Bill Barrett (BBG) 10-Q 2009 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, 2009

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    ¨  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	¨  (Do not check if a smaller reporting company)	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 45,478,260 shares of $0.001 par value common stock outstanding on October 23, 2009.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements	3
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	43
	Item 4.	Controls and Procedures	44
PART II. OTHER INFORMATION
	Item 1.	Legal Proceedings	45
	Item 1A.	Risk Factors	45
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
	Item 3.	Defaults Upon Senior Securities	46
	Item 4.	Submission of Matters to a Vote of Security Holders	46
	Item 5.	Other Information	46
	Item 6.	Exhibits	47
SIGNATURES			50

2

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30, 2009			December 31, 2008
				(As Adjusted)
	(in thousands, except share and per share data)
Assets:
Current Assets:
Cash and cash equivalents	$	53,551		$	43,063
Accounts receivable, net of allowance for doubtful accounts of $790 at September 30, 2009 and $840 at December 31, 2008		46,582			66,427
Prepayments and other current assets		5,879			3,924
Derivative assets		78,970			199,960
Total current assets		184,982			313,374
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		2,299,822			1,977,535
Unevaluated oil and gas properties, excluded from amortization		282,468			315,239
Furniture, equipment and other		24,000			20,971
		2,606,290			2,313,745
Accumulated depreciation, depletion, amortization and impairment		(938,157	)		(751,926	)
Total property and equipment, net		1,668,133			1,561,819
Derivative Assets		15,381			113,815
Deferred Financing Costs and Other Noncurrent Assets		10,444			5,485
Total	$	1,878,940		$	1,994,493
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	66,383		$	100,552
Amounts payable to oil and gas property owners		11,632			17,067
Production taxes payable		40,509			36,236
Derivative liability and other current liabilities		9,021			511
Deferred income taxes		36,515			71,428
Total current liabilities		164,060			225,794
Note Payable to Bank		33,000			254,000
Senior Notes		238,179			—
Convertible Senior Notes		157,358			153,411
Asset Retirement Obligations		47,859			46,687
Deferred Income Taxes		196,243			214,481
Derivatives and Other Noncurrent Liabilities		19,677			887
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 45,468,473 and 45,128,431 shares issued and outstanding at September 30, 2009 and December 31, 2008, respectively, with 696,844 and 590,098 shares subject to restrictions, respectively		45			45
Additional paid-in capital		787,390			775,652
Retained earnings		169,203			131,464
Treasury stock, at cost: zero shares at September 30, 2009 and December 31, 2008		—			—
Accumulated other comprehensive income		65,926			192,072
Total stockholders’ equity		1,022,564			1,099,233
Total	$	1,878,940		$	1,994,493

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,
	2009			2008			2009			2008
				(As Adjusted)						(As Adjusted)
	(in thousands, except share and per share amounts)
Operating and Other Revenues:
Oil and gas production	$	161,719		$	155,050		$	479,455		$	463,759
Commodity derivative gain (loss)		(13,693	)		8,490			(48,612	)		3,647
Other		734			875			1,547			3,730
Total operating and other revenues		148,760			164,415			432,390			471,136
Operating Expenses:
Lease operating expense		13,005			12,548			34,921			32,391
Gathering and transportation expense		16,260			10,103			40,012			29,746
Production tax expense		6,547			13,519			11,850			37,405
Exploration expense		630			1,010			2,172			2,935
Impairment, dry hole costs and abandonment expense		19,103			463			29,834			5,618
Depreciation, depletion and amortization		66,742			49,681			189,459			149,798
General and administrative expense		14,634			13,654			41,274			42,220
Total operating expenses		136,921			100,978			349,522			300,113
Operating Income		11,839			63,437			82,868			171,023
Other Income and Expense:
Interest and other income		44			805			294			1,672
Interest expense		(9,746	)		(5,067	)		(20,098	)		(14,039	)
Total other income and expense		(9,702	)		(4,262	)		(19,804	)		(12,367	)
Income before Income Taxes		2,137			59,175			63,064			158,656
Provision for Income Taxes		1,419			23,860			25,325			59,518
Net Income	$	718		$	35,315		$	37,739		$	99,138
Net Income Per Common Share, Basic	$	0.02		$	0.79		$	0.84		$	2.23
Net Income Per Common Share, Diluted	$	0.02		$	0.78		$	0.84		$	2.19
Weighted Average Common Shares Outstanding, Basic		44,758,492			44,492,723			44,703,050			44,399,343
Weighted Average Common Shares Outstanding, Diluted		45,109,085			45,056,084			44,899,440			45,183,913

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		Treasury Stock			Accumulated Other Comprehensive Income			Total Stockholders’ Equity			Comprehensive Income
	(in thousands)
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		4,615			—		(3,051	)		—			1,565		$	—
Stock-based compensation		—		17,773			—		—			—			17,773			—
Retirement of treasury stock		—		(3,051	)		—		3,051			—			—			—
Conversion option of the Convertible Senior Notes (net of $8,578 of taxes) (See Note 6)		—		13,823			—		—			—			13,823			—
Comprehensive income:
Net income (as adjusted)		—		—			105,259		—			—			105,259			105,259
Effect of derivative financial instruments, net of $110,505 of taxes		—		—			—		—			187,302			187,302			187,302
Total comprehensive income																	$	292,561
Balance — December 31, 2008 (As Adjusted)	$	45	$	775,652		$	131,464	$	—		$	192,072		$	1,099,233
Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding		—		628			—		(2,047	)		—			(1,419	)	$	—
Stock-based compensation		—		13,157			—		—			—			13,157			—
Retirement of treasury stock		—		(2,047	)		—		2,047			—			—			—
Comprehensive income:																		—
Net income		—		—			37,739		—			—			37,739			37,739
Effect of derivative financial instruments, net of $74,353 of taxes		—		—			—		—			(126,146	)		(126,146	)		(126,146	)
Total comprehensive loss																	$	(88,407	)
Balance — September 30, 2009	$	45	$	787,390		$	169,203	$	—		$	65,926		$	1,022,564

See notes to unaudited condensed consolidated financial statements.

5

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended September 30,
	2009			2008
				(As Adjusted)
	(in thousands)
Operating Activities:
Net Income	$	37,739		$	99,138
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		189,459			149,798
Deferred income taxes		20,871			58,591
Impairment, dry hole costs and abandonment expense		29,834			5,618
Unrealized derivative loss (gain)		46,166			(4,610	)
Stock compensation and other non-cash charges		13,075			13,160
Amortization of debt discounts and deferred financing costs		5,953			3,818
Gain on sale of properties		(34	)		(1,134	)
Change in operating assets and liabilities:
Accounts receivable		19,845			(479	)
Prepayments and other assets		(1,842	)		(4,633	)
Accounts payable, accrued and other liabilities		12,913			3,372
Amounts payable to oil and gas property owners		(5,435	)		(1,424	)
Production taxes payable		4,273			18,973
Net cash provided by operating activities		372,817			340,188
Investing Activities:
Additions to oil and gas properties, including acquisitions		(372,820	)		(384,775	)
Additions of furniture, equipment and other		(3,287	)		(1,957	)
Proceeds from sale of properties		2,714			2,354
Net cash used in investing activities		(373,393	)		(384,378	)
Financing Activities:
Proceeds from credit facility		100,000			67,300
Principal payments on credit facility		(321,000	)		(167,300	)
Proceeds from issuance of senior convertible notes		—			172,500
Proceeds from issuance of senior notes		237,930			—
Proceeds from sale of common stock		628			4,071
Deferred financing costs and other		(6,494	)		(5,262	)
Net cash provided by financing activities		11,064			71,309
Increase in Cash and Cash Equivalents		10,488			27,119
Beginning Cash and Cash Equivalents		43,063			60,285
Ending Cash and Cash Equivalents	$	53,551		$	87,404

See notes to unaudited condensed consolidated financial statements.

6

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

September 30, 2009

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 the Company’s financial position as of September 30, 2009, the Company’s results of operations for the three and nine months ended September 30, 2009 and 2008 and cash flows for the nine months ended September 30, 2009 and 2008. Operating results for the three and nine months ended September 30, 2009 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 the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 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 the intended cash settlement of the Company’s Convertible Senior Notes in computing dilutive earnings per share, 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 theOil and Gas Extractive Activities Topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932 (formerly Statement of Financial Accounting Standards (“SFAS”) No. 19Financial 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 were 9.9% and 7.1% for the three and nine months ended September 30, 2009, respectively, and 5.1% and 5.3% for the three and nine months ended September 30, 2008, respectively, which include interest on the Company’s 5% Convertible Senior Notes due 2028 (“Convertible Notes”), its 9.875% Senior Notes due 2016 (“Senior Notes”) and its credit facility, amortization of the Convertible Notes and Senior Notes discounts, commitment fees paid on the unused portion of its credit facility, amortization of deferred financing and debt issuance costs and the effects of interest rate hedges. The Company capitalized interest costs of $1.5 million and $3.4 million for the three and nine months ended September 30, 2009, respectively, and $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

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

Unevaluated oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive. 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. Unevaluated oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage. During the nine months ended September 30, 2009 and 2008, the Company did not recognize any non-cash impairment charges.

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 non-cash impairments relating to the Company’s natural gas and oil producing activities:

	As of September 30, 2009			As of December 31, 2008
	(in thousands)
Proved properties	$	423,027		$	415,641
Wells and related equipment and facilities		1,677,556			1,381,861
Support equipment and facilities		188,457			170,058
Materials and supplies		10,782			9,975
Total proved oil and gas properties		2,299,822			1,977,535
Accumulated depreciation, depletion, amortization and impairment		(928,497	)		(744,139	)
Total proved oil and gas properties, net	$	1,371,325		$	1,233,396
Unevaluated properties	$	163,349		$	105,665
Wells and facilities in progress		119,119			209,574
Total unevaluated oil and gas properties, excluded from amortization	$	282,468		$	315,239

Net changes in capitalized exploratory well costs for the nine months ended September 30, 2009 are reflected in the following table (in thousands):

Beginning of period	$	120,091
Additions to capitalized exploratory well costs pending the determination of proved reserves		197,844
Reclassifications of wells, facilities and equipment based on the determination of proved reserves		(234,588	)
Exploratory well costs charged to dry hole costs and abandonment expense (1)		(28,267	)
End of period	$	55,080

(1) Excludes expired leasehold abandonment expense of $1.5 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 (in thousands, except well count amount):

	September 30, 2009
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	37,377
Capitalized exploratory well costs that have been capitalized for a period greater than one year		17,703
End of period balance	$	55,080
Number of exploratory wells that have costs capitalized for a period greater than one year		100

As of September 30, 2009, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling were $17.7 million, of which $12.8 million was related to exploratory wells 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.

8

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

In addition to its wells in the Powder River Basin, the Company has three exploratory wells for a total of $4.9 million that have been capitalized for greater than one year located in the Paradox Basin. Two of the wells were drilled as vertical test wells and may be re-entered to be converted as horizontal wells. The third well is currently being tested in the Gothic shale formation with plans to test up hole formations in the first half of 2010.

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, the present value of estimated future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. During the nine months ended September 30, 2009 and 2008, the Company did not recognize any non-cash impairment charges.

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.

Stock-Based Compensation.The Company accounts for stock-based compensation in accordance with ASC Topic 718, Stock Compensation (formerly “SFAS No. 123R,Share-Based Payment”).

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 of up to four years, depending on the level at which the performance goals are achieved. Each year for four years, it is possible for up to 50% of the 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% 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. If the target level metrics are not met, no shares will vest. 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.

Based upon Company performance in 2007, 30% of the performance shares vested in February 2008. Based upon the Company’s performance in 2008, 50% of the performance shares vested in February 2009. After the February 2009 vesting, 20% of the initial grant remained available for future performance vesting. On February 26, 2009, the Compensation Committee approved a supplemental grant to each participant remaining in the performance share program equal to 30% of the initial grant received by that participant (a total of 72,479 shares) in order to provide sufficient shares so that up to 50% of the performance shares initially granted to each participant are available for vesting if all stretch goals for 2009 are met. These supplemental grants expire on February 16, 2010 if they have not vested by that time.

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 an estimate of the extent to which 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 2009, the Compensation Committee approved the performance metrics for vesting of the performance shares based on 2009 performance. For the year ending December 31, 2009, the performance goals consist of finding and development costs per Mcfe (weighted at 40%), adjusted debt per Mcfe of proved reserves (weighted at 30%), lease operating expenses per Mcfe (weighted at 15%), and general and administrative expenses (weighted at 15%). In February 2009, a total of 124,339 performance-based nonvested equity shares of common stock (including the supplemental grant) were subject to the new grant date, and the fair value was remeasured at a weighted-average price of $19.58 per share. Based upon the number of shares expected to vest through February 2010, the Company recognized $0.7 million and $1.1 million of non-cash stock-based compensation cost associated with these shares for the three and nine months ended September 30, 2009, respectively.

9

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

During the nine months ended September 30, 2009, the Company granted 771,190 options to purchase shares of common stock with a weighted average exercise price of $23.41 per share, 346,960 nonvested equity shares of common stock and 73,679 performance-based nonvested equity shares of common stock (including the supplemental grant mentioned above). During the three months ended September 30, 2009, the Company granted 15,000 options to purchase shares of common stock at a weighted average exercise price of $30.38, 4,500 nonvested equity shares of common stock and zero performance-based nonvested equity shares of common stock. The Company recognized non-cash stock-based compensation cost of $12.3 million and $12.1 million for the nine months ended September 30, 2009 and 2008, respectively, including $1.5 million and $3.2 million associated with the performance-based nonvested equity shares, respectively. The Company recognized non-cash stock-based compensation cost of $4.4 million and $4.0 million for the three months ended September 30, 2009 and 2008, respectively, including $0.7 million and $0.9 million associated with the performance-based nonvested equity shares, respectively. As of September 30, 2009, there were $28.5 million of total compensation costs related to grants of nonvested stock options and nonvested equity shares of common stock that are expected to be recognized over a weighted-average period of 2.5 years. This amount includes $0.6 million related to the performance-based nonvested equity shares that is expected to be recognized ratably through February 2010 based on current estimates for 2009 performance.

