the statement. This includes the measurement of the acquirer’s shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for pre-acquisition gain and loss contingencies, the recognition of capitalized in-process research and development, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs and the recognition of changes in the acquirer’s income tax valuation allowance and deferred taxes. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. SFAS No. 141R will only impact the Company if it is party to a business combination after SFAS No. 141R is effective.

In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities(“SFAS No. 161”). This statement is intended to improve financial reporting about derivative instruments and hedging activities by requiring companies to enhance disclosure about how these instruments and activities affect their financial position, performance and cash flows. SFAS No. 161 seeks to achieve these improvements by requiring disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It also seeks to improve the transparency of the location and amounts of derivative instruments in a company’s financial statements and how they are accounted for under SFAS No. 133. This statement will be effective for the Company beginning January 1, 2009. The adoption of SFAS No. 161 is not expected to have a material impact on the Company’s financial statements.

In May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles(“SFAS No. 162”). This statement is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. Prior to the issuance of SFAS No. 162, GAAP hierarchy was defined in the American Institute of Certified Public Accountants (“AICPA”) Statement on Auditing Standards (“SAS”) No. 69,The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. SFAS No. 162 is effective 60 days following the SEC’s approval of Public Company Accounting Oversight Board Auditing amendments to AU Section 411,The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. The adoption of SFAS No. 162 is not expected to have a material impact on the Company’s financial statements.

In May 2008, the FASB adopted FSP APB 14-1,Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (including Partial Cash Settlement). FSP APB 14-1 states that the accounting treatment for certain convertible debt instruments that may be settled in cash, shares of common stock or any portion thereof at the election of the issuing company be accounted for utilizing a bifurcation model under which the value of the debt instrument would be determined without regard to the conversion feature. The difference between the issuance amount of the debt instrument and the value determined pursuant to FSP APB 14-1 will be recorded as an equity contribution. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. FSP APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008. The Company will be required to adopt FSP APB 14-1 beginning with its 2009 fiscal year, and early adoption is not permitted. FSP APB 14-1 must be applied retrospectively to all periods presented for any instrument within the scope of FSP APB 14-1 that was outstanding during any of the periods presented. FSP APB 14-1 changes the accounting treatment for the Company’s Convertible Notes, and will increase the Company’s non-cash interest expense for its fiscal year 2008 and future reporting periods. In addition, it will reduce the Company’s long-term debt and increase the Company’s stockholders’ equity for the fiscal year 2008 reporting period. The Company is currently evaluating the full impact of FSP APB 14-1 on its consolidated financial statements.

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In October 2008, the FASB issued FSP No. FAS 157-3,Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active. FSP No. FAS 157-3 clarifies the application of SFAS No. 157 as it relates to the valuation of financial assets in a market that is not active for those financial assets. This FSP is effective immediately and includes those periods for which financial statements have not been issued. The Company currently does not have any financial assets that are valued using inactive markets, and as a result, the Company is not impacted by the issuance of FSP No. FAS 157-3.

3. 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. Potentially dilutive securities for the diluted earnings per share calculations consist of nonvested equity shares of common stock, in-the-money outstanding stock options to purchase the Company’s common stock and shares into which the Convertible Notes due 2028 are convertible.

In satisfaction of its obligation upon conversion of the Convertible Notes, the Company may elect to deliver, at its option, cash, shares of its common stock or a combination of cash and shares of its common stock. The Company currently intends to settle the Convertible Notes in cash at or near the initial redemption date of March 26, 2012; therefore, the treasury stock method was used to measure the potentially dilutive impact of shares associated with that conversion feature. The Convertible Notes issued March 12, 2008 have not been dilutive since their issuance on March 12, 2008, and therefore, do not impact the diluted earnings per share calculation for the three and nine months ended September 30, 2008.

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,
	2008		2007		2008		2007
Net income	$	36,065	$	233	$	100,755	$	24,275
Basic weighted-average common shares outstanding in period		44,493		44,085		44,399		44,009
Add dilutive effects of stock options and nonvested equity shares of common stock		563		477		785		490
Diluted weighted-average common shares outstanding in period		45,056		44,562		45,184		44,499
Basic income per common share	$	0.81	$	0.01	$	2.27	$	0.55
Diluted income per common share	$	0.80	$	0.01	$	2.23	$	0.55

4. Supplemental Disclosures of Cash Flow Information

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

	For Nine Months Ended September 30,
	2008			2007
Cash paid for interest, net of amount capitalized	$	10,506		$	8,217
Cash paid for income taxes, net of refunds received		1,069			64
Supplemental disclosures of non-cash investing and financing activities:
Reduction of deferred tax liability – Powder River Basin properties acquisition purchase price allocation		—			1,635
Current liabilities that are reflected in investing activities		99,468			19,009
Net change in asset retirement obligations		(2,604	)		(591	)
Treasury stock acquired from employee stock option exercises and collection of employee payroll taxes on vesting of restricted stock		3,051			3,292
Retirement of treasury stock		(3,051	)		(3,292	)

5. Dispositions and Property Held for Sale

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.

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During the quarter ended September 30, 2007, the Company began actively marketing its Hingeline Prospect in the Uinta Basin. In accordance with SFAS No. 144, these properties are carried at the lower of historical cost or fair value less costs to sell and were reclassified to oil and gas properties held for sale on the Unaudited Condensed Consolidated Balance Sheets. The entire $1.1 million net book value of the Hingeline Prospect is classified as unevaluated leasehold and is not subject to depletion.

Dispositions

In January 2008, the Company completed the sale of substantially all of its remaining properties in the DJ Basin. The Company received approximately $1.2 million in cash proceeds and recognized a $0.2 million pre-tax gain, which is included in other operating revenues in the Unaudited Condensed Consolidated Statements of Operations for the nine months ended September 30, 2008.

6. Long-Term Debt

Revolving Credit Facility

On October 20, 2008, the Company amended its credit facility (the “Amended Credit Facility”). The Amended Credit Facility has commitments of $592.8 million and based on mid-year 2008 reserves and hedge positions, a borrowing base of $600.0 million (after a reduction related to the Convertible Notes outstanding). Future borrowing bases will be computed based on proved natural gas and oil reserves and hedge positions. 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 1.25% to 2.00% or an alternate base rate, based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus 1.00% plus applicable margins ranging from 0.25% to 1.00%. The average annual interest rate incurred on the Amended Credit Facility was 3.6% and 6.7% for the three months ended September 30, 2008 and 2007, respectively, and 4.3% and 6.2% for the nine months ended September 30, 2008 and 2007, respectively, all of which were before the October 20, 2008 amendment. The Company pays annual commitment fees ranging from 0.35% to 0.50% 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.

At each of September 30, 2008 and October 20, 2008, borrowings outstanding under the Amended Credit Facility totaled $174.0 million. We are currently in compliance with all financial covenants and have complied with all financial covenants for all prior periods.

5% Convertible Senior Notes Due 2028

On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by the Company. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our future subordinated indebtedness; and effectively subordinated to all of our secured indebtedness, with respect to the collateral securing such indebtedness. The Convertible Notes will be structurally subordinated to all present and future secured and unsecured debt and other obligations of our subsidiaries that do not guarantee the Convertible Notes. As of September 30, 2008, the Convertible Notes are not guaranteed by any of our subsidiaries.

The conversion price is approximately $66.33 per share of our common stock, equal to the applicable conversion rate of 15.0761 shares of our common stock, subject to adjustment, for each $1,000 face amount of Convertible Note. Upon conversion of the Convertible Notes, holders will receive, at our election, cash, shares of common stock or a combination of cash and shares of common stock. If the conversion value exceeds $1,000, the Company will also deliver, at its election, cash, shares of common stock or a combination of cash and shares of common stock with respect to the remaining value deliverable upon conversion. Currently, it is the Company’s intention to net cash settle the Convertible Notes. However, the Company has not made a formal legal irrevocable election to net cash settle and reserves the right to settle the Convertible Notes in any manner allowed under the indenture for the Convertible Notes as business conditions warrant.

The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year, beginning September 15, 2008.

On or after March 26, 2012, the Company may redeem for cash all or a portion of the Convertible Notes at a redemption price equal to 100% of the principal amount of the Convertible Notes to be redeemed plus accrued and unpaid interest, if any, up to, but excluding, the applicable redemption date.

Holders of the Convertible Notes may require the Company to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2012, March 20, 2015, March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date.

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Holders may convert their Convertible Notes into cash, shares of our common stock or a combination of cash and shares of our common stock, as elected by us, at any time prior to the close of business on September 20, 2027 if any of the following conditions are satisfied: (1) if the closing price of the Company’s common stock reaches specified thresholds or the trading price of the Convertible Notes falls below specified thresholds; (2) if the Convertible Notes have been called for redemption; (3) if we make certain significant distributions to holders of our common stock; or (4) we enter into specified corporate transactions. After September 20, 2027, holders may surrender their Convertible Notes for conversion at any time prior to the close of business on the business day immediately preceding the maturity date regardless of whether any of the foregoing conditions have been satisfied.

In addition, following certain corporate transactions that constitute a qualifying fundamental change, we are required to increase the applicable conversion rate for a holder who elects to convert its Convertible Notes.

There is no established market for the Convertible Notes. Therefore, based on market-based parameters of the various components of the Convertible Notes, the estimated fair value was approximately $156.3 million as of September 30, 2008.

7. Asset Retirement Obligations

The Company accounts for its asset retirement obligations in accordance with SFAS No. 143. 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, 2008 is as follows (in thousands):

Beginning of period	$	35,849
Liabilities incurred		2,442
Liabilities settled		(1,312	)
Accretion expense		2,457
Revisions to estimate		243
End of period	$	39,679
Less: current asset retirement obligations		431
Long-term asset retirement obligations	$	39,248

8. Fair Value Measurements

The Company’s financial instruments, including cash and cash equivalents, accounts and notes receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Amended Credit Facility, as discussed in Note 6, approximates the fair value due to its floating rate structure. The Convertible Notes are recorded at cost, and the estimated fair value is disclosed in Note 6.

Effective January 1, 2008, the Company partially adopted SFAS No. 157 pursuant to FSP No. FAS 157-2, which delayed the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008. Therefore, the Company applied SFAS No. 157 to recurring fair value measurements of its financial derivatives as of January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure requirements regarding fair value measurement.

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) for valuation as a practical expedient for assigning fair value. The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market and income approaches for recurring fair value measurements and utilizes the best available information. Given the Company’s historical market transactions, its markets and instruments are fairly liquid. Therefore, the Company has been able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements).

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Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.

Level 3 –Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance sheet date, the Company performs an analysis of all instruments subject to SFAS 157 and includes in level 3 all of those whose fair value is based on significant unobservable inputs.

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and financial liabilities that were accounted for at fair value on a recurring basis as of September 30, 2008. As required by SFAS No. 157, financial assets and financial liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of assets and liabilities and their placement within the fair value hierarchy levels.