The Company’s outside 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 to receive shares of the Company’s common stock for payment of the director’s fees. For the three and nine months ended September 30, 2009, the Company issued 1,606 and 7,253 shares, respectively, of common stock for payment of directors’ 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 June 2009, the FASB issued SFAS No. 168,The FASB Accounting Standards Codification (“ASC”) and the Hierarchy of Generally Accepted Accounting Principle,as codified in FASB ASC Topic 105,Generally Accepted Accounting Principles.This standard establishes only two levels of U.S. GAAP, authoritative and nonauthoritative. The FASB ASC became the source of authoritative, nongovernmental GAAP, except for rules and interpretive releases of the SEC, which are sources of authoritative GAAP for SEC registrants. All other non-grandfathered, non-SEC accounting literature not included in the Codification became nonauthoritative. This standard is effective for financial statements for interim or annual reporting periods ending after September 15, 2009 and was effective for the Company as of the date of this filing. Therefore, all accounting references have been updated, and SFAS references have been replaced with ASC references. As the ASC was not intended to change or alter existing GAAP, it did not have any impact on the Company’s financial statements.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements (“SFAS 157”), which was incorporated into ASC Topic 820,Fair Value Measurements and Disclosures. This standard defines fair value, establishes a framework for measuring fair value and expands disclosure requirements regarding fair value measurement. As of January 1, 2009, the Company fully adopted this standard, requiring fair value measurements of nonfinancial assets and nonfinancial liabilities. The full adoption did not have a material impact on the Company’s financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007),Business Combinations (“SFAS No. 141R”), which was incorporated into ASC Topic 805,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 and was effective for the Company beginning January 1, 2009 but will only impact the Company if and when the Company becomes party to a business combination.

In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities(“SFAS No. 161”), which was incorporated into ASC Topic 815,Derivatives and Hedging. 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. It 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. This statement was effective for the Company beginning January 1, 2009. See Note 9 for the applicable disclosures.

In May 2008, the FASB issued FASB Staff Position (“FSP”) Accounting Principles Board (“APB”) 14-1,Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (including Partial Cash Settlement),which was incorporated into ASC Subtopic 470-20, Debt with Conversion and Other Options. This standard states that the accounting treatment

10

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

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 is 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 is recorded as an equity contribution. The resulting debt discount is amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. This standard was effective for financial statements issued for fiscal years beginning after December 15, 2008. The Company adopted this standard effective January 1, 2009 as early adoption was not permitted. FSP APB 14-1 changed the accounting treatment for the Company’s Convertible Notes that were issued in March 2008. See Note 6 for additional disclosures associated with the adoption of this standard.

FSP APB 14-1 was required to be applied retrospectively for any instrument within the scope that was outstanding during any of the periods presented. As a result of the retrospective application, certain amounts in the Company’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2008 and as of December 31, 2008 have been adjusted. A summary of the changes are presented below (amounts in thousands):

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
	As of December 31, 2008
	As previously Reported		After adoption of FSP APB 14-1
Deferred Financing Costs and Other Noncurrent Assets	$	6,055	$	5,485
Convertible Senior Notes		172,500		153,411
Deferred Income Taxes		207,397		214,481
Additional paid-in capital		761,829		775,652
Retained earnings		133,852		131,464

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
	Three Months Ended September 30, 2008						Nine Months Ended September 30, 2008
	As previously Reported			After adoption of FSP APB 14-1			As previously Reported			After adoption of FSP APB 14-1
Interest expense	$	(3,846	)	$	(5,067	)	$	(11,407	)	$	(14,039	)
Provision for Income Taxes		24,331			23,860			60,533			59,518
Net Income		36,065			35,315			100,755			99,138

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
	For the Nine Months Ended September 30, 2008
	As previously Reported		After adoption of FSP APB 14-1
Net Income	$	100,755	$	99,138
Deferred income taxes		59,606		58,591
Amortization of deferred financing costs		1,186		3,818

On December 31, 2008, the SEC adopted the final rules and interpretations updating its oil and gas reserve reporting requirements. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the Petroleum Resource Management System, which is a widely accepted set of evaluation guidelines that are designed to support assessment processes throughout the resource asset lifecycle. These guidelines were prepared by the Society of Petroleum Engineers (“SPE”) Oil and Gas Reserves Committee with cooperation from many industry organizations. One of the key changes to the previous SEC rules relates to using a 12-month average commodity price to calculate the value of proved reserves versus the current method of using year-end prices. Other key revisions include the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, the opportunity to establish proved undeveloped reserves without the requirement of an adjacent producing well and permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports for fiscal years ending on or after December 15, 2009. Early adoption is not permitted. The Company is currently assessing the impact that the adoption will have on the Company’s disclosures and financial statements.

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BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

In September 2009, the FASB issued its proposed updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure requirements of ASC Topic 932,Extractive Activities-Oil and Gas, with the requirements in the SEC’s final rule as discussed above. The public comment period for the FASB’s proposed updates ended October 15, 2009; however, no final guidance has been issued by the FASB. The Company is evaluating the potential impact of any updates to the oil and gas accounting rules and will comply with any new accounting and disclosure requirements once they become effective.

In April 2009, the FASB issued staff positions intended to provide additional application guidance and enhance disclosures regarding fair value measurements. FSP SFAS No. 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, intends to provide guidelines for making fair value measurements more consistent with the principles presented in SFAS No. 157. FSP SFAS No. 107-1 and APB 28-1,Interim Disclosures about Fair Value of Financial Instruments, attempt to enhance consistency in financial reporting by increasing the frequency of fair value disclosures. These statements, which were incorporated into ASC Topic 820,Fair Value Measurements and Disclosures, are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The adoption of these statements did not have a material impact on the Company’s financial statements.

In May 2009, the FASB issued SFAS No. 165,Subsequent Events, which was incorporated into ASC Topic 855,Subsequent Events. The intent of this statement is to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Particular importance has been placed on the period after the balance sheet date during which management should evaluate events or transactions that may occur leading to recognition within the financial statements or disclosure in the financial statements. This standard is effective for interim and annual periods ending after June 15, 2009 and was effective for the Company beginning June 30, 2009. The Company evaluated subsequent events occurring through November 3, 2009, the date the financial statements were issued. The adoption of this statement did not have a material impact on the Company’s financial statements.

3. Earnings Per Share

Basic net income per share of common stock 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 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 have not been dilutive since their issuance in March 2008, and therefore, do not impact the diluted earnings per share calculation for the three and nine months ended September 30, 2009 and 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,
	2009		2008		2009		2008
			(As Adjusted)				(As Adjusted)
Net income	$	718	$	35,315	$	37,739	$	99,138
Adjustments to net income for dilution		—		—		—		—
Net income adjusted for the effect of dilution	$	718	$	35,315	$	37,739	$	99,138
Basic weighted-average common shares outstanding in period		44,758		44,493		44,703		44,399
Add dilutive effects of stock options and nonvested equity shares of common stock		351		563		196		785
Diluted weighted-average common shares outstanding in period		45,109		45,056		44,899		45,184
Basic income per common share	$	0.02	$	0.79	$	0.84	$	2.23
Diluted income per common share	$	0.02	$	0.78	$	0.84	$	2.19

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BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

4. Supplemental Disclosures of Cash Flow Information

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

	Nine Months Ended September 30,
	2009			2008
Cash paid for interest, net of amount capitalized	$	15,310		$	10,506
Cash paid for income taxes, net of refunds received		4,454			1,069
Supplemental disclosures of non-cash investing and financing activities:
Current liabilities that are reflected in investing activities		35,359			99,468
Current liabilities that are reflected in financing activities		206			—
Net change in asset retirement obligations		493			(2,604	)
Treasury stock acquired from employee stock option exercises and collection of employee payroll taxes on vesting of restricted stock		2,047			3,051
Retirement of treasury stock		(2,047	)		(3,051	)

5. Acquisitions

In June 2009, the Company purchased a 90% working interest in approximately 40,300 net unproved undeveloped leasehold acres in the Cottonwood Gulch area of the Piceance Basin of Colorado for $60.0 million.

6. Long-Term Debt

Revolving Credit Facility

On April 15, 2009, the Company amended its credit facility (the “Amended Credit Facility”). 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 1.75% to 2.50% (an increase from 1.25% to 2.00% previously) 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 0.75% to 1.50% (an increase from 0.25% to 1.00% previously). The average annual interest rates incurred on the Amended Credit Facility were 2.3% and 3.6% for the three months ended September 30, 2009 and 2008, respectively, and 2.3% and 4.3% for the nine months ended September 30, 2009 and 2008, respectively. Based on our mid-year 2009 proved reserves and hedge positions, the borrowing base was increased to $630.0 million with commitments of $592.8 million effective October 9, 2009. 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 of the Company. The borrowing base is required to be redetermined twice per year. The Company pays annual commitment fees ranging from 0.35% to 0.50% of the unused amount of the commitments. 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 the Company’s subsidiaries. The Amended Credit Facility also contains certain financial covenants. The Company is currently in compliance with all financial covenants and has complied with all financial covenants for all prior periods. The Amended Credit Facility matures on March 17, 2011.

As of September 30, 2009 our borrowings outstanding under the Amended Credit Facility totaled $33.0 million.

5% Convertible Senior Notes Due 2028

On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. The full $172.5 million principal amount of the Convertible Notes is currently outstanding. 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 the Company’s existing and future senior indebtedness, are senior in right of payment to all of the Company’s future subordinated indebtedness, and are effectively subordinated to all of the Company’s 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 the Company’s subsidiaries. Upon completion of the Company’s Senior Notes offering on July 8, 2009, all current subsidiaries became guarantors of the Convertible Notes.

The conversion price is approximately $66.33 per share of the Company’s common stock, equal to the applicable conversion rate of 15.0761 shares of common stock, subject to adjustment, for each $1,000 of the principal amount of the Convertible Notes. Upon conversion of the Convertible Notes, holders will receive, at the Company’s 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.

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BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

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.

Holders may convert their Convertible Notes into cash, shares of the Company’s common stock or a combination of cash and shares of common stock, as elected by the Company, 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 the Company makes certain significant distributions to holders of the Company’s common stock; or (4) the Company enters into specified corporate transactions, none of which occurred during the nine months ended September 30, 2009. 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, the Company is required to increase the applicable conversion rate for a holder that elects to convert its Convertible Notes.

As a result of the adoption of what was formerly known as FSP APB 14-1, and its retrospective application (previously discussed in Note 2), the Company recorded a debt discount of $23.1 million, which represented the fair value of the equity conversion feature as of the date of the issuance of the Convertible Notes. The value of the equity conversion feature was also recorded as additional paid-in capital, net of $8.6 million of deferred taxes. In addition, the transaction costs incurred directly related to the issuance of the Convertible Notes were allocated proportionately to the equity conversion feature and recorded as additional paid-in capital. The equity component is not subsequently re-valued as long as it continues to qualify for equity treatment.

The debt discount is amortized as additional non-cash interest expense over the expected term of the Convertible Notes through March 2012. As of September 30, 2009, the net carrying amount of the Convertible Notes is as follows (amounts in thousands):

Principal amount of the Convertible Notes	$	172,500
Unamortized debt discount		(15,142	)
Carrying amount of the Convertible Notes	$	157,358

As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the Company’s Convertible Notes is 9.7% per annum. The amount of the cash interest expense recognized with respect to the 5% contractual interest coupon for the three and nine months ended September 30, 2009 was $2.2 and $6.5 million, respectively, and $2.2 million and $4.3 million for the three and nine months ended September 30, 2008, respectively. The amount of non-cash interest expense related to the amortization of the debt discount and amortization of the transaction costs for the three and nine month periods ended September 30, 2009 was $1.7 million and $4.8 million, respectively, and $1.5 million and $3.4 million for the three and nine month periods ended September 30, 2008, respectively.

There is no active, public market for the Convertible Notes. Therefore, based on market-based parameters of the various components of the Convertible Notes, the aggregate estimated fair value of the Convertible Notes was approximately $163.0 million as of September 30, 2009.

9.875% Senior Notes Due 2016

On July 8, 2009, the Company issued $250.0 million in principal amount of 9.875% Senior Notes due 2016 at 95.172% of par resulting in a discount recorded of $12.1 million. The 9.875% Senior Notes will mature on July 15, 2016. Interest is payable in arrears semi-annually on January 15 and July 15 beginning January 15, 2010. The Company received net proceeds of $232.3 million (net of related offering costs), which were used to repay a portion of the borrowings under the Amended Credit Facility. The Senior Notes are senior unsecured obligations of the Company and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness, including the Company’s Convertible Notes. The Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under our Amended Credit Facility. As a result of the guarantee by the guarantor subsidiaries of the Senior Notes, the terms of the Convertible Notes require the guarantor subsidiaries to also guarantee the Convertible Notes.

14

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

The Senior Notes are redeemable, at the option of the Company, at 104.938% of the principal amount after July 15, 2013, declining to 100.00% in 2015. Prior to July 15, 2013, the Company may at its option redeem the Senior Notes at a make-whole price comprised of the greater of 100% of the principal amount or the present value of 104.938% of the principal amount plus a make-whole amount. The make-whole amount is the present value of the remaining interest payments due on the Senior Notes as if such notes were redeemed on July 15, 2013 computed using a discount rate equal to the Treasury Rate plus 50 basis points, over the principal amount of the notes. The Company may redeem up to 35% of the aggregate principal amount of the Senior Notes at a price of 109.875% of the principal amount plus accrued interest upon the issuance of equity securities until July 15, 2012. If a specified change of control occurs, the Company must make an offer to purchase the notes at 101% of the principal amount plus any accrued interest. Additionally, certain asset dispositions that are not reinvested in 360 days may require the Company to offer to purchase the notes at 100% of principal plus accrued interest. The Senior Notes include certain covenants that limit the Company’s ability to incur additional indebtedness, pay dividends, make restricted payments, create liens, and sell assets. The Company is in compliance with all covenants for all periods.