	Level 1		Level 2			Level 3		Total
	(in thousands)
Assets
Commodity Derivatives	$	—	$	190,369		$	—	$	190,369
Liabilities
Commodity Derivatives	$	—	$	(167	)	$	—	$	(167	)
Interest Rate Derivatives		—		(188	)		—		(188	)

As required under SFAS No. 157, all fair values reflected in the table above and on the Unaudited Condensed Consolidated Balance Sheets have been adjusted for non-performance risk. For applicable financial assets carried at fair value, the credit standing of the counterparties is analyzed and factored into the fair value measurement of those assets. SFAS No. 157 also states that the fair value measurement of a liability must reflect the nonperformance risk of the Company. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Level 1 Fair Value Measurements

As of September 30, 2008, and for the nine months ended September 30, 2008, the Company did not have assets or liabilities measured under a level 1 fair value hierarchy.

Level 2 Fair Value Measurements

Natural Gas and Crude Oil Forwards and Options — The fair value of the natural gas and crude oil forwards and options are estimated using a combined income and market valuation methodology based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes.

Interest Rate Forwards and Options — The fair value of the interest rate forwards and options are estimated using a combined income and market valuation methodology based upon forward interest-rate yield curves and credit. The curves are obtained from independent pricing services reflecting broker market quotes.

Level 3 Fair Value Measurements

As of September 30, 2008, and for the nine months ended September 30, 2008, the Company did not have assets or liabilities measured under a level 3 fair value hierarchy.

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9. Derivative Instruments

Oil and Gas Commodity Hedges

The Company periodically uses financial derivative instruments, as part of its price risk management program, to achieve a more predictable, economic cash flow from its natural gas and oil production by reducing its exposure to price fluctuations. The Company has entered into financial commodity swap and collar contracts to fix the floor and ceiling prices received for a portion of the Company’s natural gas and oil production. The Company’s natural gas and oil derivative financial instruments are accounted for in accordance with SFAS No. 133.As of September 30, 2008, the Company had hedges in place for a portion of its anticipated production through 2011 for a total of 557,525 Bbls of crude oil and 136,980,000 MMBtu of natural gas.

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 sale 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 production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sale exception as mentioned above, are recorded at fair market value in accordance with SFAS No. 157 and included in the Unaudited Condensed Consolidated Balance Sheets as assets or liabilities. For derivative instruments that qualify and are 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. The ineffective portion of hedge derivatives is reported in commodity derivative gain or loss in the Unaudited Condensed Consolidated Statements of Operations. 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.

If the forecasted transaction to which the hedging instrument had been designated is no longer probable of occurring within the specified time period, the hedging instrument loses cash flow hedge accounting treatment in accordance with SFAS No. 133. All current mark-to-market gains and losses are recorded in earnings and all accumulated gains or losses recorded in other comprehensive income related to the hedging instrument are also reclassified to earnings. Due to its limited ability to sell its natural gas out of the Rocky Mountain region to the Mid-continent region at index prices, and due to an unexpected pipeline curtailment on Rockies Express that restricted the Company’s ability to transport to the Mid-continent for much of September 2008, a portion of its Mid-continent gas derivatives no longer qualified for hedge accounting. The Company, therefore, discontinued hedge accounting for certain hedges during the three and nine months ended September 30, 2008. The Company recognized $4.5 million and $2.2 million in unrealized net gain within commodity derivative gain in the Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2008, respectively, attributable to hedges that no longer qualified for hedge accounting. While such derivative contracts no longer qualify for hedge accounting, the Company believes that these contracts remain a valuable component of its commodity price risk management program.

Some of our derivatives do not qualify for hedge accounting under SFAS No. 133 but are, to a degree, an economic offset to our commodity price exposure. If a derivative instrument does not qualify as a cash flow hedge or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in commodity derivative gain or loss in the Unaudited Condensed Consolidated Statements of Operations. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the underlying physical transaction takes place in the future and when the associated derivative instrument contract is settled by making or receiving a payment to or from the counterparty. Realized gains and losses of derivative instruments that do not qualify as cash flow hedges are recognized in commodity derivative gain or loss in the Unaudited Condensed Consolidated Statements of Operations and are reflected in cash flows from operations on the Unaudited Condensed Consolidated Statement of Cash Flows.

During the quarter ended September 30, 2008, in addition to the swaps and collars discussed above, the Company entered into basis swaps. With a basis swap, the Company has hedged the difference between the New York Mercantile Exchange (“NYMEX”) price and the price received for our natural gas production at a specific delivery location. Although the Company believes that this represents a sound economic business hedging strategy, the basis swaps do not qualify for hedge accounting under SFAS No. 133 because the total future cash flow has not been fixed. As a result, the changes in fair value of these derivative instruments are recorded in earnings and recognized in commodity derivative gain in the Unaudited Condensed Consolidated Statements of Operations. As of September 30, 2008, the Company had basis hedges in place for a portion of our anticipated natural gas production in 2010 for a total of 3,210,000 MMbtu. The Company recognized $0.7 million in unrealized net loss within commodity derivative gain in the Unaudited Condensed Consolidated Statements of Operations for both the three and nine months ended September 30, 2008 attributable to these basis swaps.

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At September 30, 2008, the estimated fair value of all of our commodity derivative instruments was a net asset of $190.2 million, comprised of current and noncurrent assets and liabilities, including a fair value liability of $0.7 million for basis swaps. The Company will reclassify the appropriate cash flow hedge amounts from other comprehensive income 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 as of September 30, 2008, the amount to be reclassified from other comprehensive income to net income in the next 12 months would be an after-tax net gain of approximately $69.1 million. 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 derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified time periods.

The hedge instruments designated as cash flow hedges are at highly liquid trading locations but may contain slight differences compared to the delivery location of the forecasted sale, which may result in ineffectiveness in accordance with SFAS No. 133. Ineffectiveness related to the Company’s derivative instruments was $5.7 million and $3.1 million for the three and nine months ended September 30, 2008, respectively, which was reported in commodity derivative gain on the Unaudited Condensed Consolidated Statements of Operations. Although those derivatives may not achieve 100% effectiveness for accounting purposes, the Company believes that its derivative instruments continue to be highly effective in achieving its risk management objectives. Ineffectiveness for the prior year periods was de minimis.

The Company was a party to various swap and collar contracts for natural gas based on the Colorado Interstate Gas Rocky Mountains (“CIGRM”) and Panhandle Eastern Pipe Line Co. (“PEPL”) indices that settled during the three and nine months ended September 30, 2008 and based on the CIGRM index that settled during the three and nine months ended September 30, 2007. As a result, the Company recognized an increase of natural gas production revenues related to these contracts of $8.6 million and $29.6 million in the three months ended September 30, 2008 and 2007, respectively, and a reduction of $12.9 million and an increase of $57.8 million of natural gas revenues in the nine months ended September 30, 2008 and 2007, respectively. The Company also was a party to various swap and collar contracts for oil based on a West Texas Intermediate (“WTI”) index, recognizing reductions of $4.1 million and $0.03 million to oil production revenues related to these contracts in the three months ended September 30, 2008 and 2007, respectively, and a reduction of $10.8 million and an increase of $0.3 million of oil production revenues in the nine months ended September 30, 2008 and 2007, respectively.

The table below summarizes the realized and unrealized gains and losses the Company recognized related to its oil and natural gas derivative instruments for the periods indicated:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2008			2007		2008			2007
Realized gains (losses) on derivatives designated as cash flow hedges (1)	$	5,457		$	29,581	$	(22,699	)	$	58,144
Realized losses on derivatives not designated as cash flow hedges (2)	$	(963	)	$	—	$	(963	)	$	—
Unrealized ineffectiveness recognized on derivatives designated as cash flow hedges (2)		5,687			—		3,121			—
Unrealized gains on derivatives not designated as cash flow hedges (2)		3,766			—		1,489			—
Total commodity derivative gain	$	8,490		$	—	$	3,647		$	—

(1) Included in “Oil and gas production” revenues in the Unaudited Condensed Consolidated Statements of Operations.

(2) Included in “Commodity derivative gain” in the Unaudited Condensed Consolidated Statements of Operations.

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. Ineffectiveness related to the Company’s interest rate derivative instruments was de minimis for both the three and nine months ended September 30, 2008 and 2007.

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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 LIBOR 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.

During the three and nine months ended September 30, 2008, net settlement payments, which were included in interest expense, were $0.1 million and $0.2 million, respectively. The Company anticipates that all originally forecasted transactions will occur by the end of the originally specified time periods. As of September 30, 2008, based on current projected interest rates, the amount to be reclassified from other comprehensive income to interest expense in the next 12 months would be a loss of approximately $0.1 million. At September 30, 2008, the estimated fair value of the interest rate derivatives was a liability of $0.2 million.

10. Income Taxes

The Company adopted the provisions of FASB Interpretation (“FIN”) No. 48,Accounting for Uncertainty in Income Taxes, on January 1, 2007. The adoption did not result in a material adjustment to the Company’s tax liability for unrecognized income tax benefits. As of September 30, 2008, there has been no change to the Company’s FIN No. 48 liability.

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. As of September 30, 2008, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the three and nine months ended September 30, 2008.

At September 30, 2008, the Company’s Unaudited Condensed Consolidated Balance Sheets reflected a net deferred tax liability of $230.0 million, of which $68.7 million pertains to a net deferred tax liability for derivative instruments reflected in other comprehensive income. The income tax provision for the nine months ended September 30, 2008 reflects an adjustment of $0.7 million as a result of applying a lower tax rate to deferred tax assets and liabilities expected to be realized or settled on or after January 1, 2009. This lower tax rate is due to changes in the Company’s Colorado state apportionment calculation as the result of a tax law change enacted during the second quarter of 2008.

Income tax expense for the three and nine months ended September 30, 2008 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 and other operating expenses not deductible for income tax purposes.

11. Stockholders’ Equity

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, 2008, 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. There are no issued and outstanding shares of preferred stock.

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.

The Series A Junior Participating Preferred Stock will be issued pursuant to the Company’s shareholder rights plan if a stockholder acquires shares of common stock 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 shares of Series A Junior Participating Preferred Stock will be proportionately changed in the event the Company declares or pays a common stock dividend or affects a stock split of common stock.

The Company may occasionally acquire treasury stock, which is recorded at cost, in connection with the vesting and exercise of stock-based awards or for other reasons. As of September 30, 2008, all treasury stock held by the Company was retired.

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12. Accumulated Other Comprehensive Income

The components of accumulated other comprehensive income and related tax effects for the nine months ended September 30, 2008 were as follows:

	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated other comprehensive income—December 31, 2007	$	7,602		$	(2,832	)	$	4,770
Unrealized change in fair value of cash flow hedges		199,262			(73,802	)		125,460
Reclassification adjustment for realized losses on hedges included in net income		(22,948	)		8,506			(14,442	)
Reclassification adjustment for discontinued cash flow hedges included in net income		1,489			(547	)		942
Accumulated other comprehensive income—September 30, 2008	$	185,405		$	(68,675	)	$	116,730

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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, debt and equity market 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, 2007 under the “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” sections and in Item 1A, “Risk Factors” of this Quarterly Report on Form 10-Q, 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 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, 2008 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, 2008 Compared to Nine Months Ended September 30, 2007

	Nine Months Ended September 30,				Increase (Decrease)
	2008		2007		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil and gas production	$	463,759	$	268,194	$	195,565		73%
Commodity derivative gain		3,647		—		3,647		nm*
Other		3,730		13,094		(9,364	)	(72)%
Operating Expenses
Lease operating expense		32,391		32,932		(541	)	(2)%
Gathering and transportation expense		29,746		15,265		14,481		95%
Production tax expense		37,405		14,916		22,489		151%
Exploration expense		2,935		6,762		(3,827	)	(57)%
Impairment, dry hole costs and abandonment expense		5,618		10,481		(4,863	)	(46)%
Depreciation, depletion and amortization expense		149,798		124,928		24,870		20%
General and administrative expense (1)		30,124		22,475		7,649		34%
Non-cash stock-based compensation expense (1)		12,096		6,942		5,154		74%
Total operating expenses	$	300,113	$	234,701	$	65,412		28%
Production Data:
Natural gas (MMcf)		54,173		41,181		12,992		32%
Oil (MBbls)		473		463		10		2%
Combined volumes (MMcfe)		57,011		43,959		13,052		30%
Daily combined volumes (MMcfe/d)		208		161		47		29%
Average Prices (2):
Natural gas (per Mcf)	$	7.87	$	5.86	$	2.01		34%
Oil (per Bbl)		76.57		58.08		18.49		32%
Combined (per Mcfe)		8.12		6.10		2.02		33%
Average Costs (per Mcfe):
Lease operating expense	$	0.57	$	0.75	$	(0.18	)	(24)%
Gathering and transportation expense		0.52		0.35		0.17		49%
Production tax expense		0.66		0.34		0.32		94%
Depreciation, depletion and amortization (3)		2.63		2.91		(0.28	)	(10)%
General and administrative expense (4)		0.53		0.51		0.02		4%

* Not meaningful.

(1) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense in the Unaudited Condensed Consolidated Statements of Operations for a total of $42.2 million and $29.4 million for the nine months ended September 30, 2008 and 2007, respectively. This separate presentation is a non-GAAP 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 for a more accurate comparison to our peers, which may have higher or lower costs associated with stock-based grants.

(2) Average prices shown in the table are net of the effects of all of our realized commodity hedging transactions. Our average realized price calculation includes all cash settlements for commodity derivatives, whether or not they qualify for hedge accounting under SFAS No. 133. As a result of our realized hedging transactions, natural gas production revenues were reduced by $12.9 million for the nine months ended September 30, 2008 and increased by $57.8 million for the nine months ended

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September 30, 2007. Oil production revenues were reduced by $10.8 million for the nine months ended September 30, 2008 and increased by $0.3 million for the nine months ended September 30, 2007. The average price we received for natural gas for the nine months ended September 30, 2008 was $8.11 per Mcf compared to $4.45 per Mcf for the nine months ended September 30, 2007 before the effect of hedging contracts. The average price we received for oil for the nine months ended September 30, 2008 was $99.47 per Bbl compared to $57.48 per Bbl for the nine months ended September 30, 2007 before the effect of hedging contracts.

(3) The calculated depreciation, depletion and amortization (“DD&A”) per Mcfe based on the DD&A expense and MMcfe production data presented in the table for the nine months ended September 30, 2007 was $2.84. The DD&A rate per Mcfe for the nine months ended September 30, 2007 of $2.91, as presented in the table above, excludes production of 1,195 MMcfe associated with our properties that were classified as held for sale in the Williston and DJ Basins, as these were not depleted throughout 2007.

(4) Excludes non-cash stock-based compensation expense as described in footnote (1) above. Average costs per Mcfe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Unaudited Condensed Consolidated Statements of Operations, were $0.74 and $0.67 for the nine months ended September 30, 2008 and 2007, respectively.

Production Revenues.Production revenues increased to $463.8 million for the nine months ended September 30, 2008 from $268.2 million for the nine months ended September 30, 2007, primarily due to a 30% increase in production and a 33% increase in natural gas and oil prices after the effect of realized hedges on a per Mcfe basis. The net increase in production added approximately $106.2 million of production revenues, and the increase in prices on a per Mcfe basis increased production revenues by approximately $89.4 million. Additional information concerning production is in the following table:

	Nine Months Ended September 30, 2008			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)
Piceance Basin	301	21,361	23,167	197	12,274	13,456	53	%	74	%	72%
Uinta Basin	127	19,992	20,754	33	18,851	19,049	285	%	6	%	9%
Powder River Basin	—	5,777	5,777	—	4,319	4,319	—		34	%	34%
Wind River Basin	23	7,023	7,161	30	5,625	5,805	(23)	%	25	%	23%
Williston Basin (1)	—	—	—	184	73	1,177	(100)	%	(100)	%	(100)%
Other	22	20	152	19	39	153	16	%	(49)	%	(1)%
Total	473	54,173	57,011	463	41,181	43,959	2	%	32	%	30%

(1) The sale of the Williston Basin properties was completed on June 22, 2007.

Total production volumes for the nine months ended September 30, 2008 of 57.0 Bcfe increased from 44.0 Bcfe for the nine months ended September 30, 2007 due to increased production in the Piceance, Uinta, Powder River and Wind River Basins. The increased production was partially offset by the sale of the Williston Basin properties in June 2007. The production increase in the Piceance Basin was the result of our continued development activities with initial sales on 111 new gross wells from October 1, 2007 to September 30, 2008. The production increase in the Uinta Basin reflects our continued exploration and development activities in the West Tavaputs, Black Tail Ridge and Lake Canyon fields. As a result, we had initial sales on 46 new gross wells from October 1, 2007 to September 30, 2008 in the Uinta Basin. The production increase in the Powder River Basin was the result of our continued development activities with initial sales on 90 new gross wells from October 1, 2007 to September 30, 2008. The production increase in the Wind River Basin was due to the recompletion of an existing well to a third zone in the Frontier formation in May 2008.

Hedging Activities.During the nine months ended September 30, 2008, approximately 72% of our natural gas volumes and 66% of our oil volumes were hedged, which resulted in a reduction in gas revenues of $12.9 million and a reduction in oil revenues of $10.8 million after cash settlements for all commodity derivatives. During the nine months ended September 30, 2007, we hedged approximately 64% of our natural gas volumes and 47% of our oil volumes, which resulted in an increase in gas revenues of $57.8 million and an increase in oil revenues of $0.3 million after cash settlements for all commodity derivatives.

Commodity Derivative Gain. During the nine months ended September 30, 2008, we determined that the forecasted transactions to which certain Mid-continent natural gas hedges had been designated were no longer probable of occurring within the specified time periods. We therefore discontinued hedge accounting for these hedges in accordance with SFAS No. 133. In addition, we entered into basis swaps for natural gas in the Rocky Mountain region, which do not qualify for cash flow hedge accounting during the period. The change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting is recognized in the line item titled “commodity derivative gain” in the Unaudited Condensed Consolidated Statements of Operations.

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The table below summarizes the realized and unrealized gains and losses we recognized in commodity derivative gain for the periods indicated:

	Nine Months Ended September 30,
	2008			2007
Realized losses on derivatives not designated as cash flow hedges	$	(963	)	$	—
Unrealized ineffectiveness recognized on derivatives designated as cash flow hedges		3,121			—
Unrealized gains on derivatives not designated as cash flow hedges		1,489			—
Total commodity derivative gain	$	3,647		$	—

Other Operating Revenues.Other operating revenues decreased to $3.7 million for the nine months ended September 30, 2008 from $13.1 million for the nine months ended September 30, 2007. Other operating revenues for the nine months ended September 30, 2008 primarily consisted of gains realized from the sale of properties of $1.1 million, gathering and rental fees of $1.6 million and the sale of seismic data of $1.0 million. Other operating revenues for the nine months ended September 30, 2007 primarily consisted of a gain realized on the sale of the Williston Basin properties of $10.5 million and gains realized on joint exploration agreements entered into in the Paradox Basin of $1.1 million, along with $1.5 million in gathering and rental fees.

Lease Operating Expense.The decrease in lease operating expense to $0.57 per Mcfe for the nine months ended September 30, 2008 from $0.75 per Mcfe for the nine months ended September 30, 2007 was primarily the result of decreased expenses on an Mcfe basis in the Piceance, Powder River and Wind River Basins offset by an increase in the Uinta Basin. The following table displays the lease operating expense by basin:

	Nine Months Ended September 30, 2008				Nine Months Ended September 30, 2007				% Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		($ per Mcfe)
Piceance Basin	$	7,482	$	0.32	$	8,628	$	0.64	(50)%
Uinta Basin		11,852		0.57		7,562		0.40	43%
Powder River Basin		7,799		1.35		7,446		1.72	(22)%
Wind River Basin		4,821		0.67		5,963		1.03	(35)%
Williston Basin (1)		—		—		2,736		2.32	(100)%
Other		437		2.88		597		3.91	(26)%
Total	$	32,391	$	0.57	$	32,932	$	0.75	(24)%

(1) The sale of the Williston Basin properties was completed on June 22, 2007.

Lease operating expense decreased in the Piceance Basin to $0.32 per Mcfe for the nine months ended September 30, 2008 from $0.64 per Mcfe for the nine months ended September 30, 2007 primarily due to the implementation of a new water disposal pipeline system, which substantially reduced water hauling expenses. The increase in the Uinta Basin to $0.57 per Mcfe for the nine months ended September 30, 2008 from $0.40 per Mcfe for the nine months ended September 30, 2007 was the result of overhauls on three compressors at our Dry Canyon Compressor Station and increased water disposal costs in the West Tavaputs. Higher costs related to high pour point oil production in our early development program in the Lake Canyon and Black Tail Ridge fields also contributed to the higher lease operating expense in the Uinta Basin. Lease operating expense decreased in the Powder River Basin to $1.35 per Mcfe for the nine months ended September 30, 2008 from $1.72 per Mcfe for the nine months ended September 30, 2007 primarily as a result of lower well servicing and lease maintenance costs, along with initial production on wells that were previously in the dewatering stage. Lease operating expense decreased in the Wind River Basin to $0.67 per Mcfe for the nine months ended September 30, 2008 from $1.03 per Mcfe for the nine months ended September 30, 2007 as a result of lower well servicing, workover costs and compressor maintenance, along with an increase in production.