The debt discount is amortized as additional non-cash interest expense over the term of the Senior Notes. As of September 30, 2009, the net carrying amount of the Senior Notes is as follows (amounts in thousands):

Principal amount of the Senior Notes	$	250,000
Unamortized debt discount		(11,821	)
Carrying amount of the Senior Notes	$	238,179

As a result of the amortization of the debt discount through non-cash interest expense, the effective interest rate on the Company’s Senior Notes is 11.3% per annum. The amount of the cash interest expense recognized with respect to the 9.875% contractual interest coupon for both the three and nine months ended September 30, 2009 was $5.6 million. The amount of non-cash interest expense related to the amortization of the debt discount and amortization of the transaction costs for both the three and nine month period ended September 30, 2009 was $0.5 million. The aggregate estimated fair value of the Senior Notes was approximately $263.8 million as of September 30, 2009.

7. Asset Retirement Obligations

The Company accounts for and estimates the initial fair value measurement for its asset retirement obligations in accordance with ASC Topic 410,Asset Retirement and Environmental Obligations(formerly SFAS No. 143, Accounting for Asset Retirement Obligations). This statement generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset.

A reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2009 is as follows (in thousands):

Beginning of period	$	47,193
Liabilities incurred		944
Liabilities settled		(1,699	)
Accretion expense		2,459
Revisions to estimate		—
End of period	$	48,897
Less: current asset retirement obligations		1,038
Long-term asset retirement obligations	$	47,859

15

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

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 its fair value due to its floating rate structure. The Company’s financial and non-financial assets and liabilities that are measured on a recurring basis are measured and reported at fair value in accordance with ASC Topic 820,Fair Value Measurements and Disclosures.

Fair value is defined as 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. A fair value hierarchy was established 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).

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 securities 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 than 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 applicable instruments 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 assets and liabilities as of September 30, 2009 that were measured at fair value on a recurring basis. Assets and 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	$	—	$	94,351		$	—	$	94,351
Liabilities
Commodity Derivatives	$	—	$	(27,529	)	$	—	$	(27,529	)
Interest Rate Derivatives		—		(219	)		—		(219	)

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. In addition, the fair value measurement of a liability has been adjusted to 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.

16

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

Level 1 Fair Value Measurements

As of September 30, 2009, and for the nine months ended September 30, 2009, 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, 2009, and for the nine months ended September 30, 2009, the Company did not have assets or liabilities measured under a Level 3 fair value hierarchy.

9. Derivative Instruments

The Company 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 does not enter into derivative instruments for speculative trading purposes. The Company’s natural gas and oil derivative financial instruments are accounted for in accordance with ASC Topic 815,Derivatives and Hedging (formerly known as SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities).As of September 30, 2009, the Company had hedges in place for a portion of its anticipated production for a total of 322,500 Bbls of crude oil through 2010 and 110,016,500 MMBtu of natural gas through 2012, excluding basis only swaps described below.

In addition to financial contracts, the Company may at times be party to various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. 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.

The Company also has two interest rate derivative contracts to manage the Company’s exposure to changes in interest rates. The first contract is a floating-to-fixed interest rate swap for a notional amount of $10.0 million, and the second is 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 contracts have been designated as cash flow hedges. 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 the Company’s Amended Credit Facility.

All derivative instruments, other than those that meet the normal purchase and normal sale exception as mentioned above, are recorded at fair market value and included in the Unaudited Condensed Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location and fair value of all derivative instruments in the Unaudited Condensed Consolidated Balance Sheets as of September 30, 2009:

	Derivative Assets			Derivative Liabilities
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(in thousands)
Derivatives Designated as Cash Flow Hedges
Current
Interest Rate Contracts	N/A	$	—	Derivative Liability and Other Current Liabilities	$	219
Commodity Contracts	Derivative Assets		90,908	Derivative Assets (2)		4,851
Commodity Contracts	Derivative Liability and Other Current Liabilities (1)		902	Derivative Liability and Other Current Liabilities		2,181
Long Term
Commodity Contracts	Derivative Assets		17,711	Derivative Assets (2)		2,330
Commodity Contracts	Derivatives and Other Noncurrent Liabilities (1)		3,823	Derivatives and Other Noncurrent Liabilities		10,286
Total derivatives designated as hedging instruments		$	113,344		$	19,867
Derivatives Not Designated as Cash Flow Hedges
Current
Commodity Contracts	Derivative Assets	$	9,201	Derivative Assets (2)	$	16,288
Commodity Contracts	N/A		—	Derivative Liability and Other Current Liabilities		7,208
Long Term
Commodity Contracts	Derivative Assets		—	Derivative Assets (2)		—
Commodity Contracts	Derivative and Other Noncurrent Liabilities (1)		232	Derivatives and Other Noncurrent Liabilities		12,811
Total derivates not designated as hedging instruments		$	9,433		$	36,307
Total Derivatives		$	122,777		$	56,174

(1) Amounts are netted against derivative liability balances from the same counterparty, and, therefore, are presented as a net liability on the Company’s Unaudited Condensed Consolidated Balance Sheets.

(2) Amounts are netted against derivative asset balances from the same counterparty, and, therefore, are presented as a net asset on the Company’s Unaudited Condensed Consolidated Balance Sheets.

17

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

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 (“OCI”) until the forecasted transaction occurs. The Company will reclassify the appropriate cash flow hedge amounts from OCI to gains or losses in the Unaudited Condensed Consolidated Statements of Operations as the hedged production quantity is produced or the interest rate derivative is settled. Based on projected market prices as of September 30, 2009, the amount to be reclassified from OCI to net income in the next 12 months would be an after-tax net gain of approximately $60.1 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 the Company’s derivatives that continue to be accounted for as cash flow hedges will occur by the end of the originally specified time periods.

The commodity 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. 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. The ineffective portion of commodity hedge derivatives is reported in commodity derivative gain or loss in the Unaudited Condensed Consolidated Statements of Operations. Ineffectiveness on interest rate derivatives was de minimis for the three and nine months ended September 30, 2009. The following table summarizes the cash flow hedge gains and losses and their locations on the Unaudited Condensed Consolidated Balance Sheet as of September 30, 2009 and Unaudited Condensed Consolidated Statements of Operations for the three months ended September 30, 2009:

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in OCI (net of tax)			Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (before tax)			Location of Loss on Ineffective Hedges	Amount of Loss Recognized in Income on Ineffective Hedges (before tax)
	(in thousands)
Interest Rate Contracts	$	127		Interest and Other Income	$	(221	)	N/A		N/A
Commodity Contracts		(65,004	)	Oil and Gas Production		71,210		Commodity Derivative Gain (Loss)		741
Total	$	(64,877	)		$	70,989			$	741

18

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

The following table summarizes the cash flow hedge gains and losses and their locations on the Unaudited Condensed Consolidated Balance Sheet as of September 30, 2009 and Unaudited Condensed Consolidated Statement of Operations for the nine months ended September 30, 2009:

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in OCI (net of tax)			Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (before tax)			Location of Loss on Ineffective Hedges	Amount of Loss Recognized in Income on Ineffective Hedges (before tax)
	(in thousands)
Interest Rate Contracts	$	183		Interest and Other Income	$	(633	)	N/A		N/A
Commodity Contracts		(126,329	)	Oil and Gas Production		234,664		Commodity Derivative Gain (Loss)		(5,721	)
Total	$	(126,146	)		$	234,031			$	(5,721	)

If, during the derivative’s term, the Company determines that the hedge is no longer effective or necessary, hedge accounting is prospectively discontinued. All subsequent changes in the derivative’s fair value are recorded in earnings, and all accumulated gains or losses, based on the effective portion of the derivative at that date, recorded in OCI will remain in OCI and are reclassified to earnings when the underlying transaction 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. All current mark-to-market gains and losses are recorded in earnings and all accumulated gains or losses recorded in OCI related to the hedging instrument are also reclassified to earnings. Effective September 1, 2009, the Company voluntarily elected to discontinue cash flow hedge accounting for certain hedges in the Rocky Mountain region and instead enter into physical fixed-price sales contracts for a portion of the anticipated October 2009 natural gas production. As a result, an unrealized gain of $13.5 million was frozen in OCI and will be reclassified to earnings as the underlying natural gas hedged production quantity is produced and sold in October 2009. In addition, a loss of $5.9 million was recognized in the Unaudited Condensed Consolidated Statements of Operations in the three months ended September 30, 2009 representing the subsequent change in fair value for those de-designated hedges.

Some of the Company’s commodity derivatives do not qualify for hedge accounting but are, to a degree, an economic offset to the Company’s commodity price exposure. If a commodity 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. The Company’s cash flow is only impacted when the underlying physical sales 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 commodity 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 Statements of Cash Flows.

In addition to the swaps and collars discussed above, the Company has entered into basis only swaps. Basis only swaps hedge the difference between the New York Mercantile Exchange (“NYMEX”) gas price and the price received for the Company’s natural gas production at a specific delivery location. Although the Company believes that this represents a sound risk mitigation strategy, the basis only swaps do not qualify for hedge accounting 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 or loss in the Unaudited Condensed Consolidated Statements of Operations. As of September 30, 2009, the Company had basis only swaps in place for a portion of the Company’s anticipated natural gas production in 2009, 2010, 2011 and 2012 for a total of 29,090,000 MMbtu.

The following table summarizes the location in the Unaudited Condensed Consolidated Statements of Operations and amounts of realized and unrealized gains and losses on derivative instruments that do not qualify for hedge accounting for the three and nine months ended September 30, 2009:

Derivatives Not Designated as Hedging Instruments	Location of Loss Recognized in Income on Derivatives	Amount of Loss Recognized in Income on Derivatives for the Three Months Ended September 30, 2009			Amount of Loss Recognized in Income on Derivatives for the Nine Months Ended September 30, 2009
		(in thousands)			(in thousands)
Commodity Contracts	Commodity Derivative Gain (Loss)	$	(14,434	)	$	(42,891	)

19

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

The Company was a party to various swap and collar contracts for natural gas based on the Colorado Interstate Gas Rocky Mountains (“CIGRM”), Panhandle Eastern Pipe Line Co. (“PEPL”) and Northwest Pipeline Corporation (“NWPL”) indices that settled during the three and nine months ended September 30, 2009 and based on the CIGRM and PEPL indices that settled during the three and nine months ended September 30, 2008. As a result, the Company recognized an increase of natural gas production revenues related to these contracts of $68.6 million and $225.9 million in the three and nine months ended September 30, 2009, respectively, and an increase of revenues of $8.6 million and a decrease of $12.9 million related to these contracts in the three and nine months ended September 30, 2008, respectively. The Company was also a party to various swap and collar contracts for oil based on a West Texas Intermediate (“WTI”) index, recognizing an increase to oil production revenues related to these contracts of $1.2 million and $6.3 million in the three and nine months ended September 30, 2009, respectively, and a reduction of revenues of $4.1 million and $10.8 million related to these contracts in the three and nine months ended September 30, 2008, 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,
	2009			2008			2009			2008
Realized gains (losses) on derivatives designated as cash flow hedges (1)	$	71,210		$	5,457		$	234,664		$	(22,699	)
Realized losses on derivatives not designated as cash flow hedges (2)	$	(1,423	)	$	(963	)	$	(2,446	)	$	(963	)
Unrealized ineffectiveness gains (losses) recognized on derivatives designated as cash flow hedges (2)		741			5,687			(5,721	)		3,121
Unrealized gains (losses) on derivatives not designated as cash flow hedges (2)		(13,011	)		3,766			(40,445	)		1,489
Total commodity derivative gain (loss)	$	(13,693	)	$	8,490		$	(48,612	)	$	3,647

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

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

Derivative financial instruments that hedge the price of oil and gas and interest rate levels are generally executed with major financial or commodities trading institutions that expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company has hedges in place with nine different counterparties, of which all but one are lenders in the Amended Credit Facility. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. The credit worthiness of counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.

It is the Company’s policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility, or potential lenders in the Amended Credit Facility. With the exception of one counterparty, the Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). The counterparty with which the Company currently does not have an ISDA in place represents 0.8% of the fair value of the net derivative asset balance. Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions with its lenders (or affiliates of lenders) that, in the event of counterparty default, allow the Company to set-off amounts owed under the Amended Credit Facility or other general obligations against monies owed for derivative contracts. Accordingly, the maximum amount of loss in the event of all counterparties defaulting is $75.2 million as of September 30, 2009, after netting any amounts owed by the Company to its counterparties.

10. Income Taxes

The Company accounts for its uncertain tax positions in accordance with the provisions of the ASC Topic 740,Income Taxes. During the nine months ended September 30, 2009, there was no change to the Company’s liability for uncertain tax positions.

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, 2009, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the nine months ended September 30, 2009.

At September 30, 2009, the Company’s Unaudited Condensed Consolidated Balance Sheets reflected a net deferred tax liability of $232.8 million, of which $39.0 million pertains to the tax effects of derivative instruments reflected in OCI.

20

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

Income tax expense for the three and nine months ended September 30, 2009 and 2008 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. The remainder of the authorized preferred stock is undesignated. There are no issued and outstanding shares of preferred stock.

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 common stockholders.

The Company may occasionally acquire treasury stock, which is recorded at cost, in connection with the vesting and exercise of share-based awards or for other reasons. As of September 30, 2009, all treasury stock held by the Company was retired.