Gathering and Transportation Expense.Gathering and transportation expense increased to $0.52 per Mcfe for the nine months ended September 30, 2008 from $0.35 per Mcfe for the nine months ended September 30, 2007 primarily due to additional transportation and processing contracts entered into throughout 2007 and 2008, along with increased fuel costs. The following table displays the gathering and transportation expense by basin:

	Nine Months Ended September 30, 2008				Nine Months Ended September 30, 2007				% Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		($ per Mcfe)
Piceance Basin	$	12,046	$	0.52	$	5,047	$	0.38	37%
Uinta Basin		10,670		0.51		4,657		0.24	113%
Powder River Basin		6,890		1.19		5,405		1.25	(5)%
Wind River Basin		125		0.02		131		0.02	0%
Other		15		0.10		25		0.02	400%
Total	$	29,746	$	0.52	$	15,265	$	0.35	49%

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We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to reduce the risk and impact related to possible production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production in the Piceance, Uinta and Powder River 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 Piceance and Uinta Basins to provide sales quality gas into existing pipelines. Included in the above gathering and transportation expense are $0.12 and $0.08 per Mcfe of transportation expense for the nine months ended September 30, 2008 and 2007, respectively, along with $0.05 and $0.06 per Mcfe of processing expense from long-term contracts for the nine months ended September 30, 2008 and 2007, respectively.

The increase in firm transportation expense to $0.12 per Mcfe for the nine months ended September 30, 2008 from $0.08 per Mcfe for the nine months ended September 30, 2007 was the result of additional long-term contracts with Rockies Express Pipeline and Questar Pipeline to deliver 25,000 gross MMBtu per day to each pipeline. Our transportation commitment with Rockies Express Pipeline, which was effective January 2008, provides us access to sell natural gas to Mid-continent markets. Our commitment with Questar Pipeline, which was effective November 2007, provides us the flexibility to access and sell natural gas to various Rocky Mountain markets.

Production Tax Expense.Total production taxes increased to $37.4 million for the nine months ended September 30, 2008 from $14.9 million for the nine months ended September 30, 2007. The increase in production tax expense was primarily related to the increase in natural gas and oil revenues before the effects of hedging. Production taxes as a percentage of natural gas and oil sales before the effects of hedging adjustments were 7.7% for the nine months ended September 30, 2008 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 expense decreased to $2.9 million for the nine months ended September 30, 2008 from $6.8 million for the nine months ended September 30, 2007. Exploration expense for the nine months ended September 30, 2008 consisted of $2.2 million for seismic programs, principally in the Big Horn, Uinta and Paradox Basins, and $0.7 million for delay rentals and other exploration costs across all basins. The expense for the nine months ended September 30, 2007 consisted of $5.6 million for seismic programs, principally in the Montana Overthrust, Paradox and Big Horn Basins and $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 to $5.6 million during the nine months ended September 30, 2008 from $10.5 million during the nine months ended September 30, 2007. For the nine months ended September 30, 2008, abandonment expense was $0.8 million, dry hole costs included $3.4 million for a well drilled in the Uinta Basin and $1.4 million related to additional costs on wells that were deemed to be uneconomic in prior years. The $3.4 million for dry hole costs were associated with the Peters Point 7-1-13-16 Ultra Deep well, which was completed June 2008, was tested and determined to be non-commercial in the Pennsylvanian Weber sandstone and Mississippi Leadville zones. Therefore, a proportionate share of the well cost was expensed.

We evaluate the impairment of our oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate a property’s carrying amount may not be recoverable. If the carrying amount exceeds the property’s estimated fair value, we will adjust the carrying amount of the properties to fair value through a charge to impairment expense. For the nine months ended September 30, 2008, we did not incur any impairment charges. For the nine months ended September 30, 2007, impairment expense was $2.3 million for properties we divested in early 2008, abandonment expense was $1.5 million and dry hole costs were $6.7 million.

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, 2008 pending determination of whether the wells will be assigned proved reserves. The following table does not include $4.7 million related to exploratory wells in progress for which drilling had not been completed at September 30, 2008:

	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	$	31,649	$	21,448	$	22,443	$	35,114	$	110,654

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The majority of the $35.1 million of exploratory well costs that have been capitalized for a period greater than one year are for wells 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, we have six wells that have been capitalized for greater than one year located in the Montana Overthrust area, and in the Paradox, Big Horn and Uinta Basins. The two wells located in the Montana Overthrust and the two wells located in the Paradox Basin area are under economic evaluation for possible development. The Company is are assessing and conducting appraisal operations to determine whether economic reserves can be attributed to the respective areas. The well located in the Big Horn Basin is pending upgrades of production gathering and processing facilities. The well located in the Uinta Basin requires us to evaluate gas processing options.

Depreciation, Depletion and Amortization.DD&A was $149.8 million for the nine months ended September 30, 2008 compared to $124.9 million for the nine months ended September 30, 2007. The increase of $24.9 million was a result of increased production for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007, partially offset by a decrease in the DD&A rate. The decrease in the DD&A rate is primarily attributable to additional reserves booked on our mid-year reserve report as the result of our ongoing development programs. The increase in production accounted for $41.5 million of additional DD&A expense, offset by $16.6 million related to an overall decrease in the DD&A rate.

During the nine months ended September 30, 2008, the weighted average DD&A rate was $2.63 per Mcfe. For the nine months ended September 30, 2007, the weighted average DD&A rate was $2.91 per Mcfe. The DD&A rate for the nine months ended September 30, 2007 excluded production of 1,195 MMcfe associated with our properties held for sale in the Williston and DJ Basins. Under successful efforts accounting, DD&A 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 DD&A rate for current production. Future DD&A 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 to $30.1 million in the nine months ended September 30, 2008 from $22.5 million in the nine months ended September 30, 2007. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, also increased to $0.53 per Mcfe for the nine months ended September 30, 2008 from $0.51 per Mcfe for the nine months ended September 30, 2007. This increase was primarily due to increased costs related to our employees’ compensation and benefit plans and additional personnel required for our capital program and production levels. As of September 30, 2008, we had 159 full time employees in our corporate office compared to 153 as of September 30, 2007. In addition, in the nine months ended September 30, 2008 due to a change in the terms of our proposed debt offering from a high-yield debt offering to the Convertible Notes, we expensed $0.4 million of costs related to the initially planned high-yield debt offering that would not have been incurred with the Convertible Notes. We also incurred expenses of $0.8 million in the nine months ended September 30, 2008 in connection with our efforts in the Colorado Oil and Gas Conservation Commission (“COGCC”) rulemaking process.

Non-cash charges for stock-based compensation were $12.1 million for the nine months ended September 30, 2008 compared to $6.9 million for the nine months ended September 30, 2007. Non-cash stock-based compensation expense is related to vesting of our stock option awards and nonvested shares of common stock issued to employees. The increase in charges for non-cash stock-based compensation was primarily due to the additional equity awards, including nonvested performance awards, which were granted during the fourth quarter of 2007 and during the nine months ended September 30, 2008.

Interest Expense.Interest expense increased to $11.4 million in the nine months ended September 30, 2008 from $8.7 million in the prior year period. The increase was due to higher average outstanding debt balances in order to fund exploration and development activities. Our weighted average outstanding debt balance, including our Amended Credit Facility and Convertible Notes issued in March 2008, was $309.9 million for the nine months ended September 30, 2008 compared to $185.8 million in the prior year period.

Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use. The weighted average interest rates used to capitalize interest for the nine months ended September 30, 2008 and 2007 were 5.3% and 7.1%, respectively, which included interest on both our Convertible Notes and our Amended Credit Facility, commitment fees paid on the unused portion of our Amended Credit Facility, amortization of deferred financing and debt issuance costs and the effects of interest rate hedges. We capitalized interest costs of $1.4 million and $1.3 million for the nine months ended September 30, 2008 and 2007, respectively.

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Income Tax Expense. Our effective tax rates were 37.5% and 38.7% for the nine months ended September 30, 2008 and 2007, respectively. Our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense under SFAS No. 123 (revised 2004),Share-Based Payment(“SFAS No. 123R”), and other operating expenses that are not deductible for income tax purposes. Due to the tax deductions 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. At September 30, 2008, we had approximately $96.6 million of federal tax net operating loss carryforwards (“NOLs”), which expire through 2023. We also have a federal AMT credit carryforward of $1.1 million, which has no expiration date. We believe it is more likely than not that we will use these NOLs to offset and reduce current tax liabilities in future years.

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

	Three Months Ended September 30,				Increase (Decrease)
	2008		2007		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil and gas production	$	155,050	$	82,216	$	72,833		89%
Commodity derivative gain		8,490		—		8,490		nm*
Other		875		39		836		nm*
Operating Expenses
Lease operating expense		12,548		9,846		2,702		27%
Gathering and transportation expense		10,103		4,873		5,230		107%
Production tax expense		13,519		4,220		9,299		220%
Exploration expense		1,010		4,004		(2,994	)	(75)%
Impairment, dry hole costs and abandonment expense		463		3,609		(3,146	)	(87)%
Depreciation, depletion and amortization expense		49,681		43,070		6,611		15%
General and administrative expense (1)		9,704		7,610		2,094		28%
Non-cash stock-based compensation expense (1)		3,950		2,461		1,489		61%
Total operating expenses	$	100,978	$	79,693	$	21,285		27%
Production Data:
Natural gas (MMcf)		18,568		14,226		4,342		31%
Oil (MBbls)		172		85		87		102%
Combined volumes (MMcfe)		19,600		14,736		4,864		33%
Daily combined volumes (MMcfe/d)		213		160		53		33%
Average Prices (2):
Natural gas (per Mcf)	$	7.57	$	5.36	$	2.21		41%
Oil (per Bbl)		79.07		70.26		8.81		13%
Combined (per Mcfe)		7.86		5.58		2.28		41%
Average Costs (per Mcfe):
Lease operating expense	$	0.64	$	0.67	$	(0.03	)	(4)%
Gathering and transportation expense		0.52		0.33		0.19		58%
Production tax expense		0.69		0.29		0.40		138%
Depreciation, depletion and amortization (3)		2.53		2.92		(0.39	)	(13)%
General and administrative expense (4)		0.50		0.52		(0.02	)	(4)%

* Not meaningful.

(1) Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense for a total of $13.7 million and $10.1 million for the three months ended September 30, 2008 and 2007, respectively, in the Unaudited Condensed Consolidated Statements of Operations. This separate presentation is a non-GAAP 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 for a more accurate comparison to our peers, which may have higher or lower costs associated with stock-based grants.

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(2) Average prices shown in the table are net of the effects of all of our realized commodity hedging transactions. Our average realized price calculation includes all cash settlements for commodity derivatives, whether or not they qualify for hedge accounting under SFAS No. 133. As a result of our realized hedging transactions, natural gas production revenues were increased by $8.6 million for the three months ended September 30, 2008 and increased by $29.6 million for the three months ended September 30, 2007. Oil production revenues were reduced by $4.1 million and $0.03 million for the three months ended September 30, 2008 and 2007, respectively. Before the effects of hedging, the average price we received for natural gas for the three months ended September 30, 2008 was $7.10 per Mcf compared to $3.28 per Mcf for the three months ended September 30, 2007. The average price we received for oil for the three months ended September 30, 2008 was $102.98 per Bbl compared to $70.57 per Bbl for the three months ended September 30, 2007.

(3) The DD&A rate per Mcfe for the three months ended September 30, 2007 of $2.92, as presented in the table above, excludes production of 3.7 MMcfe 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 Statements of Operations, were $0.70 and $0.68 for the three months ended September 30, 2008 and 2007, respectively.