12. Accumulated Other Comprehensive Income

The Company follows the provisions of ASC Topic 220,Comprehensive Income(formerly known as SFAS No. 130,Reporting Comprehensive Income). The components of accumulated other comprehensive income and related tax effects for the nine months ended September 30, 2009 were as follows:

	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated other comprehensive income—December 31, 2008	$	305,410		$	(113,338	)	$	192,072
Unrealized change in fair value of cash flow hedges		33,532			(12,613	)		20,919
Reclassification adjustment for realized gains on hedges included in net income		(234,031	)		86,966			(147,065	)
Accumulated other comprehensive income—September 30, 2009	$	104,911		$	(38,985	)	$	65,926

13. Guarantor Subsidiaries

On July 8, 2009, the Company (“Parent Issuer”) issued 9.875 % Senior Notes (see Note 6). The Senior Notes, as well as the Convertible Notes, are jointly and severally guaranteed on a full and unconditional basis by the Company’s wholly-owned subsidiaries (“Guarantor Subsidiaries”). Presented below are the Company’s condensed consolidating balance sheets, statements of income and statements of cash flows, as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.

The following condensed consolidating financial statements have been prepared from the Company’s financial information on the same basis of accounting as the consolidated financial statements. Investments in the subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent Issuer and the Guarantor Subsidiaries are reflected in the Intercompany Eliminations column.

21

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

Condensed Consolidating Balance Sheets (Unaudited)
	September 30, 2009 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Assets:
Current assets	$	184,684		$	298		$	—		$	184,982
Property and equipment, net		1,577,669			90,464			—			1,668,133
Intercompany receivable (payable)		67,288			(67,288	)		—			—
Investment in subsidiaries		(3,559	)		—			3,559			—
Noncurrent assets		25,825			—			—			25,825
Total assets	$	1,851,907		$	23,474		$	3,559		$	1,878,940
Liabilities and Stockholders’ Equity:
Current liabilities	$	163,240		$	820		$	—		$	164,060
Long-term debt		428,537			—			—			428,537
Deferred income taxes		170,621			25,622			—			196,243
Other noncurrent liabilities		66,945			591			—			67,536
Stockholders’ equity		1,022,564			(3,559	)		3,559			1,022,564
Total liabilities and stockholders’ equity	$	1,851,907		$	23,474		$	3,559		$	1,878,940
	December 31, 2008 (As Adjusted) (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Assets:
Current assets	$	312,554		$	820		$	—		$	313,374
Property and equipment, net		1,468,989			92,830			—			1,561,819
Intercompany receivable (payable)		66,009			(66,009	)		—			—
Investment in subsidiaries		552			—			(552	)		—
Noncurrent assets		119,300			—			—			119,300
Total assets	$	1,967,404		$	27,641		$	(552	)	$	1,994,493
Liabilities and Stockholders’ Equity:
Current liabilities	$	224,891		$	903		$	—		$	225,794
Long-term debt		407,411			—			—			407,411
Deferred income taxes		188,859			25,622			—			214,481
Other noncurrent liabilities		47,010			564			—			47,574
Stockholders’ equity		1,099,233			552			(552	)		1,099,233
Total liabilities and stockholders’ equity	$	1,967,404		$	27,641		$	(552	)	$	1,994,493
Condensed Consolidating Statements of Income (Unaudited)
	Three Months Ended September 30, 2009 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Operating and other revenues	$	146,932		$	1,828		$	—		$	148,760
Operating costs and expenses		118,671			3,616			—			122,287
General and administrative		14,634			—			—			14,634
Interest and other income (expense)		(9,702	)		—			—			(9,702	)
Equity in earnings (loss) of subsidiaries		(1,788	)		—			1,788			—
Income (loss) before income taxes		2,137			(1,788	)		1,788			2,137
Income tax expense		1,419			—			—			1,419
Net income (loss)	$	718		$	(1,788	)	$	1,788		$	718

22

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

	Nine Months Ended September 30, 2009 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Operating and other revenues	$	427,279		$	5,111		$	—		$	432,390
Operating costs and expenses		299,026			9,222			—			308,248
General and administrative		41,274			—			—			41,274
Interest and other income (expense)		(19,804	)		—			—			(19,804	)
Equity in earnings (loss) of subsidiaries		(4,111	)		—			4,111			—
Income (loss) before income taxes		63,064			(4,111	)		4,111			63,064
Income tax expense		25,325			—			—			25,325
Net income (loss)	$	37,739		$	(4,111	)	$	4,111		$	37,739
	Three Months Ended September 30, 2008 (As Adjusted) (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Operating and other revenues	$	161,077		$	3,338		$	—		$	164,415
Operating costs and expenses		84,696			2,628			—			87,324
General and administrative		13,654			—			—			13,654
Interest and other income (expense)		(4,262	)					—			(4,262	)
Equity in earnings (loss) of subsidiaries		710			—			(710	)		—
Income (loss) before income taxes		59,175			710			(710	)		59,175
Income tax expense		23,860			—			—			23,860
Net income (loss)	$	35,315		$	710		$	(710	)	$	35,315
	Nine Months Ended September 30, 2008 (As Adjusted) (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Operating and other revenues	$	464,678		$	6,458		$	—		$	471,136
Operating costs and expenses		252,931			4,962			—			257,893
General and administrative		42,220			—			—			42,220
Interest and other income (expense)		(12,300	)		(67	)		—			(12,367	)
Equity in earnings (loss) of subsidiaries		1,429			—			(1,429	)		—
Income (loss) before income taxes		158,656			1,429			(1,429	)		158,656
Income tax expense		59,518			—			—			59,518
Net income (loss)	$	99,138		$	1,429		$	(1,429	)	$	99,138
Condensed Consolidating Statements of Cash Flows (Unaudited)
	Nine Months Ended September 30, 2009 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities	$	371,707		$	1,110		$	—		$	372,817
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions		(371,589	)		(1,231	)		—			(372,820	)
Additions to furniture, fixtures and other		(2,130	)		(1,157	)		—			(3,287	)
Proceeds from sale of properties		2,714			—			—			2,714
Cash flows from financing activities:
Proceeds from debt		337,930			—			—			337,930
Principal payments on debt		(321,000	)		—			—			(321,000	)
Intercompany transfers		(1,278	)		1,278			—			—
Other financing activities		(5,866	)		—			—			(5,866	)
Change in cash and cash equivalents		10,488			—			—			10,488
Beginning cash and cash equivalents		43,063			—			—			43,063
Ending cash and cash equivalents	$	53,551		$	—		$	—		$	53,551

23

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

	Nine Months Ended September 30, 2008 (As Adjusted) (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Cash flows from operating activities	$	336,507		$	3,681		$	—	$	340,188
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions		(379,312	)		(5,463	)		—		(384,775	)
Additions to furniture, fixtures and other		(1,957	)		—			—		(1,957	)
Proceeds from sale of properties		2,354			—			—		2,354
Cash flows from financing activities:
Proceeds from debt		239,800			—			—		239,800
Principal payments on debt		(167,300	)		—			—		(167,300	)
Intercompany transfers		(1,782	)		1,782			—		—
Other financing activities		(1,191	)		—			—		(1,191	)
Change in cash and cash equivalents		27,119			—			—		27,119
Beginning cash and cash equivalents		60,285			—			—		60,285
Ending cash and cash equivalents	$	87,404		$	—		$	—	$	87,404

24

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 restrictions and 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, 2008 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 (“we,” “our” 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 of coalbed methane properties located in the Powder River Basin. In June 2007, we completed the sale of our Williston Basin properties. In June 2009, we completed an acquisition of unproved undeveloped acreage in the Cottonwood Gulch area of the Piceance Basin.

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Results of Operations

The financial information for the nine months ended September 30, 2009 and 2008 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, 2009 Compared to Nine Months Ended September 30, 2008

	Nine Months Ended September 30,					Increase (Decrease)
	2009			2008		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil and gas production	$	479,455		$	463,759	$	15,696		3	%
Commodity derivative gain (loss)		(48,612	)		3,647		(52,259	)	nm	*
Other		1,547			3,730		(2,183	)	(59	)%
Operating Expenses
Lease operating expense		34,921			32,391		2,530		8	%
Gathering and transportation expense		40,012			29,746		10,266		35	%
Production tax expense		11,850			37,405		(25,555	)	(68	)%
Exploration expense		2,172			2,935		(763	)	(26	)%
Impairment, dry hole costs and abandonment expense		29,834			5,618		24,216		431	%
Depreciation, depletion and amortization expense		189,459			149,798		39,661		26	%
General and administrative expense (1)		29,193			30,124		(931	)	(3	)%
Non-cash stock-based compensation expense (1)		12,081			12,096		(15	)	nm	*
Total operating expenses	$	349,522		$	300,113	$	49,409		16	%
Production Data:
Natural gas (MMcf)		63,859			54,173		9,686		18	%
Oil (MBbls)		517			473		44		9	%
Combined volumes (MMcfe)		66,961			57,011		9,950		17	%
Daily combined volumes (MMcfe/d)		245			208		37		18	%
Average Prices (2):
Natural gas (per Mcf)	$	7.02		$	7.87	$	(0.85	)	(11	)%
Oil (per Bbl)		55.76			76.57		(20.81	)	(27	)%
Combined (per Mcfe)		7.12			8.12		(1.00	)	(12	)%
Average Costs (per Mcfe):
Lease operating expense	$	0.52		$	0.57	$	(0.05	)	(9	)%
Gathering and transportation expense		0.60			0.52		0.08		15	%
Production tax expense		0.18			0.66		(0.48	)	(73	)%
Depreciation, depletion and amortization		2.83			2.63		0.20		8	%
General and administrative expense (3)		0.44			0.53		(0.09	)	(17	)%

* 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 $41.3 million and $42.2 million for the nine months ended September 30, 2009 and 2008, 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 expenses 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. As a result of our realized hedging transactions, natural gas production revenues were increased by $225.9 million for the nine months ended September 30, 2009 and reduced by $12.9 million for the nine months ended September 30, 2008. As

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a result of our realized hedging transactions, oil production revenues were increased by $6.3 million for the nine months ended September 30, 2009 and reduced by $10.8 million for the nine months ended September 30, 2008. Before the effects of hedging, the average prices we received for natural gas and oil were as follows:

	Nine Months Ended September 30,
	2009		2008
Natural gas (per Mcf)	$	3.48	$	8.11
Oil (per Bbl)	$	43.59	$	99.47

(3) Excludes non-cash stock-based compensation expense as described in footnote (1) above. This presentation is a non-GAAP measure. 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 $0.62 and $0.74 for the nine months ended September 30, 2009 and 2008, respectively.

Production Revenues.Production revenues increased to $479.5 million for the nine months ended September 30, 2009 from $463.8 million for the nine months ended September 30, 2008, primarily due to a 17% increase in production volumes offset by a 12% decrease in natural gas and oil prices after the effects of realized hedges on a per Mcfe basis. The net increase in production volumes added approximately $71.2 million of production revenues, while the decrease in prices reduced production revenues by approximately $55.5 million. Production from our main areas of operation are summarized in the following table:

	Nine Months Ended September 30, 2009			Nine Months Ended September 30, 2008			% 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	313	24,814	26,692	301	21,361	23,167	4	%	16	%	15	%
Uinta Basin	162	23,776	24,748	127	19,992	20,754	28	%	19	%	19	%
Wind River Basin	22	6,328	6,460	23	7,023	7,161	(4	)%	(10	)%	(10	)%
Powder River Basin	—	8,682	8,682	—	5,777	5,777	—		50	%	50	%
Paradox Basin	1	195	201	—	—	—	nm	*	nm	*	nm	*
Other	19	64	178	22	20	152	(14	)%	220	%	17	%
Total	517	63,859	66,961	473	54,173	57,011	9	%	18	%	17	%

* Not meaningful

Total production volumes for the nine months ended September 30, 2009 of 67.0 Bcfe increased from 57.0 Bcfe for the nine months ended September 30, 2008 due to increased production from the Piceance, Uinta and Powder River Basins, offset by a decrease in production in the Wind River Basin. The production increase in the Piceance Basin was the result of our continued development activities with initial sales from 111 new gross wells from October 1, 2008 to September 30, 2009. The production increase in the Uinta Basin was the result of our continued development activities with initial sales from 48 new gross wells from October 1, 2008 to September 30, 2009. The production increase in the Powder River Basin was the result of our continued development activities with initial sales from 228 new gross wells from October 1, 2008 to September 30, 2009. Although we have reduced our current year development activities in the Powder River Basin as the result of lower natural gas prices, our production in the Basin has benefited from prior year development programs due to the extended dewatering process of the coal bed methane wells. The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields with no significant drilling or recompletion activities to offset these declines.

Hedging Activities.During the nine months ended September 30, 2009, approximately 75% of our natural gas volumes and 52% of our oil volumes were hedged, which resulted in an increase in gas revenues of $225.9 million and an increase in oil revenues of $6.3 million after settlements for all commodity derivatives, including basis only swaps. 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 settlements for all commodity derivatives.

Commodity Derivative Gain (Loss). Ineffectiveness on cash flow hedges related to slight differences between the contracted location and the actual delivery location is recognized in the line item titled “Commodity derivative gain (loss)” in the Unaudited Condensed Consolidated Statements of Operations. We also have basis only swaps for natural gas in the Rocky Mountain region, which do not qualify for cash flow hedge accounting. The change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting is also recognized in this line item. In addition, effective September 1, 2009 we elected to de-designate certain cash flow hedges in the Rocky Mountain region and enter into physical fixed-price sales contracts for a portion of our anticipated October 2009 natural gas production. As a result, subsequent changes to the fair value of these derivatives will also be reflected in “Commodity derivative gain (loss).” We will continue to consider short term circumstances in the gas markets and make assessments as to whether we will enter into additional physical fixed-price sales contracts in the future.

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

	Nine Months Ended September 30,
	2009			2008
Realized losses on derivatives not designated as cash flow hedges	$	(2,446	)	$	(963	)
Unrealized ineffectiveness gains (losses) recognized on derivatives designated as cash flow hedges		(5,721	)		3,121
Unrealized gains (losses) on derivatives not designated as cash flow hedges		(40,445	)		1,489
Total commodity derivative gain (loss)	$	(48,612	)	$	3,647

Other Operating Revenues.Other operating revenues decreased to $1.5 million for the nine months ended September 30, 2009 from $3.7 million for the nine months ended September 30, 2008. Other operating revenues for the nine months ended September 30, 2009 consisted of gathering, compression and salt water disposal fees received from third parties. 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.