Production Revenues.Production revenues increased to $155.0 million for the three months ended September 30, 2008 from $82.2 million for the three months ended September 30, 2007, primarily due to a 33% increase in production along with a 41% increase in natural gas and oil prices after the effect of realized hedges on a per Mcfe basis. The net increase in production added approximately $38.5 million of production revenues, and the increase in prices on a per Mcfe basis increased production revenues by approximately $34.3 million. Additional information concerning production is in the following table:

	Three Months Ended September 30, 2008			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)
Piceance Basin	100	7,287	7,887	58		4,220		4,568		72%	73%	73%
Uinta Basin	53	6,236	6,554	11		6,753		6,819		382%	(8)%	(4)%
Powder River Basin	—	2,292	2,292	—		1,498		1,498		—	53%	53%
Wind River Basin	9	2,750	2,804	11		1,741		1,807		(18)%	58%	55%
Williston Basin (1)	—	—	—	(2	)	(4	)	(16	)	(100)%	(100)%	(100)%
Other	10	3	63	7		18		60		43%	(83)%	5%
Total	172	18,568	19,600	85		14,226		14,736		102%	31%	33%

(1) The sale of the Williston Basin properties was completed on June 22, 2007.

Total production volumes for the three months ended September 30, 2008 of 19.6 Bcfe increased from 14.7 Bcfe for the three months ended September 30, 2007 due to increased production in the Piceance, Powder River and Wind River Basins. The increased production was partially offset by decreased production in the Uinta Basin. The production increase in the Piceance Basin was the result of our continued development activities with initial sales on 111 new gross wells from October 1, 2007 to September 30, 2008. The production increase in the Powder River Basin was the result of our continued development activities with initial sales on 90 new gross wells from October 1, 2007 to September 30, 2008. The production increase in the Wind River Basin was due to the recompletion of an existing well to a third zone in the Frontier formation in May 2008. The production decrease in the Uinta Basin is primarily the result of shutting-in production from existing wells in our West Tavaputs field while completion work was performed on recently drilled wells on the existing multi-well pad.

Hedging Activities.During the three months ended September 30, 2008, approximately 71% of our natural gas volumes and 64% of our oil volumes were hedged, which resulted in an increase in gas revenues of $8.6 million and a reduction in oil revenues of $4.1 million after cash settlements for all commodity derivatives. During the three months ended September 30, 2007, we hedged approximately 69% of our natural gas volumes and 87% of our oil volumes, which resulted in an increase in gas revenues of $29.6 million and a decrease in oil revenues of $0.03 million after cash settlements for all commodity derivatives.

Commodity Derivative Gain.During the three months ended September 30, 2008, we determined that additional forecasted transactions to which certain Mid-continent natural gas hedges had been designated were no longer probable of occurring within the specified time periods due to the unexpected maintenance on the Rockies Express pipeline. We therefore discontinued hedge accounting for these hedges. During the three months ended September 30, 2008, we also entered into basis swaps for natural gas in the Rocky Mountain Region, which do not qualify for cash flow hedge accounting during the period. The change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting is recognized in commodity derivative gain in the Unaudited Condensed Consolidated Statements of Operations.

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The table below summarizes the realized and unrealized gains and losses we recognized in commodity derivative gain for the periods indicated:

	Three Months Ended September 30,
	2008			2007
Realized losses on derivatives not designated as cash flow hedges	$	(963	)	$	—
Ineffectiveness recognized on derivatives designated as cash flow hedges		5,687			—
Unrealized gains on derivatives not designated as cash flow hedges		3,766			—
Total commodity derivative gain	$	8,490		$	—

Other Operating Revenues.Other operating revenues increased to $0.9 million for the three months ended September 30, 2008 from $0.04 million for the three months ended September 30, 2007. Other operating revenues for the three months ended September 30, 2008 consisted of gains realized from the sale of properties of $0.5 million and gathering and rental fees of $0.4 million. Other operating revenues for the three months ended September 30, 2007 consisted of gathering and rental fess of $0.55 million, offset by a reduction to the gain realized from the sale of the Williston Basin properties of $0.51 million.

Lease Operating Expense.The decrease in lease operating expense to $0.64 per Mcfe for the three months ended September 30, 2008 from $0.67 per Mcfe for the three months ended September 30, 2007 was primarily the result of decreased expenses in the Piceance, Powder River and Wind River Basins offset by an increase in the Uinta Basin. The following table displays the lease operating expense by basin:

	Three Months Ended September 30, 2008				Three Months Ended September 30, 2007					% Increase/     (Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)			($ per Mcfe)
Piceance Basin	$	2,689	$	0.34	$	2,932	$	0.64		(47)%
Uinta Basin		4,227		0.64		2,228		0.33		94%
Powder River Basin		3,850		1.68		2,636		1.76		(5)%
Wind River Basin		1,608		0.57		1,810		1.00		(43)%
Williston Basin (1)		—		—		63		(3.84	)	(100)%
Other		174		2.76		177		3.08		(5)%
Total	$	12,548	$	0.64	$	9,846	$	0.67		(4)%

(1) The sale of the Williston Basin properties was completed on June 22, 2007.

Lease operating expense decreased in the Piceance Basin to $0.34 per Mcfe for the three months ended September 30, 2008 from $0.64 per Mcfe for the three months ended September 30, 2007 primarily due to the implementation of a new water disposal pipeline system, which substantially reduced water hauling expenses. The increase in the Uinta Basin to $0.64 per Mcfe for the three months ended September 30, 2008 from $0.33 per Mcfe for the three months ended September 30, 2007 was the result of overhauls on two compressors at our Dry Canyon Compressor Station. Higher costs related to high pour point oil production in our early development program in the Lake Canyon and Black Tail Ridge fields also contributed to the higher lease operating expense in the Uinta Basin. Lease operating expense decreased in the Powder River Basin to $1.68 per Mcfe for the three months ended September 30, 2008 from $1.76 per Mcfe for the three months ended September 30, 2007 primarily as a result of lower lease maintenance costs, along with initial production on wells that were previously in the dewatering stage. Lease operating expense decreased in the Wind River Basin to $0.57 per Mcfe for the three months ended September 30, 2008 from $1.00 per Mcfe for the three months ended September 30, 2007 as a result of lower well servicing, along with an increase in production.

Gathering and Transportation Expense.Gathering and transportation expense increased to $0.52 per Mcfe for the three months ended September 30, 2008 from $0.33 per Mcfe for the three months ended September 30, 2007 primarily due to additional transportation and processing contracts entered into throughout 2007, along with increased fuel costs. The following table displays the gathering and transportation expense by basin:

	Three months Ended September 30, 2008				Three months Ended September 30, 2007				% Increase/     (Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		($ per Mcfe)
Piceance Basin	$	3,734	$	0.47	$	1,223	$	0.27	74%
Uinta Basin		3,521		0.54		1,784		0.26	108%
Powder River Basin		2,810		1.23		1,824		1.22	1%
Wind River Basin		37		0.01		30		0.02	(50)%
Other		1		0.02		12		0.27	(93)%
Total	$	10,103	$	0.52	$	4,873	$	0.33	58%

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We have entered into long-term firm transportation contracts on a portion of our production to guarantee capacity on major pipelines to reduce the risk and impact related to production curtailments that may arise due to limited pipeline capacity. The majority of our long-term firm transportation agreements are for gas production in the Piceance, Uinta and Powder River 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 Piceance and Uinta Basins to provide sales quality gas into existing pipelines. Included in the above gathering and transportation expense is $0.12 and $0.09 per Mcfe of transportation expense for the three months ended September 30, 2008 and 2007, respectively, along with $0.04 and $0.07 per Mcfe of processing expense from long-term contracts for the three months ended September 30, 2008 and 2007.

The increase in firm transportation expense to $0.12 per Mcfe for the three months ended September 30, 2008 from $0.09 per Mcfe for the three months ended September 30, 2007 was the result of additional long-term contracts with Rockies Express Pipeline and Questar Pipeline to deliver 25,000 gross MMBtu per day to each pipeline. Our transportation commitment with Rockies Express Pipeline, which was effective January 2008, provides us access to sell natural gas to Mid-continent markets. Our commitment with Questar Pipeline, which was effective November 2007, provides us the flexibility to access and sell natural gas to various Rocky Mountain markets.

Production Tax Expense.Total production taxes increased to $13.5 million for the three months ended September 30, 2008 from $4.2 million for the three months ended September 30, 2007. The increase in production tax expense was primarily related to the increase in natural gas and oil revenues before the effects of hedging. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 9.0% for the three months ended September 30, 2008 and 8.0% for the three 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 expense decreased to $1.0 million for the three months ended September 30, 2008 from $4.0 million for the three months ended September 30, 2007. Exploration expense for the three months ended September 30, 2008 consisted of $0.8 million for seismic programs, principally in the Uinta, Paradox and Big Horn Basins, and $0.2 million for delay rentals and other costs across all basins. The expense 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 to $0.5 million during the three months ended September 30, 2008 from $3.6 million during the three months ended September 30, 2007. For the three months ended September 30, 2008, abandonment expense was $0.5 million. For the three months ended September 30, 2007, abandonment expense was $0.5 million and dry hole costs were $3.1 million. For the three months ended September 30, 2008 and 2007, we did not incur any impairment charges.

Depreciation, Depletion and Amortization.DD&A was $49.7 million for the three months ended September 30, 2008 compared to $43.1 million for the three months ended September 30, 2007. The increase of $6.6 million was a result of increased production for the three months ended September 30, 2008 compared to the three months ended September 30, 2007, partially offset by a decrease in the DD&A rate. The increase in production accounted for $14.2 million of additional DD&A expense, offset by $7.6 million related to an overall decrease in the DD&A rate.

During the three months ended September 30, 2008, the weighted average DD&A rate was $2.53 per Mcfe. For the three months ended September 30, 2007, the weighted average DD&A rate was $2.92 per Mcfe. The DD&A rate for the three months ended September 30, 2007 excluded production of 3.7 MMcfe associated with our properties held for sale in the DJ Basins. Under successful efforts accounting, DD&A 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 DD&A rate for current production. Future DD&A 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 to $9.7 million in the three months ended September 30, 2008 from $7.6 million in the three months ended September 30, 2007. This increase was primarily due to increased costs related to our employees’ compensation and benefit plans and additional personnel required for our capital program and production levels. As of September 30, 2008, we had 159 full time employees in our corporate office compared to 153 as of September 30, 2007. On a per Mcfe basis, general and administrative expense, excluding non- cash stock-based compensation, decreased slightly to $0.50 per Mcfe for the three months ended September 30, 2008 from $0.52 per Mcfe for the three months ended September 30, 2007.

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Non-cash charges for stock-based compensation were $4.0 million for the three months ended September 30, 2008 compared to $2.5 million for the three months ended September 30, 2007. Non-cash stock-based compensation expense for each of the three months ended September 30, 2008 and 2007 was related to vesting of our stock option awards and nonvested shares of common stock issued to employees. The increase in charges for non-cash stock-based compensation was primarily due to the additional equity awards, including nonvested performance awards, that were granted during the fourth quarter in 2007 and during the nine months ended September 30, 2008.

Interest Expense.Interest expense increased to $3.8 million for the three months ended September 30, 2008 from $2.7 million in the prior year period. The increase for the three months ended September 30, 2008 was due to higher average outstanding debt balances in order to fund exploration and development activities. Our weighted average outstanding debt balance, including our Amended Credit Facility and Convertible Notes issued in March 2008, was $334.2 million for the three months ended September 30, 2008 compared to $170.7 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. The weighted average interest rates used to capitalize interest for the three months ended September 30, 2008 and 2007 were 5.1% and 7.2%, respectively, which included interest on both our Convertible Notes and our Amended Credit Facility, commitment fees paid on the unused portion of our Amended Credit Facility, amortization of deferred financing and debt issuance costs and the effects of interest rate hedges. We capitalized interest costs of $0.6 million and $0.4 million for the three months ended September 30, 2008 and 2007, respectively.

Income Tax Expense. Our effective tax rate was 40.3% and 53.3% in the three months ended September 30, 2008 and 2007, respectively. For both the 2008 and 2007 periods, our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense under SFAS No. 123R, that is not deductible for income tax purposes.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been sales and other issuances of equity securities, net cash provided by operating activities, bank credit facilities, convertible senior notes, 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 profitable reserve and production growth, we continually monitor the capital resources, including issuance of equity and debt securities, 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. Currently, the debt and equity markets are under considerable stress and dislocation making financing transactions difficult and expensive to complete if they can be completed at all. However, we have significant liquidity available to us under our Amended Credit Facility for our planned uses of capital. In addition, our strong hedge position provides relative certainty on a significant portion of our cash flows from operations even upon a decline in the price of natural gas and oil. 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, which under current market conditions we may not be able to obtain on terms acceptable to us or at all.

At September 30, 2008, our balance sheet reflected a cash and cash equivalents balance of $87.4 million with a balance of $174.0 million outstanding under our Amended Credit Facility. The borrowing base under our Amended Credit Facility was increased on October 20, 2008 to $600.0 million based on our mid-year 2008 reserves and hedge positions, after reduction related to the Convertible Notes outstanding, with commitments of $592.8 million.

Cash Flow from Operating Activities

Net cash provided by operating activities was $340.2 million and $198.2 million for the nine months ended September 30, 2008 and 2007, respectively. The increase in net cash provided by operating activities was primarily due to an increase in oil and gas revenues and increased non-cash expenses, as discussed above in “—Results of Operations.” Changes in current assets and liabilities resulted in an increase in cash flow from operations of $15.8 million and $26.6 million for the nine months ended September 30, 2008 and 2007, respectively.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of sales prices for natural gas and oil. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “—Quantitative and Qualitative Disclosure about Market Risk” below.

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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. We typically hedge a fixed price for natural gas at our sales points (New York Mercantile Exchange (“NYMEX”) less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. At September 30, 2008, we had in place natural gas and crude oil financial collars and swaps covering portions of our 2008, 2009, 2010 and 2011 production.

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 purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value in accordance with SFAS No. 157 and are included in the Unaudited Condensed Consolidated Balance Sheets as assets or liabilities. As required under SFAS No. 157, all fair values are adjusted for non-performance risk. For derivative instruments that qualify and are 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. The ineffective portion of hedge derivatives is reported in commodity derivative gain or loss in the Unaudited Condensed Consolidated Statements of Operations. Realized gains and losses on cash flow hedges are transferred from other 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.

If the forecasted transaction to which the hedging instrument had been designated is no longer probable of occurring within the specified time period, the hedging instrument loses cash flow hedge accounting treatment in accordance with SFAS No. 133. All current mark-to-market gains and losses are recorded in earnings and all accumulated gains or losses recorded in other comprehensive income related to the hedging instrument are also reclassified to earnings. Due to our limited ability to sell our natural gas out of the Rocky Mountain region to the Mid-continent region at index prices, and due to an unexpected pipeline curtailment on Rockies Express that restricted our ability to transport to the Mid-continent for much of September 2008, a portion of our Mid-continent gas derivatives no longer qualified for hedge accounting. We therefore discontinued hedge accounting for certain hedges during the three and nine months ended September 30, 2008. We recognized $4.5 million and $2.2 million in unrealized net gain within commodity derivative gain in the Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2008, respectively, attributable to hedges that no longer qualified for hedge accounting. While such derivative contracts no longer qualify for hedge accounting as of September 30, 2008, we believe that these contracts remain a valuable component of our commodity price risk management program.

Some of our derivatives do not qualify for hedge accounting under SFAS No. 133 but are, to a degree, an economic offset to our commodity price exposure. If a derivative instrument does not qualify as a cash flow hedge or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in commodity derivative gain or loss in the Unaudited Condensed Consolidated Statements of Operations. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the underlying physical transaction takes place in the future and when the associated derivative instrument contract is settled by making or receiving a payment to or from the counterparty. Realized gains and losses of derivative instruments that do not qualify as cash flow hedges are recognized in commodity derivative gain or loss in the Unaudited Condensed Consolidated Statements of Operations and are reflected in cash flows from operations on the Unaudited Condensed Consolidated Statement of Cash Flows.

During the quarter ended September 30, 2008, in addition to the swaps and collars discussed above, we entered into basis swaps. With a basis swap, we have hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location. Although we believe this is a sound economic hedging strategy, the basis swaps do not qualify for hedge accounting under SFAS No. 133 because the total future cash flow has not been fixed. As a result, the changes in fair value of these derivative instruments are recorded in earnings. As of September 30, 2008, we had basis hedges in place for a portion of our anticipated natural gas production in 2010 for a total of 3,210,000 MMbtu. The Company recognized $0.7 million in unrealized net loss within commodity derivative gain in the Unaudited Condensed Consolidated Statements of Operations for both the three and nine months ended September 30, 2008 attributable to these basis swaps.

At September 30, 2008, the estimated fair value of all of our commodity derivative instruments was a net asset of $190.2 million comprised of current and noncurrent assets and liabilities, including a fair value liability of $0.7 million for basis swaps. We will reclassify the appropriate cash flow hedge amounts to gains or losses included in natural gas and oil production operating revenues as the hedged production quantities are produced. Based on current projected market prices, the net amount of existing unrealized after-tax income as of September 30, 2008 to be reclassified from other comprehensive income to earnings in the next 12 months would be a gain of approximately $69.1 million. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. We anticipate that all originally forecasted transactions related to our derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified time periods.

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The hedge instruments designated as cash flow hedges are at highly liquid trading locations but may contain slight differences compared to the delivery location of the forecasted sale, which may result in ineffectiveness in accordance with SFAS No. 133. Ineffectiveness related to our cash flow derivative instruments for the three and nine months ended September 30, 2008 was $5.7 million and $3.1 million, respectively, which was reported in commodity derivative gain the Unaudited Condensed Consolidated Statements of Operations. Although those derivatives may not achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving our risk management objectives. Ineffectiveness for the prior year periods was de minimis.

The table below summarizes the realized and unrealized gains and losses we incurred related to our oil and natural gas derivative instruments for the periods indicated:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2008			2007		2008			2007
Realized gains (losses) on derivatives designated as cash flow hedges (1)	$	5,457		$	29,581	$	(22,699	)	$	58,144
Realized losses on derivatives not designated as cash flow hedges (2)	$	(963	)	$	—	$	(963	)	$	—
Unrealized ineffectiveness recognized on derivatives designated as cash flow hedges (2)		5,687			—		3,121			—
Unrealized gains on derivatives not designated as cash flow hedges (2)		3,766			—		1,489			—
Total commodity derivative gain	$	8,490		$	—	$	3,647		$	—

(1) Included in “Oil and gas production” revenues in the Unaudited Condensed Consolidated Statements of Operations.

(2) Included in “Commodity derivative gain” in the Unaudited Condensed Consolidated Statements of Operations.

We have in place the following swap contracts and cashless collars (purchased put options and written call options) as of September 30, 2008 in order to hedge a portion of our natural gas and oil production for the remainder of 2008 and 2009, 2010 and, for certain natural gas swap contracts, 2011. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production. During the three months ended September 30, 2008, in addition to the swaps and collars, we also entered into basis swaps. With a basis swap, we have hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location.

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Pricing		Weighted Average Ceiling Pricing		Weighted Average Fixed Price		Weighted Average Basis Differential	Index Price (1)	Fair Market Value,  Asset (Liability)
											(in thousands)
Cashless Collars:
2008
Natural gas	3,830,000	MMBtu	$	6.82	$	10.35		N/A	N/A	CIGRM	$	8,584
Natural gas	1,220,000	MMBtu	$	7.50	$	12.02		N/A	N/A	NWPL	$	4,335
Oil	57,500	Bbls	$	73.60	$	94.16		N/A	N/A	WTI	$	(942	)
2009
Natural gas	6,375,000	MMBtu	$	7.00	$	9.94		N/A	N/A	CIGRM	$	10,033
Natural gas	5,160,000	MMBtu	$	6.52	$	11.29		N/A	N/A	NWPL	$	6,831
Oil	200,750	Bbls	$	86.82	$	143.51		N/A	N/A	WTI	$	275
2010
Natural gas	6,080,000	MMBtu	$	6.00	$	10.41		N/A	N/A	NWPL	$	4,784
Natural gas	2,140,000	MMBtu	$	7.00	$	11.00		N/A	N/A	TCO	$	10
Oil	109,500	Bbls	$	90.00	$	163.00		N/A	N/A	WTI	$	486
Swap Contracts:
2008
Natural gas	8,745,000	MMBtu		N/A		N/A	$	7.11	N/A	CIGRM	$	22,780
Natural gas	1,934,000	MMBtu		N/A		N/A	$	7.04	N/A	PEPL	$	4,402
Oil	52,900	Bbls		N/A		N/A	$	73.84	N/A	WTI	$	(1,389	)

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Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Pricing	Weighted Average Ceiling Pricing	Weighted Average Fixed Price		Weighted Average Basis Differential			Index Price (1)	Fair Market Value,  Asset (Liability)
											(in thousands)
2009
Natural gas	47,120,000	MMBtu	N/A	N/A	$	7.18		N/A		CIGRM	$	77,260
Natural gas	5,425,000	MMBtu	N/A	N/A	$	7.91		N/A		PEPL	$	4,016
Oil	136,875	Bbls	N/A	N/A	$	74.41		N/A		WTI	$	(3,618	)
2010
Natural gas	32,495,000	MMBtu	N/A	N/A	$	6.95		N/A		CIGRM	$	35,693
Natural gas	2,736,000	MMBtu	N/A	N/A	$	7.63		N/A		PEPL	$	(143	)
Natural gas	2,140,000	MMBtu	N/A	N/A	$	6.50		N/A		NWPL	$	2,378
Natural gas	2,140,000	MMBtu	N/A	N/A	$	9.43		N/A		DA	$	1,556
2011
Natural gas	7,300,000	MMBtu	N/A	N/A	$	7.64		N/A		CIGRM	$	9,991
Natural gas	2,140,000	MMBtu	N/A	N/A	$	7.75		N/A		NWPL	$	3,550
Basis Swap Contracts (2):
2008
Natural gas	2,140,000	MMBtu	N/A	N/A		N/A	$	(3.20	)	NWPL	$	(470	)
Natural gas	1,070,000	MMBtu	N/A	N/A		N/A	$	(3.20	)	CIGRM	$	(199	)

(1) CIGRM refers to Colorado Interstate Gas Rocky Mountains, TCO refers to Columbia Gas Transmission Corporation for Appalachia, NWPL refers to Northwest Pipeline Corporation, DA refers to Dominion Transmission Inc. for Appalachia 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 NYMEX.