Lease Operating Expense.Lease operating expense decreased to $0.52 per Mcfe for the nine months ended September 30, 2009 from $0.57 per Mcfe for the nine months ended September 30, 2008. The following table displays the lease operating expense by basin:

	Nine Months Ended September 30, 2009				Nine Months Ended September 30, 2008				%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		($ per Mcfe)
Piceance Basin	$	10,933	$	0.41	$	7,482	$	0.32	28	%
Uinta Basin		8,401		0.34		11,852		0.57	(40	)%
Wind River Basin		3,897		0.60		4,821		0.67	(10	)%
Powder River Basin		10,949		1.26		7,799		1.35	(7	)%
Paradox Basin		270		1.34		—		—	nm	*
Other		471		2.65		437		2.83	7	%
Total	$	34,921	$	0.52	$	32,391	$	0.57	(9	)%

* Not meaningful

Lease operating expense increased in the Piceance Basin to $0.41 per Mcfe for the nine months ended September 30, 2009 from $0.32 per Mcfe for the nine months ended September 30, 2008 primarily due to increased compression costs associated with the Bailey Compressor Station that was placed into service in July 2008. The decrease in lease operating expense in the Uinta Basin to $0.34 per Mcfe for the nine months ended September 30, 2009 from $0.57 per Mcfe for the nine months ended September 30, 2008 was the result of decreased water disposal costs due to the utilization of a salt water disposal well, as well as a decrease in compressor overhaul activity in our West Tavaputs field. In addition, for the first half of 2009 we shut in a majority of our Lake Canyon and Blacktail Ridge fields due to gas gathering constraints, which reduced our lease operating expense in the Uinta Basin. Lease operating expense decreased in the Wind River Basin to $0.60 per Mcfe for the nine months ended September 30, 2009 from $0.67 per Mcfe for the nine months ended September 30, 2008 as a result of decreased workover activity and reduced water handling costs. Lease operating expense decreased in the Powder River Basin to $1.26 per Mcfe for the nine months ended September 30, 2009 from $1.35 per Mcfe for the nine months ended September 30, 2008 primarily as a result of decreased power, fuel and labor costs. Initial production from wells in the Powder River Basin that were previously in the dewatering stage increased production without increasing costs, which also reduced the cost per Mcfe in that basin.

Gathering and Transportation Expense.Gathering and transportation expense increased to $0.60 per Mcfe for the nine months ended September 30, 2009 from $0.52 per Mcfe for the nine months ended September 30, 2008. The following table displays the gathering and transportation expense by basin:

	Nine Months Ended September 30, 2009				Nine Months Ended September 30, 2008				%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		($ per Mcfe)
Piceance Basin	$	15,288	$	0.57	$	12,046	$	0.52	10	%
Uinta Basin		14,964		0.60		10,670		0.51	18	%
Wind River Basin		39		0.01		125		0.02	(50	)%
Powder River Basin		9,518		1.10		6,890		1.19	(8	)%
Paradox Basin		174		0.87		—		—	nm	*
Other		29		0.16		15		0.10	60	%
Total	$	40,012	$	0.60	$	29,746	$	0.52	15	%

* Not meaningful

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Gathering and transportation expense increased in the Piceance Basin to $0.57 per Mcfe for the nine months ended September 30, 2009 from $0.52 per Mcfe for the nine months ended September 30, 2008. The increase is primarily attributable to our election to process our gas in order to sell the resulting natural gas liquids (“NGLs”). Beginning in January 2009, we incurred additional fees to process our natural gas and received additional revenue from the sale of NGLs. Although sales revenue for NGLs can fluctuate based on monthly index prices, for the nine months ended September 30, 2009, we realized a Company-wide increase of approximately $0.24 per Mcfe to our average realized price while incurring additional gathering and processing costs of approximately $0.07 per Mcfe. Gathering and transportation expense in the Uinta Basin increased to $0.60 per Mcfe for the nine months ended September 30, 2009 from $0.51 per Mcfe for the nine months ended September 30, 2008. This increase is a result of additional contracts to gather, process and transport our West Tavaputs gas from the Uinta Basin. Also contributing to the increases in both basins were higher fees associated with the Rockies Express Pipeline (“REX”) due to the completion of an additional segment of the pipeline that gave us access to midcontinent delivery points farther east.

We have 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 allocate 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. Included in the above gathering and transportation expense is $0.17 and $0.12 per Mcfe of firm transportation expense for the nine months ended September 30, 2009 and 2008, respectively, along with $0.05 per Mcfe of processing expense from long-term contracts for both the nine months ended September 30, 2009 and 2008.

The increase in firm transportation expense to $0.17 per Mcfe for the nine months ended September 30, 2009 from $0.12 per Mcfe for the nine months ended September 30, 2008 was the result of the additional contracts executed for our West Tavaputs gas and increased fees for REX transportation as mentioned above.

Production Tax Expense.Total production taxes decreased to $11.9 million for the nine months ended September 30, 2009 from $37.4 million for the nine months ended September 30, 2008. The decrease in production taxes is primarily related to decreased natural gas and oil prices during the nine months ended September 30, 2009. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. In addition to the decrease in natural gas and oil prices, on March 23, 2009 we entered into a settlement agreement with the State of Colorado that allowed additional deductions against the gross taxable value of our production related to our 2004 through 2006 severance tax returns. As a result, severance tax expense was reduced by $0.8 million related to the 2004 through 2006 tax years. Based on this settlement, we revised our estimates of 2007 and 2008 Colorado severance tax, which reduced our production tax expense by an additional $4.0 million. Excluding the reduction associated with the Colorado severance tax, production taxes as a percentage of natural gas and oil sales before hedging adjustments were 6.8% for the nine months ended September 30, 2009 and 7.7% for the nine months September 30, 2008. Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas.

Exploration Expense.Exploration expense decreased to $2.2 million for the nine months ended September 30, 2009 from $2.9 million for the nine months ended September 30, 2008. Exploration expense for the nine months ended September 30, 2009 consisted of $0.8 million for seismic programs, principally in the Paradox Basin, $0.4 million related to the evaluation of non-acquired assets and $1.0 million for delay rentals and other costs across all basins. Exploration expense for the nine months ended September 30, 2008 consisted of $2.2 million for seismic programs, principally in the Deseret, Uinta, Paradox and Big Horn Basins, along with $0.7 million for delay rentals and other exploration costs.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense increased to $29.8 million during the nine months ended September 30, 2009 from $5.6 million during the nine months ended September 30, 2008. For the nine months ended September 30, 2009, abandonment expense associated with exploratory drilling locations was $1.2 million, expired leasehold costs were $1.5 million and dry hole costs were $27.1 million. The $27.1 million in dry hole costs were associated with six exploratory wells in the Montana Overthrust area, three exploratory wells in the Hook prospect of the Uinta Basin and one exploratory well in each of the Big Horn Basin, the Yellow Jacket prospect of the Paradox Basin, the Salt Flank prospect of the Paradox Basin and the Woodside prospect of the Uinta Basin, each of which were tested and determined to be non-commercial. For the nine months ended September 30, 2008, abandonment expense associated with exploratory drilling locations was $0.2

29

million, expired leasehold costs were $0.6 million and 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 in June 2008, and was tested and determined to be non-commercial in the Pennsylvanian Weber and Mississippi Leadville zones. Therefore, a proportionate share of the well cost was expensed. For the nine months ended September 30, 2009 and 2008, we did not incur any impairment charges related to the net carrying value of our development areas.

Depreciation, Depletion and Amortization (“DD&A”).DD&A was $189.5 million for the nine months ended September 30, 2009 compared to $149.8 million for the nine months ended September 30, 2008. The increase of $39.7 million was a result of a 17% increase in production for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, along with an increase in the DD&A rate. The increase in production accounted for $26.2 million of additional DD&A expense, while the overall increase in the DD&A rate accounted for $13.5 million of additional DD&A expense.

During the nine months ended September 30, 2009, the weighted average DD&A rate was $2.83 per Mcfe. For the nine months ended September 30, 2008, the weighted average DD&A rate was $2.63 per Mcfe. Under the successful efforts method of accounting, DD&A expense is separately computed for each producing area based on proved reserves in each geologic and reservoir delineation. Proved reserves for each producing area are determined on a semi-annual basis using engineering forecasts with oil and natural gas prices as of the period end date. 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, decreased to $29.2 million in the nine months ended September 30, 2009 from $30.1 million in the nine months ended September 30, 2008. This decrease was primarily due to non-recurring expenses that were incurred in the nine months ended September 30, 2008, including $0.8 million in connection with our efforts in the Colorado Oil and Gas Conservation Commission (“COGCC”) rulemaking process, $0.4 million of penalty expense on a production tax audit and $0.4 million related to the expensing of high-yield debt offering costs that did not apply to our Convertible Notes offering. This decrease was partially offset by an increase in employee compensation and benefit programs for the nine months ended September 30, 2009. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, decreased to $0.44 per Mcfe for the nine months ended September 30, 2009 from $0.53 per Mcfe for the nine months ended September 30, 2008 due to the reasons mentioned above as well as increased production.

Non-cash charges for stock-based compensation remained consistent at $12.1 million for both the nine months ended September 30, 2009 and 2008. Non-cash stock-based compensation expense for each of the nine months ended September 30, 2009 and 2008 related to vesting of our stock option awards and nonvested shares of common stock issued to employees.

Interest Expense.Interest expense increased to $20.1 million for the nine months ended September 30, 2009 from $14.0 million for the nine months ended September 30, 2008. The increase for the nine months ended September 30, 2009 was due to higher average outstanding debt balances at higher interest rates. Our weighted average outstanding debt balance, including our Amended Credit Facility, our 5.0% Convertible Notes issued in March 2008 and our 9.875% Senior Notes issued in July 2009, was $433.0 million for the nine months ended September 30, 2009 compared to $294.1 million for the nine months ended September 30, 2008. Our weighted average interest rate for the nine months ended September 2009, including our Amended Credit Facility, our Convertible Notes issued in March 2008 and our Senior Notes issued in July 2009, was 7.1% compared to 7.0% for the nine months ended September 2008.

Interest expense also includes $4.2 million and $2.7 million of non-cash interest expense for the nine months ended September 30, 2009 and 2008, respectively, related to the amortization of debt discounts recorded on our Convertible Notes and Senior Notes. The debt discounts are amortized to interest expense over the expected term of the debt; thus, resulting in non-cash interest expense.

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, 2009 and 2008 were 7.1% and 5.3%, respectively, which included interest on our Convertible Notes and Senior Notes and Amended Credit Facility, amortization of the Convertible Notes and Senior Notes discounts, 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 $3.4 million and $1.4 million for the nine months ended September 30, 2009 and 2008, respectively.

        Income Tax Expense. Income tax expense totaled $25.3 million for the nine months ended September 30, 2009 compared to $59.5 million for the nine months ended September 30, 2008, resulting in effective tax rates of 40.2% and 37.5%, respectively. The decrease in income tax expense is primarily the result of the variations in components, and the resulting decrease, of net income as discussed above. The decrease in operating income had little impact on permanent differences affecting the tax rate calculation, thus increasing the overall effective tax rate. For both the 2009 and 2008 periods, our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense and other operating expenses that are not deductible for income tax purposes.

30

Due to the tax deductions created by our drilling activities and a federal tax net operating loss carryforward from 2008 of $95.8 million, we expect that we will incur cash income tax liabilities relating only to the alternative minimum tax in 2009.

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

	Three Months Ended September 30,					Increase (Decrease)
	2009			2008		Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil and gas production	$	161,719		$	155,050	$	6,669		4	%
Commodity derivative gain (loss)		(13,693	)		8,490		(22,183	)	(261	)%
Other		734			875		(141	)	(16	)%
Operating Expenses
Lease operating expense		13,005			12,548		457		4	%
Gathering and transportation expense		16,260			10,103		6,157		61	%
Production tax expense		6,547			13,519		(6,972	)	(52	)%
Exploration expense		630			1,010		(380	)	(38	)%
Impairment, dry hole costs and abandonment expense		19,103			463		18,640		4,026	%
Depreciation, depletion and amortization expense		66,742			49,681		17,061		34	%
General and administrative expense (1)		10,291			9,704		587		6	%
Non-cash stock-based compensation expense (1)		4,343			3,950		393		10	%
Total operating expenses	$	136,921		$	100,978	$	35,943		36	%
Production Data:
Natural gas (MMcf)		21,711			18,568		3,143		17	%
Oil (MBbls)		180			172		8		5	%
Combined volumes (MMcfe)		22,791			19,600		3,191		16	%
Daily combined volumes (MMcfe/d)		248			213		35		16	%
Average Prices (2):
Natural gas (per Mcf)	$	6.86		$	7.57	$	(0.71	)	(9	)%
Oil (per Bbl)		63.30			79.07		(15.77	)	(20	)%
Combined (per Mcfe)		7.03			7.86		(0.83	)	(11	)%
Average Costs (per Mcfe):
Lease operating expense	$	0.57		$	0.64	$	(0.07	)	(11	)%
Gathering and transportation expense		0.71			0.52		0.19		37	%
Production tax expense		0.29			0.69		(0.40	)	(58	)%
Depreciation, depletion and amortization		2.93			2.53		0.40		16	%
General and administrative expense (3)		0.45			0.50		(0.05	)	(10	)%

(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 $14.6 million and $13.7 million for the three months ended September 30, 2009 and 2008, 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 expenses 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. As a result of our realized hedging transactions, natural gas production revenues were increased by $68.6 million for the three months ended September 30, 2009 and by $8.6 million for the three months ended September 30, 2008. As a result of our realized hedging transactions, oil production revenues were increased by $1.2 million for the three months ended September 30, 2009, and reduced by $4.1 million for the three months ended September 30, 2008. Before the effects of hedging, the average prices we received for natural gas and oil were as follows:

	Three Months Ended September 30,
	2009		2008
Natural gas (per Mcf)	$	3.70	$	7.10
Oil (per Bbl)	$	56.53	$	102.98

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(3) Excludes non-cash stock-based compensation expense as described in footnote (1) above. This presentation is a non-GAAP measure. 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 $0.64 and $0.70 for the three months ended September 30, 2009 and 2008, respectively.

Production Revenues.Production revenues increased to $161.7 million for the three months ended September 30, 2009 from $155.0 million for the three months ended September 30, 2008, primarily due to a 16% increase in production volumes offset by an 11% decrease in natural gas and oil prices after the effects of realized hedges on a per Mcfe basis. The net increase in production volumes added approximately $22.7 million of production revenues, while the decrease in prices reduced production revenues by approximately $16.0 million. Production from our main areas of operation are summarized in the following table:

	Three Months Ended September 30, 2009			Three Months Ended September 30, 2008			% 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	105	8,467	9,097	100	7,287	7,887	5	%	16	%	15	%
Uinta Basin	58	8,069	8,417	53	6,236	6,554	9	%	29	%	28	%
Wind River Basin	11	1,829	1,895	9	2,750	2,804	22	%	(33	)%	(32	)%
Powder River Basin	—	3,273	3,273	—	2,292	2,292	—		43	%	43	%
Paradox Basin	—	69	69	—	—	—	—		nm	*	nm	*
Other	6	4	40	10	3	63	(40	)%	33	%	(37	)%
Total	180	21,711	22,791	172	18,568	19,600	5	%	17	%	16	%

* Not meaningful

Total production volumes for the three months ended September 30, 2009 of 22.8 Bcfe increased from 19.6 Bcfe for the three months ended September 30, 2008 due to increased production from the Piceance, Uinta and Powder River Basins, offset by a decrease in production in the Wind River Basin. The production increase in the Piceance Basin was the result of our continued development activities with initial sales from 111 new gross wells from October 1, 2008 to September 30, 2009. The production increase in the Uinta Basin was the result of our continued development activities with initial sales from 48 new gross wells from October 1, 2008 to September 30, 2009. The production increase in the Powder River Basin was the result of our continued development activities with initial sales from 228 new gross wells from October 1, 2008 to September 30, 2009. Although we have reduced our current year development activities in the Powder River Basin as the result of lower natural gas prices, our production in the basin has benefited from prior year development programs due to the extended dewatering process of the coal bed methane wells. The production decrease in the Wind River Basin is due to natural production declines in our Cave Gulch, Cooper Reservoir and Wallace Creek fields with no significant drilling or recompletion activities to offset these declines.

Hedging Activities.During the three months ended September 30, 2009, approximately 72% of our natural gas volumes and 56% of our oil volumes were hedged, which resulted in an increase in gas revenues of $68.6 million and an increase in oil revenues of $1.2 million after settlements for all commodity derivatives. 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 settlements for all commodity derivatives.

Commodity Derivative Gain (Loss). Ineffectiveness on cash flow hedges related to slight differences between the contracted location and the actual delivery location is recognized in the line item titled “Commodity derivative gain (loss)” in the Unaudited Condensed Consolidated Statements of Operations. We also have basis only swaps for natural gas in the Rocky Mountain region, which do not qualify for cash flow hedge accounting. The change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting is also recognized in this line item. In addition, effective September 1, 2009 we elected to de-designate certain cash flow hedges in the Rocky Mountain region and enter into physical fixed-price sales contracts for a portion of our anticipated October 2009 natural gas production. As a result, subsequent changes to the fair value of these derivatives will also be reflected in “Commodity derivative gain (loss).”

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

	Three Months Ended September 30,
	2009			2008
Realized losses on derivatives not designated as cash flow hedges	$	(1,423	)	$	(963	)
Unrealized ineffectiveness gains recognized on derivatives designated as cash flow hedges		741			5,687
Unrealized gains (losses) on derivatives not designated as cash flow hedges		(13,011	)		3,766
Total commodity derivative gain (loss)	$	(13,693	)	$	8,490

Other Operating Revenues.Other operating revenues decreased to $0.7 million for the three months ended September 30, 2009 from $0.9 million for the three months ended September 30, 2008. Other operating revenues for the three months ended September 30, 2009 consisted of gathering, compression and salt water disposal fees received from third parties. 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.

Lease Operating Expense.Lease operating expense decreased to $0.57 per Mcfe for the three months ended September 30, 2009 from $0.64 per Mcfe for the three months ended September 30, 2008. The following table displays the lease operating expense by basin:

	Three Months Ended September 30, 2009				Three Months Ended September 30, 2008				%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		($ per Mcfe)
Piceance Basin	$	4,030	$	0.44	$	2,689	$	0.34	29	%
Uinta Basin		3,357		0.40		4,227		0.64	(38	)%
Wind River Basin		1,458		0.77		1,608		0.57	35	%
Powder River Basin		3,994		1.22		3,850		1.68	(27	)%
Paradox Basin		81		1.17		—		—	nm	*
Other		85		2.13		174		2.76	(23	)%
Total	$	13,005	$	0.57	$	12,548	$	0.64	(11	)%

* Not meaningful

Lease operating expense increased in the Piceance Basin to $0.44 per Mcfe for the three months ended September 30, 2009 from $0.34 per Mcfe for the three months ended September 30, 2008 primarily due to increased compression costs associated with the Bailey Compressor Station that was placed into service in July 2008. In addition, property taxes in the Piceance Basin increased due to an increase in the assessed value of the Bailey and Mamm Creek compressor stations. The decrease in lease operating expense in the Uinta Basin to $0.40 per Mcfe for the three months ended September 30, 2009 from $0.64 per Mcfe for the three months ended September 30, 2008 was the result of decreased water disposal costs due to the utilization of a salt water disposal well in addition to a decrease in compressor overhaul activity and decreased labor costs in our West Tavaputs field. Lease operating expense increased in the Wind River Basin to $0.77 per Mcfe for the three months ended September 30, 2009 from $0.57 per Mcfe for the three months ended September 30, 2008 as a result of an increase in property taxes, compression and labor costs. The decrease in lease operating expense in the Powder River Basin to $1.22 per Mcfe for the three months ended September 30, 2009 from $1.68 per Mcfe for the three months ended September 30, 2008 is primarily due to decreased power, fuel and labor costs. Initial production from wells in the Powder River Basin that were previously in the dewatering stage increased production without increasing costs which also reduced the cost per Mcfe in that basin.

Gathering and Transportation Expense.Gathering and transportation expense increased to $0.71 per Mcfe for the three months ended September 30, 2009 from $0.52 per Mcfe for the three months ended September 30, 2008. The following table displays the gathering and transportation expense by basin:

	Three Months Ended September 30, 2009						Three Months Ended September 30, 2008				%Increase/(Decrease)
	($ in thousands)			($ per Mcfe)			($ in thousands)		($ per Mcfe)		($ per Mcfe)
Piceance Basin	$	7,056		$	0.78		$	3,734	$	0.47	66	%
Uinta Basin		5,509			0.65			3,521		0.54	20	%
Wind River Basin		10			0.01			37		0.01	0	%
Powder River Basin		3,655			1.12			2,810		1.23	(9	)%
Paradox Basin		40			0.58			—		—	nm	*
Other		(10	)		(0.25	)		1		0.02	nm	*
Total	$	16,260		$	0.71		$	10,103	$	0.52	37	%

* Not meaningful

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Gathering and transportation expense increased in the Piceance Basin to $0.78 per Mcfe for the three months ended September 30, 2009 from $0.47 per Mcfe for the three months ended September 30, 2008. This increase is due in part to our election to process our gas in order to sell the resulting NGLs. For the three months ended September 30, 2009, we incurred additional fees to process our natural gas and received additional revenue from the sale of NGLs. Although sales revenue for NGLs can fluctuate based on monthly index prices, for the three months ended September 30, 2009, we realized a Company-wide increase of approximately $0.39 per Mcfe to our average realized price while incurring additional gathering and processing costs of approximately $0.08 per Mcfe. Also contributing to the increase was higher transportation fees associated with REX due to the completion of an additional segment of the pipeline that gave us access to midcontinent delivery points farther east. Additionally, the majority of gas transported on REX was supplied by the Piceance Basin for the three months ended September 30, 2009, whereas the majority of gas transported on REX for the three months ended September 30, 2008 was supplied by the Uinta Basin. The increase in expense in the Uinta Basin to $0.65 per Mcfe for the three months ended September 30, 2009 from $0.54 per Mcfe for the three months ended September 30, 2008 was the result of additional contracts to gather, process and transport our West Tavaputs gas.

Included in the total gathering and transportation expense is $0.19 and $0.12 per Mcfe of firm transportation expense for the three months ended September 30, 2009 and 2008, respectively, along with $0.05 and $0.04 per Mcfe of processing expense from long-term contracts for the three months ended September 30, 2009 and 2008, respectively.

The increase in firm transportation expense to $0.19 per Mcfe for the three months ended September 30, 2009 from $0.12 per Mcfe for the three months ended September 30, 2008 was the result of additional long-term contracts executed for our West Tavaputs gas and increased fees for REX transportation as mentioned above.

Production Tax Expense.Total production taxes decreased to $6.5 million for the three months ended September 30, 2009 from $13.5 million for the three months ended September 30, 2008. The decrease in production taxes is primarily related to decreased natural gas and oil prices during the nine months ended September 30, 2009. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of natural gas and oil sales before hedging adjustments were 7.2% for the three months ended September 30, 2009 and 9.0% for the three months September 30, 2008. Production tax rates vary across the different areas in which we operate. Therefore, as the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas.

Exploration Expense.Exploration expense decreased to $0.6 million for the three months ended September 30, 2009 from $1.0 million for the three months ended September 30, 2008. Exploration expense for the three months ended September 30, 2009 consisted of $0.1 million for seismic programs, principally in the Hook and Blacktail Ridge prospects of the Uinta Basin, $0.3 million for delay rentals and other costs across all basins and $0.2 million related to the evaluation of non-acquired assets. 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, along with $0.2 million for delay rentals and other costs across all basins.

Impairment, Dry Hole Costs and Abandonment Expense.Our impairment, dry hole costs and abandonment expense increased to $19.1 million during the three months ended September 30, 2009 from $0.5 million during the three months ended September 30, 2008. For the three months ended September 30, 2009, abandonment expense associated with exploratory drilling locations was $0.9 million, expired leasehold costs were $0.5 million and dry hole costs were $17.7 million. The $17.7 million in dry hole costs were associated with four exploratory wells in our Circus prospect of the Montana Overthrust area, two exploratory wells in our Hook prospect and one exploratory well in our Woodside prospect, both in the Uinta Basin, and one exploratory well in our Salt Flank prospect of the Paradox Basin, each of which were tested and determined to be non-commercial. For the three months ended September 30, 2008, abandonment expense associated with exploratory drilling locations was $0.2 million and expired leasehold costs were $0.3 million. For the three months ended September 30, 2009 and 2008, we did not incur any impairment charges related to the net carrying value of our development areas.

Depreciation, Depletion and Amortization.DD&A was $66.7 million for the three months ended September 30, 2009 compared to $49.7 million for the three months ended September 30, 2008. The increase of $17.0 million was a result of a 16% increase in production for the three months ended September 30, 2009 compared to the three months ended September 30, 2008, along with an increase in the DD&A rate. The increase in production accounted for $8.1 million of additional DD&A expense, while the increase in the DD&A rate accounted for $8.9 million of additional DD&A expense.

During the three months ended September 30, 2009, the weighted average DD&A rate was $2.93 per Mcfe. For the three months ended September 30, 2008, the weighted average DD&A rate was $2.53 per Mcfe. Under the successful efforts method of accounting, DD&A expense is separately computed for each producing area based on proved reserves in each geologic and reservoir delineation.

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Proved reserves for each producing area are determined on a semi-annual basis using engineering forecasts with oil and gas prices as of the period end date. 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 $10.3 million in the three months ended September 30, 2009 compared to $9.7 million in the three months ended September 30, 2008. This increase was primarily due to an increase in employee compensation and benefit programs for the three months ended September 30, 2009. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, decreased to $0.45 per Mcfe for the three months ended September 30, 2009 from $0.50 per Mcfe for the three months ended September 30, 2008 due to an increase in production for the three months ended September 30, 2009.

Non-cash charges for stock-based compensation were $4.3 million for the three months ended September 30, 2009 compared to $4.0 million for the three months ended September 30, 2008. Non-cash stock-based compensation expense for each of the three months ended September 30, 2009 and 2008 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 2008 and during the nine months ended September 30, 2009.

Interest Expense.Interest expense increased to $9.7 million for the three months ended September 30, 2009 from $5.1 million for the three months ended September 30, 2008. The increase for the three months ended September 30, 2009 was due to higher average outstanding debt balances at higher average interest rates primarily due to the 9.875% Senior Notes issued in July 2009. Our weighted average outstanding debt balance, including our Amended Credit Facility, our 5.0% Convertible Notes issued in March 2008 and our 9.875% Senior Notes issued in July 2009, was $446.9 million for the three months ended September 30, 2009 compared to $313.4 million for the three months ended September 30, 2008. Our weighted average interest rate for the three months ended September 2009, including our Amended Credit Facility, our Convertible Notes issued in March 2008 and our Senior Notes issued in July 2009, was 9.9% compared to 7.0% for the three months ended September 2008.

Interest expense also includes $1.6 million and $1.3 million of non-cash interest expense for the three months ended September 30, 2009 and 2008, respectively, related to the amortization of debt discounts recorded on our Convertible Notes and Senior Notes. The debt discounts are amortized to interest expense over the expected term of the debt; thus, resulting in non-cash interest expense.

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, 2009 and 2008 were 9.9% and 5.1%, respectively, which included interest on our Convertible Notes and Senior Notes and Amended Credit Facility, amortization of the Convertible Notes and Senior Notes discounts, 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 $1.5 million and $0.6 million for the three months ended September 30, 2009 and 2008, respectively.