(2) Represents a swap of the basis between the NYMEX price and the spot price of the index listed under Index Price above.

Subsequent to September 30, 2008 through October 24, 2008, we did not enter into any new hedges.

By removing the price volatility from a portion of our natural gas and oil production for 2008, 2009, 2010 and, for certain natural gas swap contracts, 2011, 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.

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, we expose ourself to credit risk to our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, 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. The creditworthiness of our counterparties is subject to periodic review. We have hedges in place with seven different counterparties, all but one of which are lenders in our Amended Credit Facility. We believe all of these institutions currently are acceptable credit risks. We are not required to provide credit support or collateral to any of our counterparties under current contracts, nor are they required to provide credit support to us. As of October 24, 2008, we have no past due receivables from any of our counterparties.

Capital Expenditures

Our capital expenditures are summarized in the following tables:

	Nine Months Ended September 30,
Basin/Area	2008		2007
	(in millions)
Uinta	$	156.0	$	122.5
Piceance		188.3		124.3
Powder River		28.9		28.0
Wind River		24.0		6.6
Other		26.6		35.0
Total	$	423.8	$	316.4

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	Nine Months Ended September 30,
	2008		2007
	(in millions)
Acquisitions of proved and unevaluated properties and other real estate	$	22.3	$	21.0
Drilling, development, exploration and exploitation of natural gas and oil properties		390.9		277.1
Geologic and geophysical costs, exploratory dry hole costs and abandonment expense		8.6		14.9
Furniture, fixtures and equipment		2.0		3.4
Total	$	423.8	$	316.4

Total unevaluated properties increased $96.3 million to $329.8 million at September 30, 2008 from $233.5 million at December 31, 2007. The unevaluated property balances include $1.1 million related to unevaluated properties in the Hingeline Prospect that are currently classified as held for sale at September 30, 2008 and $2.0 million related to unevaluated properties in the DJ Basin and Hingeline Prospect that were classified as held for sale at December 31, 2007. The increase was principally from an increase in wells in progress resulting from increased development and exploratory drilling activity during the nine months ended September 30, 2008.

Excluding material oil and gas property acquisitions, our current capital budget for 2008 is $590-$610 million, of which we plan to spend approximately $460-$475 million in our development areas for drilling and facilities, and up to $135 million on delineation and exploration drilling, leasehold acquisitions, geologic and geophysical costs, equipment and other costs. While we may reallocate capital among our areas of activity, our approved budget provides that we plan to spend $255-$265 million in the Piceance Basin, $210-$220 million in the Uinta Basin, $35-$40 million in the Powder River Basin, $30-$35 million in the Wind River Basin, up to $30 million in the Paradox Basin and up to $30 million in other areas. For 2009, we currently plan to limit our capital expenditures to our operating cash flow. We also expect that our available liquidity through 2009, including through the Amended Credit Facility, will provide flexibility if the broader market environment becomes more favorable. Future cash flows are subject to a number of variables, including our 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 our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, 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 October 20, 2008, we amended our credit facility (the “Amended Credit Facility”). The Amended Credit Facility, which matures on March 17, 2011, has commitments of $592.8 million and based on mid-year 2008 reserves and our hedge positions, a borrowing base of $600.0 million (after a reduction related to the Convertible Notes outstanding). The borrowing base increased from $510.0 million. Future borrowing bases will be computed based on proved natural gas and oil reserves, hedge positions and estimated future cash flows from those reserves as well as any other outstanding debt. The Amended Credit Facility bears interest, based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 1.25% to 2.00% or an alternate base rate, based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus 1.00% plus applicable margins ranging from 0.25% to 1.00%. We pay commitment fees ranging from 0.35% to 0.50% 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 our proved reserves and the pledge of all of the stock of our subsidiaries. For information concerning the effect of changes in interest rates on interest payments under this facility, see “—Quantitative and Qualitative Disclosure about Market Risk — Interest Rate Risks” below.

As of September 30, 2008 and December 31, 2007, borrowings outstanding under the Amended Credit Facility totaled $174.0 and $274.0 million, respectively. The Amended Credit Facility contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants for all prior 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

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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. Ineffectiveness related to such derivative instruments was de minimis for both the three and nine months ended September 30, 2008 and 2007.

During the three and nine months ended September 30, 2008, net settlement payments on the interest rate derivative contracts, which were included in interest expense, were $0.1 million and $0.2 million, respectively. We anticipate that all originally forecasted transactions will occur by the end of the originally specified time periods. As of September 30, 2008, based on current projected interest rates, the amount to be reclassified from accumulated other comprehensive income to net income in the next 12 months would be a reduction of approximately $0.1 million. At September 30, 2008, the estimated fair value of the interest rate derivatives was a liability of $0.2 million.

Convertible Notes. On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. The full $172.5 million principal amount of the Convertible Notes currently is outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed, or purchased by us. The conversion price is approximately $66.33 per share of our common stock, equal to the applicable conversion rate of 15.0761 shares of our common stock, subject to adjustment. Upon conversion of the Convertible Notes, holders will receive, at our election, cash, shares of common stock, or a combination of cash and shares of common stock. The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year, beginning September 15, 2008. There is no established market for the Convertible Notes. Therefore, based on market-based parameters of the various components of the Convertible Note, the estimated fair value was approximately $156.3 million as of September 30, 2008.

On or after March 26, 2012, we may redeem for cash all or a portion of the Convertible Notes at a redemption price equal to 100% of the principal amount of the Convertible Notes to be redeemed plus accrued and unpaid interest, if any, up to, but excluding, the applicable redemption date. In satisfaction of our obligation upon conversion of the Convertible Notes, we may elect to deliver, at our option, cash, shares of our common stock or a combination of cash and shares of our common stock. We currently intend to net cash settle the Convertible Notes. However, we have not made a formal legal irrevocable election to net cash settle and reserve the right to settle the Convertible Notes in any manner allowed under the indenture for the Convertible Notes as business conditions warrant.

Holders of the Convertible Notes may require us to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2012, March 20, 2015, March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date.

Holders may convert their Convertible Notes into cash, shares of our common stock, or a combination of cash and shares of our common stock, as elected by us, at any time prior to the close of business on September 20, 2027 if any of the following conditions are satisfied: (1) if the closing price of our common stock reaches specified thresholds or the trading price of the Convertible Notes falls below specified thresholds; (2) if the Convertible Notes have been called for redemption; (3) if we make certain significant distributions to holders of our common stock, or (4) we enter into specified corporate transactions. After September 20, 2027, holders may surrender their Convertible Notes for conversion at any time prior to the close of business on the business day immediately preceding the maturity date regardless of whether any of the foregoing conditions have been satisfied.

In addition, following certain corporate transactions that constitute a qualifying fundamental change, we are required to increase the applicable conversion rate for a holder who elects to convert its Convertible Notes in connection with such corporate transactions in certain circumstances.

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Contractual Obligations.A summary of our contractual obligations as of and subsequent to September 30, 2008 is provided in the following table (in thousands).

	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	(in thousands)
Notes payable (1)	$	—	$	—	$	—	$	174,000	$	—	$	—	$	174,000
Convertible Notes (2)		8,625		8,625		8,625		176,683		—		—		202,558
Other commitments for developing oil and gas properties		25,163		18,393		5,204		369		—		—		49,129
Office and office equipment leases and other		2,403		2,416		1,080		159		—		—		6,058
Firm transportation and processing agreements		25,691		41,400		49,868		51,432		51,318		302,579		522,288
Asset retirement obligations (3)		431		6,196		1,640		1,283		912		29,217		39,679
Derivative liability (4)		184		171		—		—		—		—		355
Total	$	62,497	$	77,201	$	66,417	$	403,926	$	52,230	$	331,796	$	994,067

(1) Included in Notes payable is the outstanding principal amount under our Amended Credit Facility. This table does not include future commitment fees, interest expense or other fees on our Amended Credit Facility because the Amended Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

(2) On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. For purposes of contractual obligations, we assume that the holders of our Convertible Notes will not exercise the conversion feature, and we will, therefore, repay the $172.5 million in cash. We currently expect to call the Convertible Notes for redemption in 2012. We are also obligated to make annual interest payments equal to $8.6 million.

(3) 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, 2007 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(4) Derivative liabilities represent the fair value for oil and gas commodity derivatives and interest rate derivatives presented as liabilities in our Unaudited Condensed Consolidated Balance Sheets as of September 30, 2008. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market risk. 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, 2007 for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

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 one to 13 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 and software as of and subsequent to September 30, 2008 for a total of $8.8 million.

Regulatory

Our future cash flows and cost of operations also can be affected by changes in regulations and the ability to obtain drilling permits. Our properties located in Colorado are subject to the authority of the COGCC. The COGCC has the authority to regulate oil and gas activities to protect public health, safety and welfare, including the environment and wildlife. In 2007, the Colorado legislature approved legislation changing the composition of the COGCC to reduce industry representation and to add the heads of the Colorado Department of Natural Resources (“CDNR”) and the Colorado Department of Public Health and Environment (“CDPHE”) plus other stakeholders. In addition, the legislation required the COGCC to promulgate rules (1) in consultation with CDPHE, to provide CDPHE an opportunity to provide comments on public health issues during the COGCC’s decision-making process and (2) in consultation with the Colorado Division of Wildlife (“CDOW”), to establish standards for minimizing adverse impacts to wildlife resources affected by oil and gas operations and to ensure the proper reclamation of wildlife habitat during and following such operations. The COGCC has published draft proposals to implement these provisions and initiated formal rule-making in the first quarter of 2008. Final rules are expected to be approved during the fourth quarter of 2008 and to become effective in the first or second quarter of 2009. While this regulatory development has not adversely affected our operations to date, if these revised rules are implemented as drafted, they would cause additional costs, delay and uncertainty in our operations in Colorado. While the COGCC has not yet enacted final rules, the rules as currently drafted require consultation with the CDOW prior to drilling and completion operations in our Piceance Basin and for the portion of the Paradox Basin located in Colorado. If we are unable to negotiate wildlife

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mitigation plans with the CDOW, the CDOW may attempt to prohibit drilling and completion operations for some period corresponding to wildlife’s use of the habitat. The period of curtailment would be greater than the prohibition period because of the time necessary to move drilling equipment out of the area in order to finish completion operations before the restricted period begins. If we were not able to avoid these timing limitations, our Piceance Basin and, if our Paradox Basin exploratory activities are successful, the Colorado portion of our Paradox Basin production and production growth would be reduced. In addition, the costs of these and the other proposed rules could add substantial increases in incremental well costs in our Colorado operations. The proposed rules also would impact the ability and time necessary to obtain drilling permits, which creates substantial uncertainty about our ability to obtain sufficient permits in a timely fashion in order to meet future drilling plans and thus production and capital expenditure targets. It is also possible that similar rules will be proposed in the other states in which we operate, further impacting our operations.