Income Tax Expense. Income tax expense totaled $1.4 million for the three months ended September 30, 2009 compared to $23.9 million for the three months ended September 30, 2008, resulting in effective tax rates of 66.4% and 40.3%, respectively. The decrease in income tax expense is primarily the result of the variations in components, and the resulting decrease, of net income as discussed above. The decrease in operating income had little impact on permanent differences affecting the tax rate calculation, thus increasing the overall effective tax rate. For both the 2009 and 2008 periods, our effective tax rate differs from the statutory rates primarily because we recorded stock-based compensation expense and other operating expenses that are 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 and debt securities, including our Convertible Notes and Senior Notes, net cash provided by operating activities, bank credit facilities, proceeds from joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the exploration, development and acquisition of natural gas and oil properties. As we pursue 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. Over the past eighteen months, the debt and equity markets have been under considerable stress and dislocation making financing transactions difficult to complete. However, we believe that we have significant liquidity available to us from cash flows from operations and under our Amended Credit Facility for our planned uses of capital. In addition, our strong hedge positions provide relative certainty on a significant portion of our cash flows from operations through 2010 even with a general decline in the prices of natural gas and oil

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resulting from current oversupply and decreased demand. 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. We filed an automatically effective shelf registration statement with the SEC that we used for the offering of our Senior Notes and we may use for future securities offerings.

At September 30, 2009, we had cash and cash equivalents of $53.6 million with a balance of $33.0 million of borrowings outstanding under our Amended Credit Facility. Based on our mid-year 2009 proved reserves and hedge positions, the borrowing base was increased to $630.0 million with commitments from 17 lenders for a total of $592.8 million effective October 9, 2009.

Cash Flow from Operating Activities

For the nine months ended September 30, 2009, we generated $372.8 million of cash provided by operating activities, an increase of $32.6 million over the same period in 2008. Cash provided by operating activities increased primarily due to higher natural gas and oil volumes partially offset by lower average sales prices for both crude oil and natural gas produced in the nine months ended September 30, 2009. Cash provided by operating activities further increased due to changes in current assets and liabilities.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas and oil production. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity, weather, infrastructure capacity to reach markets, supply levels 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 “Item 3.—Quantitative and Qualitative Disclosure about Market Risk” below.

To mitigate some of the potential negative impact on cash flow caused by changes in natural gas and oil prices, we have entered into financial commodity swap and collar contracts to receive fixed prices for a portion of our natural gas and oil production. At September 30, 2009, we had in place natural gas and crude oil financial collars and swaps covering portions of our 2009, 2010, 2011 and 2012 production.

In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of natural gas that cover varying periods of time and have varying pricing provisions. 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 and are included in the Unaudited Condensed Consolidated Balance Sheets as assets or liabilities. 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 OCI 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 OCI 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, during the derivative’s term, we determine that the hedge is no longer effective or necessary, hedge accounting is prospectively discontinued. All subsequent changes in the derivative’s fair value are recorded in earnings, and all accumulated gains or losses, based on the effective portion of the derivative at that date, recorded in OCI will remain in OCI and are reclassified to earnings when the underlying transaction 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. All current mark-to-market gains and losses are recorded in earnings, and all accumulated gains or losses recorded in OCI related to the hedging instrument are also reclassified to earnings. Effective September 1, 2009, we voluntarily elected to discontinue cash flow hedge accounting for certain hedges in the Rocky Mountain region and instead enter into physical fixed-price sales contracts for a portion of our anticipated October 2009 natural gas production. As a result, an unrealized gain of $13.5 million was frozen in OCI and will be reclassified to earnings when the underlying natural gas sales occur in October 2009. In addition, a loss of $5.9 million was recognized in the Unaudited Condensed Consolidated Statements of Operations representing the subsequent change in fair value for those de-designated hedges. For additional information, see above “—Results of Operations—Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008”.

Some of our derivatives do not qualify for hedge accounting 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

36

changes in market prices. Our cash flow is only impacted when the underlying physical sales 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 Statements of Cash Flows.

In addition to the swaps and collars discussed above, we have entered into basis only swaps to hedge 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 risk mitigation strategy, the basis only swaps do not qualify for hedge accounting 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, 2009, we had basis only hedges in place for a portion of our anticipated natural gas production in 2009, 2010, 2011 and 2012 for a total of 29,090,000 MMbtu. We recognized $7.1 million and $34.5 million in unrealized net loss within commodity derivative gain (loss) in the Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2009, respectively, attributable to these basis only swaps.

At September 30, 2009, the estimated fair value of all of our commodity derivative instruments was a net asset of $66.8 million comprised of current and noncurrent assets and liabilities, including a fair value net liability of $34.5 million for basis only 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, 2009 to be reclassified from OCI to earnings in the next 12 months would be a gain of approximately $60.2 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.

The hedge instruments designated as cash flow hedges are at liquid trading locations but may contain slight differences compared to the delivery location of the forecasted sale, which may result in ineffectiveness. Ineffectiveness related to our cash flow derivative instruments for the three and nine months ended September 30, 2009 was a gain of $0.7 million and a loss of $5.7 million, respectively, and gains of $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 (loss) in 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.

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,
	2009			2008			2009			2008
Realized gains (losses) on derivatives designated as cash flow hedges (1)	$	71,210		$	5,457		$	234,664		$	(22,699	)
Realized losses on derivatives not designated as cash flow hedges (2)	$	(1,423	)	$	(963	)	$	(2,446	)	$	(963	)
Unrealized ineffectiveness gains (losses) recognized on derivatives designated as cash flow hedges (2)		741			5,687			(5,721	)		3,121
Unrealized gains (losses) on derivatives not designated as cash flow hedges (2)		(13,011	)		3,766			(40,445	)		1,489
Total commodity derivative gain (loss)	$	(13,693	)	$	8,490		$	(48,612	)	$	3,647

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

(2) Included in “Commodity derivative gain (loss)” 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, 2009 in order to hedge a portion of our natural gas production for the remainder of 2009 and years 2010, 2011 and 2012 and a portion of our oil production for the remainder of 2009 and the year 2010. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production. In addition to the swaps and collars, we also have in place basis only swaps in order to hedge the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location.

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Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Price		Weighted Average Ceiling Price		Weighted Average Fixed Price		Basis Differential			Index Price(1)	Fair Market Value (in thousands)
Cashless Collars:
2009
Natural gas	1,380,000	MMBtu	$	6.75	$	9.57		N/A		N/A		CIGRM	$	3,323
Natural gas	1,530,000	MMBtu	$	6.00	$	10.56		N/A		N/A		NWPL	$	2,365
Oil	50,600	Bbls	$	86.82	$	143.51		N/A		N/A		WTI	$	835
2010
Natural gas	6,080,000	MMBtu	$	6.00	$	10.41		N/A		N/A		NWPL	$	6,265
Natural gas	1,982,500	MMBtu	$	4.87	$	5.66		N/A		N/A		CIGRM	$	(592	)
Natural gas	2,140,000	MMBtu	$	7.00	$	11.00		N/A		N/A		TCO	$	2,744
Oil	146,000	Bbls	$	80.00	$	148.13		N/A		N/A		WTI	$	2,139
2011
Natural gas	2,140,000	MMBtu	$	4.75	$	6.00		N/A		N/A		CIGRM	$	(930	)
Swap Contracts:
2009
Natural gas	10,287,500	MMBtu		N/A		N/A	$	6.60		N/A		CIGRM	$	24,005
Natural gas	1,138,000	MMBtu		N/A		N/A	$	7.96		N/A		PEPL	$	4,240
Natural gas	610,000	MMBtu		N/A		N/A	$	6.56		N/A		NWPL	$	1,003
Natural gas	305,000	MMBtu		N/A		N/A	$	5.45		N/A		DA	$	(18	)
Natural gas	305,000	MMBtu		N/A		N/A	$	5.33		N/A		TCO	$	(28	)
Oil	52,900	Bbls		N/A		N/A	$	74.02		N/A		WTI	$	155
2010
Natural gas	40,747,500	MMBtu		N/A		N/A	$	6.57		N/A		CIGRM	$	40,077
Natural gas	3,497,500	MMBtu		N/A		N/A	$	6.49		N/A		NWPL	$	3,068
Natural gas	1,666,000	MMBtu		N/A		N/A	$	7.74		N/A		PEPL	$	3,382
Natural gas	2,590,000	MMBtu		N/A		N/A	$	8.74		N/A		DA	$	6,188
Natural gas	450,000	MMBtu		N/A		N/A	$	5.33		N/A		DA	$	(366	)
Oil	73,000	Bbls		N/A		N/A	$	73.78		N/A		WTI	$	(40	)
2011
Natural gas	24,025,000	MMBtu		N/A		N/A	$	6.20		N/A		CIGRM	$	2,425
Natural gas	8,227,500	MMBtu		N/A		N/A	$	6.16		N/A		NWPL	$	1,258
2012
Natural gas	915,000	MMBtu		N/A		N/A	$	5.96		N/A		CIGRM	$	(196	)
Basis Only Swap Contracts(2):
2009
Natural gas	920,000	MMBtu		N/A		N/A		N/A	$	(1.92	)	NWPL	$	(1,433	)
Natural gas	610,000	MMBtu		N/A		N/A		N/A	$	(1.75	)	CIGRM	$	(843	)
2010
Natural gas	6,690,000	MMBtu		N/A		N/A		N/A	$	(2.49	)	NWPL	$	(12,509	)
Natural gas	6,250,000	MMBtu		N/A		N/A		N/A	$	(2.34	)	CIGRM	$	(10,646	)
2011
Natural gas	7,300,000	MMBtu		N/A		N/A		N/A	$	(1.72	)	NWPL	$	(6,459	)
2012
Natural gas	3,660,000	MMBtu		N/A		N/A		N/A	$	(1.24	)	NWPL	$	(1,374	)
Natural gas	3,660,000	MMBtu		N/A		N/A		N/A	$	(1.20	)	CIGRM	$	(1,215	)

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The following table includes all hedges entered into subsequent to September 30, 2009 through October 23, 2009:

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Floor Price	Weighted Average Ceiling Price	Weighted Average Fixed Price		Basis Differential	Index Price(1)
Swap Contracts:
2009
Natural gas	610,000	MMBtu	N/A	N/A	$	5.13	N/A	CIGRM
2010
Natural gas	305,000	MMBtu	N/A	N/A	$	6.65	N/A	CIGRM
Natural gas	152,500	MMBtu	N/A	N/A	$	6.55	N/A	NWPL
Oil	73,000	Bbls	N/A	N/A	$	80.00	N/A	WTI
2011
Natural gas	985,000	MMBtu	N/A	N/A	$	6.29	N/A	CIGRM
Natural gas	225,000	MMBtu	N/A	N/A	$	6.55	N/A	NWPL

(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 New York Mercantile Exchange.

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

By removing the price volatility from a portion of our natural gas production for 2009, 2010, 2011 and 2012 and a portion of our oil production for 2009 and 2010, 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 or settled on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of 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 and that are lenders in our Amended Credit Facility, affiliates of lenders in our Amended Credit Facility or potential lenders in our Amended Credit Facility. The creditworthiness of our counterparties is subject to continual review. Furthermore, with the exception of one counterparty, our derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). The ISDAs contain set-off provisions that, in the event of counterparty default, allow us to net our receivables with amounts that we owe the counterparties under our Amended Credit Facility or other general obligations. Accordingly, the maximum amount of loss in the event of all counterparties defaulting is $75.2 million as of September 30, 2009, after netting any amounts owed to us by our counterparties.

The counterparty with which we currently do not have an ISDA in place represents 0.8% of the fair value of the net fair market value of our derivative asset balance. 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 other than cross collateralization with the properties securing our Amended Credit Facility, nor are they required to provide credit support to us. As of October 23, 2009, we do not have any 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	2009		2008
	(in millions)
Piceance	$	203.2	$	188.3
Uinta		80.1		156.0
Paradox		22.5		8.7
Powder River		11.4		28.9
Wind River		1.7		24.0
Other		9.6		17.9
Total	$	328.5	$	423.8

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	Nine Months Ended September 30,
	2009		2008
	(in millions)
Acquisitions of proved and unevaluated properties and other real estate	$	68.9	$	22.9
Drilling, development, exploration and exploitation of natural gas and oil properties		255.5		395.9
Geologic and geophysical costs		2.2		3.0
Furniture, fixtures and equipment		1.9		2.0
Total	$	328.5	$	423.8

The increase in acquisitions of proved and unevaluated properties and other real estate for the nine months ended September 30, 2009 compared to 2008 is primarily related to our acquisition of the Cottonwood Gulch unevaluated properties in the Piceance Basin for $60.0 million. The decrease in drilling, development, exploration and exploitation of natural gas and oil properties is related to a decrease in drilling and completion activities due to lower natural gas prices and also to align our capital spending with cash flows from operations for the year 2009.

Due to current commodity price forecasts, we plan to align capital spending, before acquisitions, with cash flow from operations. Our current estimate for our capital expenditure budget in 2009 is approximately $410.0 million, including the $60.0 million acquisition of the Cottonwood Gulch leasehold in the Piceance Basin. We believe that we have sufficient available liquidity through 2009 and 2010 with the Amended Credit Facility, our hedge positions, and cash flow from operations. 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 of cash flow 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 generally 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, including acquisitions and divestitures, 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 April 15, 2009, we amended our credit facility (the “Amended Credit Facility”). 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 1.75% to 2.50% (an increase from 1.25% to 2.00% previously) 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 0.75% to 1.50% (an increase from 0.25% to 1.00% previously). The average annual interest rates incurred on the Amended Credit Facility were 2.3% and 4.3% for the nine months ended September 30, 2009 and 2008, respectively. Based on our mid-year 2009 proved reserves and hedge position, the borrowing base was increased to $630.0 million with commitments of $592.8 million effective October 9, 2009. 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 borrowing base is required to be redetermined twice per year. 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 “Item 3.—Quantitative and Qualitative Disclosure about Market Risk—Interest Rate Risks” below.