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, 2007 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 primary 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 collars contracts in place for the nine months ended September 30, 2008, our annual income before income taxes, including all hedge settlements, would have decreased by approximately $1.2 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.1 million for each $1.00 per barrel change in crude oil prices.

We routinely 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 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. During the three months ended September 30, 2008, in addition to the swaps and collars discussed above, we also entered into basis swaps. With a basis swap, we have hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location.

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.

For the fourth quarter of 2008, we currently have financial hedges in place for 15,279,000 MMBtu of natural gas production and approximately 110,400 Bbls of oil production. As of October 24, 2008, we also have hedges in place for 64,080,000 MMBtu of natural gas production and 337,625 Bbls of oil production for 2009, 47,731,000 MMBtu of natural gas production and 109,500 Bbls of oil production for 2010 and 9,440,000 MMBtu of natural gas production for 2011. In addition, we have basis swaps in place for 3,210,000 MMBtu of natural gas for 2010. These hedges are summarized in the table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Cash Flow from Operating Activities— Commodity Hedging Activities.”

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Commodity Hedges

Through a price swap, we have fixed the price we will receive on a portion of our natural gas and oil production for the remainder of 2008 and 2009, 2010 and, for certain natural gas swap contracts, 2011. 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.

Through cashless collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas and oil production for the remainder of 2008 and 2009 and 2010. In a cashless 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. The table presented above under “Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Cash Flow from Operating Activities— Commodity Hedging Activities” provides the deliveries, fixed prices and floor and ceiling prices associated with these various arrangements as of September 30, 2008.

Interest Rate Risks

At September 30, 2008, we had debt outstanding under our Amended Credit Facility of $174.0 million, which bears interest at floating rates in accordance with our Amended Credit Facility. The average annual interest rate incurred on this debt for the nine months ended September 30, 2008 was 4.3%. 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, 2008 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, 2008. We also had $172.5 million principal amount of Convertible Notes outstanding at September 30, 2008, which have a fixed interest rate of 5.0%.

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 LIBOR rate of 4.70% through December 2009. We also entered into an interest rate collar for a notional amount of $10.0 million in which the interest rate has fixed minimum and maximum LIBOR rates of 4.50% and 4.95%, respectively, through December 2009.

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, 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 effective as of September 30, 2008.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the three months ended September 30, 2008 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 and a matter with the Environmental Protection Agency (“EPA”). In September 2006, the EPA alleged that we and an industry partner failed to comply with air quality and emissions standards for equipment used at our North Hill Creek compressor station in the Uinta Basin of Utah. In September 2008, we entered into a consent decree with the EPA pursuant to which we and our industry partner agreed to pay a fine of $240,000, of which $140,000 was agreed to be paid by us. The consent decree is subject to the approval of the United States Federal Court for the District of Utah.

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.

Other than as set forth below, as of the date of this filing, there have been no material changes from the risk factors previously disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2007, referred to as our 2007 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 2007 Annual Report and subsequent reports filed with the SEC. These risks and uncertainties are not the only ones facing us, and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our Company.

The continuing crisis in U.S. and world financial and securities markets could have a material adverse effect on our business and operations.

Any or all of the following may occur as a result of the continuing crisis in the U.S. and world financial and securities markets:

• We may be unable to obtain debt or equity financing, which would require us to limit our capital expenditures and other spending to our anticipated cash flow. This would lead to lower growth in our production and reserves than if we were able to spend more than our cash flow as we have in the past. Financing costs may increase as lenders may be reluctant to lend without receiving higher fees and spreads.

• The economic slowdown has led and could continue to lead to lower demand for oil and natural gas by individuals and industries, which in turn could result in lower prices for the oil and natural gas sold by us, declining production, lower revenues and possibly losses.

• With the current turbulent credit markets, including as a result of losses from the sub-prime mortgage crisis, the lenders under our credit facility may become more restrictive in their lending practices or unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserve growth, leading to losses and declining production.

• The current economic crisis and the losses incurred by financial institutions as well as the bankruptcy of some financial institutions heightens the risk that a counterparty to our hedge arrangements could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales. As a result, our financial condition could be materially adversely affected.

• Our Amended Credit Facility bears floating interest rates based on the London Interbank Offer Rate (LIBOR). As banks have been reluctant to lend to each other to avoid risk, LIBOR has increased to unprecedented spread levels. This causes higher interest expense for unhedged levels.

• The market crisis could lead to the inability of pipeline companies to obtain funding for new pipelines, leading to an increased inability to transport gas out of our operating areas in the Rocky Mountains to markets with higher demand and higher prices. As a result, we could be faced with lower prices in the Rocky Mountain region due to increasing supplies and lower demand in the region compared to more populated and more heavily industrialized areas. This would result in lower revenues for us and possibly losses.

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• Bankruptcies of financial institutions or illiquidity of money market funds may limit or delay our access to our cash equivalent deposits, causing us to lose some or all of those funds or to incur additional costs to borrow funds needed on a short-term basis that were previously funded from our money market deposits.

Recent Colorado legislative changes could limit our Colorado operations and adversely affect our cost of doing business.

Our future Colorado operations and cost of doing business may be affected by changes in regulations and the ability to obtain drilling permits. Our properties located in Colorado are subject to the authority of the COGCC. The COGCC has the authority to regulate oil and gas activities to protect public health, safety and welfare, including the environment and wildlife. In 2007, the Colorado legislature approved legislation changing the composition of the COGCC to reduce industry representation and to add the heads of the CDNR and the CDPHE plus other stakeholders. In addition, the legislation required the COGCC to promulgate rules (1) in consultation with CDPHE, to provide CDPHE an opportunity to provide comments on public health issues during the COGCC’s decision-making process and (2) in consultation with the CDOW, to establish standards for minimizing adverse impacts to wildlife resources affected by oil and gas operations and to ensure the proper reclamation of wildlife habitat during and following such operations. The COGCC has published draft proposals to implement these provisions and initiated formal rule-making in the first quarter of 2008. Final rules are expected to be approved during the fourth quarter of 2008 and to become effective in the first or second quarter of 2009. While this regulatory development has not adversely affected our operations to date, if these revised rules are implemented as drafted, they would cause additional costs, delay and uncertainty in our operations in Colorado. While the COGCC has not yet enacted final rules, the rules as currently drafted require consultation with the CDOW prior to drilling and completion operations in our Piceance Basin and for the portion of the Paradox Basin located in Colorado. If we are unable to negotiate wildlife mitigation plans with the CDOW, the CDOW may attempt to prohibit drilling and completion operations for some period corresponding to wildlife’s use of the habitat. The period of curtailment would be greater than the prohibition period because of the time necessary to move drilling equipment out of the area in order to finish completion operations before the restricted period begins. If we were not able to avoid these timing limitations, our Piceance Basin and, if our Paradox Basin exploratory activities are successful, the Colorado portion of our Paradox Basin production and production growth would be reduced. In addition, the costs of these and the other proposed rules could add substantial increases in incremental well costs in our Colorado operations. The proposed rules also would impact the ability and time necessary to obtain drilling permits, which creates substantial uncertainty about our ability to obtain sufficient permits in a timely fashion in order to meet future drilling plans and thus production and capital expenditure targets. It is also possible that similar rules will be proposed in the other states in which we operate, further impacting our operations.

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

Unregistered Sales of Securities

There were no sales of unregistered equity securities during the period covered by this report.

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Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended September 30, 2008:

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, 2008	3,307	$	48.79	—	—
August 1 – 31, 2008	—		—	—	—
September 1 – 30, 2008	78		32.28	—	—
Total	3,385	$	48.41	—	—

(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/or shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of shares of common stock issued pursuant to our 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
1.1	Underwriting Agreement, dated March 4, 2008, among Bill Barrett Corporation and Deutche Bank Securities Inc., Banc of America Securities LLC, and J.P. Morgan Securities Inc., as representatives of the several underwriters identified therein. [Incorporated by reference to Exhibit 1.1 of the Company’s Current Report on Form 8-K filed with the Commission on March 10, 2008.]
3.1	Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.4 of 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 by the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2004.]
4.1(a)	Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of Amendment No. 1 to the Company’s Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.1(b)	Indenture, dated March 12, 2008, between the Company and the Trustee. [Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the Commission on March 12, 2008.]
4.2(a)	Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 of Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
4.2(b)	First Supplemental Indenture, dated March 12, 2008, by and between the Company and Trustee (including form of 5% Convertible Senior Notes due 2028). [Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed with the Commission on March 12, 2008.]
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 Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
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. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to the Company’s Registration Statement on Form 8-A.]
4.6	Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to the Company’s Registration Statement on Form 8-A.]
10.1(a)	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 dated March 22, 2006.]
10.1(b)	First Amendment to Second Amended and Restated Credit Agreement dated as of 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 dated November 7, 2007.]
10.1(c)	Second Amendment to Second Amended and Restated Credit Agreement dated as of March 4, 2008, among Bill Barrett Corporation, as borrower, the Guarantors, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 10, 2008.]
10.1(d)	2008 Stock Incentive Plan dated as of May 13, 2008, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 16, 2008.]
10.1(e)	Third Amendment to Second Amended and Restated Credit Agreement dated as of October 20, 2008 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 dated October 21, 2008.]

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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 Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
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 Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
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 Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.4*	Amended and Restated 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
10.5(a)*	Form of Tranche A Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(a) to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.5(b)*	Form of Tranche B Stock Option Agreement for 2002 Stock Option Plan. [Incorporated by reference to Exhibit 10.13(b) to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.6*	2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.14 to Amendment No. 3 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on September 22, 2004.]
10.7*	Form of Stock Option Agreement for 2003 Stock Option Plan. [Incorporated by reference to Exhibit 10.15 to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
10.8	Form of Management Rights Agreement between Bill Barrett Corporation and certain investors. [Incorporated by reference to Exhibit 10.16 to Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
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 Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
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 Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
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 Amendment No. 4 to the Company’s Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on October 13, 2004.]
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 5, 2008	By:	/s/ Fredrick J. Barrett
		Fredrick J. Barrett
		Chairman of the Board of Directors and Chief Executive Officer
		(Principal Executive Officer)
Date: November 5, 2008	By:	/s/ Robert W. Howard
		Robert W. Howard
		Chief Financial Officer
		(Principal Financial Officer)

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