As of September 30, 2009 and December 31, 2008, borrowings outstanding under the Amended Credit Facility totaled $33.0 million and $254.0 million, respectively. The reduction in borrowings resulted from our application of the proceeds from our Senior Notes issued in June 2009, as discussed below. 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.

We have two interest rate derivative contracts to manage our exposure to changes in interest rates. The first contract is a floating-to-fixed interest rate swap for a notional amount of $10.0 million, and the second is a floating-to-fixed interest rate collar for a notional amount of $10.0 million, both to terminate on December 12, 2009. Under the swap, we will make payments to (or receive payments from) the contract counterparty when the variable rate of one-month LIBOR falls below (or exceeds) the fixed rate of 4.70%. Under the collar, we will make payments to (or receive payments from) the contract counterparty when the variable rate falls below the floor rate of 4.50% or exceeds the ceiling rate of 4.95%. Our interest rate derivative instruments have been designated as

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cash flow hedges. Changes in fair value of the interest rate swaps or collars are reported in OCI, 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, 2009 and 2008.

During the three and nine months ended September 30, 2009, settlement payments on the interest rate derivative contracts, which were included in interest expense, were $0.2 million and $0.6 million, respectively. We anticipate that all originally forecasted transactions will occur by the end of the originally specified time periods. As of September 30, 2009, 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, 2009, 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 is currently 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 certain events. 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 and the Convertible Notes are not traded on a public exchange. Therefore, based on market-based parameters of the various components of the Convertible Notes, the estimated fair value was approximately $163.0 million as of September 30, 2009.

On or after March 26, 2012, at our option, 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, none of which occurred during the three or nine months ended September 30, 2009 or through the date of the filing of this Form 10-Q. 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 that elects to convert its Convertible Notes in connection with such corporate transactions in certain circumstances.

Effective January 1, 2009, we adopted, and retrospectively applied, what was formerly known as Financial Accounting Standards Board (“FASB”) Staff Position (“FSP”) Accounting Principles Board (“APB”) 14-1,Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (including Partial Cash Settlement),which was incorporated into ASC Subtopic 470-20, Debt with Conversion and Other Option. Upon adoption, we recorded a debt discount of $23.1 million as of the date of the issuance of the Convertible Notes. The debt discount is amortized as additional non-cash interest expense over the expected term of the Convertible Notes through March 2012. Total non-cash interest expense related to the Convertible Notes was $1.7 million and $4.8 million for the three and nine months ended September 30, 2009, respectively, and $1.5 million and $3.4 million for the three and nine months ended September 30, 2008, respectively. The amount of cash interest expense recognized for the three and nine months ended September 30, 2009 related to the 5% contractual interest coupon was $2.2 million and $6.5 million, respectively, for the three and nine months ended September 30, 2009, respectively, and $2.2 million and 4.3 million for the three and nine months ended September 30, 2008, respectively. Including the non-cash interest expense, the effective interest rate on our Convertible Notes is 9.7% per annum.

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As of September 30, 2009, the net carrying amount of the Convertible Notes was as follows (amounts in thousands):

Principal amount of the Convertible Notes	$	172,500
Unamortized debt discount		(15,142	)
Carrying amount of the Convertible Notes	$	157,358

Senior Notes. On July 8, 2009, we issued $250.0 million in principal amount of 9.875% Senior Notes due 2016 at 95.172% of par. The 9.875% Senior Notes will mature on July 15, 2016. Interest is payable in arrears semi-annually on January 15 and July 15 beginning January 15, 2010. We received net proceeds of $232.3 million (net of related offering costs), which were used to repay a portion of the borrowings under the Amended Credit Facility. The Senior Notes are our senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes. The Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under our Amended Credit Facility.

The Senior Notes are redeemable, at our option, at 104.938% of the principal amount after July 15, 2013, declining to 100.00% in 2015. Prior to July 15, 2013, we may at our option redeem the Senior Notes at a make-whole price comprised of the greater of 100% of the principal amount or the present value of 104.938% of the principal amount plus a make-whole amount. The make-whole amount is the present value of the remaining interest payments due on the Senior Notes as if such notes were redeemed on July 15, 2013 computed using a discount rate equal to the Treasury Rate plus 50 basis points, over the principal amount of the Senior Notes. We may redeem up to 35% of the aggregate principal amount of the Senior Notes at a price of 109.875% of the principal amount plus accrued interest upon the issuance of equity securities until July 15, 2012. If a specified change of control occurs, we must make an offer to purchase the notes at 101% of the principal amount plus any accrued interest. Additionally, certain asset dispositions that are not reinvested in 360 days may require us to offer to purchase the notes at 100% of principal plus accrued interest. The Senior Notes include certain covenants that limit our ability to incur additional indebtedness, pay dividends, make restricted payments, create liens, and sell assets. We are in compliance with all covenants for all periods.

As a result of the guarantee by the guarantor subsidiaries of the Senior Notes, the terms of the Convertible Notes require the guarantor subsidiaries to also guarantee the Convertible Notes.

The debt discount is amortized as additional non-cash interest expense over the term of the Senior Notes. As of September 30, 2009, the net carrying amount of the Senior Notes is as follows (amounts in thousands):

Principal amount of the Senior Notes	$	250,000
Unamortized debt discount		(11,821	)
Carrying amount of the Senior Notes	$	238,179

As a result of the amortization of the debt discount and amortization of the transaction costs through non-cash interest expense, the effective interest rate on the Senior Notes is 11.3% per annum. The amount of the cash interest expense recognized with respect to the 9.875% contractual interest coupon for both the three and nine months ended September 30, 2009 was $5.6 million. The amount of non-cash interest expense related to the amortization of the debt discount and amortization of the transaction costs for both the three and nine month period ended September 30, 2009 was $0.5 million. The aggregate estimated fair value of the Senior Notes was approximately $263.8 million as of September 30, 2009.

Contractual Obligations.A summary of our contractual obligations as of September 30, 2009 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)	$	—	$	33,000	$	—	$	—	$	—	$	—	$	33,000
Convertible Notes (2)		8,625		8,625		176,741		—		—		—		193,991
Senior Notes (3)		24,688		24,688		24,688		24,688		24,688		294,232		417,672
Purchase commitments (4)(8)		4,416		3,574		824		—		—		—		8,814
Drilling rig commitments (5)(8)		18,584		6,530		769		—		—		—		25,883
Office and office equipment leases and other		3,144		2,191		687		249		222		560		7,053
Firm transportation and processing agreements (8) (9)		28,447		45,143		54,165		54,277		53,900		286,431		522,363
Asset retirement obligations (6)		1,038		9,129		1,943		1,293		504		34,990		48,897
Derivative liability (7)		8,706		12,367		5,916		759		—		—		27,748
Total	$	97,648	$	145,247	$	265,733	$	81,266	$	79,314	$	616,213	$	1,285,421

(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.

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(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 repay the $172.5 million in cash in 2012. We currently expect to call the Convertible Notes for redemption in 2012 or have them put to us. We are also obligated to make annual interest payments equal to $8.6 million.

(3) On July 8, 2009, we issued $250.0 million aggregate principal amount of Senior Notes. We are obligated to make annual interest payments equal to $24.7 million.

(4) We have one take-or-pay carbon dioxide (“CO2”) purchasing agreement that expires in October 2011 whereby we have a minimum volume commitment to purchase CO2 at a contracted price. The contract provides for CO2 used in fracturing operations in our West Tavaputs field. If we do not take delivery of the minimum volume required, we would be obligated to pay for the deficiency.

(5) We currently have three drilling rigs under contract. Two contracts expire in 2010, and one contract expires in 2011.

(6) 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, 2008 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(7) 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, 2009. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. 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, 2008 and in “—Commodity Hedging Activities” above in this Quarterly Report on Form 10-Q for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

(8) The values in the table represent the gross amounts that we are financially committed to pay. However, we record in our financials our proportionate share based on our working interest and net revenue interest, which will vary from basin to basin.

(9) 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 14 years and require us to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by us.

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, 2008 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 price we receive for our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our price swap and collar contracts in place for the nine months ended September 30, 2009, our annual income before income taxes would have decreased by approximately $1.4 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.2 million for each $1.00 per barrel decrease in crude oil prices.

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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 financial transactions may include 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. In addition to the swaps and collars discussed above, we also entered into basis only swaps. With a basis only swap, we have hedged the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location to protect against the risk of large differences between NYMEX (Henry Hub) and our primary sales points, CIGRM and NWPL.

For the fourth quarter ending December 31, 2009, we have financial hedges in place for 16,165,500 MMBtu of natural gas production and approximately 103,500 Bbls of oil production. As of October 23, 2009, we have hedges in place for 59,611,000 MMBtu of natural gas production and 292,000 Bbls of oil production for 2010, 35,602,500 MMBtu of natural gas production for 2011 and 915,000 MMBtu of natural gas production for 2012. In addition, we have basis only swaps in place for 1,530,000 MMBtu of natural gas for 2009, 12,940,000 MMBtu of natural gas for 2010, 7,300,000 MMBtu of natural gas for 2011 and 7,320,000 MMBtu of natural gas for 2012. 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—Commodity Hedging Activities.”

Commodity Hedges

Through a price swap, we have fixed the price we will receive on a portion of our natural gas and oil production. 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 a basis only swap, we have fixed the price differential on a portion of our natural gas production between NYMEX and a specific delivery location such as CIGRM or NWPL. In a basis only swap, the counterparty is required to make a payment to us if the price differential is greater than the fixed price. We are required to make a payment to the counterparty if the price differential is less than the fixed price. We may consider entering into hedge transactions based on a NYMEX price in the future with a volume equal to the volume for our basis only swaps, thereby effectively fixing a price for CIGRM or NWPL.

Through cashless collars, we have fixed the minimum and maximum price we will receive on a portion of our natural gas and oil production. 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 prices. These hedges are summarized in the table presented under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Commodity Hedging Activities.”

Interest Rate Risks

At September 30, 2009, we had debt outstanding under our Amended Credit Facility of $33.0 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, 2009 was 2.3%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the nine months ended September 30, 2009 would have resulted in an estimated $1.5 million increase in interest expense assuming a similar average debt level to the nine months ended September 30, 2009. In addition, we had $172.5 million principal amount of Convertible Notes and $250.0 of Senior Notes outstanding at September 30, 2009, which have fixed cash interest rates of 5.0% and 9.875% per annum, respectively.

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, 2009.

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, 2009 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 we agreed to pay $140,000. The consent decree is subject to the approval of the United States District 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 or updates to the risk factors previously disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2008, referred to as our 2008 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 2008 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.

Various proposed Federal legislation initiatives may decrease our ability, and increase the cost, to enter into hedge transactions.

Various measures are being proposed by Congress that would further regulate hedging transactions. This legislation could make it more difficult and costly for us to enter into hedging transactions by requiring that we post collateral to a central clearing exchange. Because we currently enter into hedges with counterparties that are affiliated with lenders under our Amended Credit Facility, we are not required to post collateral for those transactions. If we are required to post collateral, we would have to do so by utilizing cash or letters of credit, which would reduce our liquidity position and increase costs. Decreasing our ability to enter into hedging transactions would expose us to additional risks related to commodity price volatility and impair our ability to have certainty with respect to a portion of our cash flow, which could lead to decreases in capital spending and therefore decreases in future production and reserves.

Proposed tax law changes could increase our costs and may reduce future production and reserves.

Legislation eliminating or reducing the deduction for intangible drilling costs is currently being considered by the U.S. Congress. This legislation, if passed, would reduce our operating cash flows and funding available for exploration and development programs, which in turn would reduce our future production and reserves. These funding reductions are also likely to impact our peers in the industry and could potentially have a significant adverse effect on drilling for natural gas and oil in the United States. The legislation currently is anticipated to be considered during the last quarter of 2009.

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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.

Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended September 30, 2009:

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, 2009	2,779	$	26.02	—	—
August 1 – 31, 2009	—		—	—	—
September 1 – 30, 2009	1,823		32.47	—	—
Total	4,602	$	28.57	—	—

(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 June 30, 2009, among Bill Barrett Corporation, its subsidiaries, as guarantors, and Banc of America Securities LLC, Deutsche Bank Securities Inc., and J.P. Morgan Securities Inc., as representatives of the several underwriters identified therein. [Incorporated by reference to Exhibit 1.1 of our Current Report on Form 8-K filed with the Commission on June 30, 2009.]
3.1	Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.4 of our 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 of our 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 our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.1(b)	Indenture, dated March 12, 2008, between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]
4.1(c)	Indenture, dated July 8, 2009, between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on July 8, 2009.]
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 our 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 Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 5% Convertible Senior Notes due 2028). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]
4.2(c)	First Supplemental Indenture, dated July 8, 2009, by Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 9.875% Senior Notes due 2016). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on July 8, 2009.]
4.3(a)	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.]
4.3(b)	Second Supplemental Indenture, dated July 8, 2009, by Bill Barrett Corporation, Bill Barrett CBM Corporation, Bill Barrett CBM LLC, Circle B Land Company LLC and Deutsche Bank Trust Company Americas, as Trustee (including form of 9.875% Senior Notes due 2016). [Incorporated by reference to Exhibit 4.3 of our Current Report on Form 8-K with the Commission on July 8, 2009.]
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 Exhibit B thereto the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to our 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 our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
4.6	Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 24, 2004.]
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 our Current Report on Form 8-K filed with the Commission on 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 our Current Report on Form 8-K filed with the Commission on November 7, 2007.]

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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 our Current Report on Form 8-K filed with the Commission on March 10, 2008.]
10.1(d)	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 our Current Report on Form 8-K filed with the Commission on October 21, 2008.]
10.1(e)	Fourth Amendment to Second Amendment and Restated Credit Agreement dated as of April 15, 2009, 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 April 16, 2009.]
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 our 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 of the Company. [Incorporated by reference to Exhibit 10.10(a) to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 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 our 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 our 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 our 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 our 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 our 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 our 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 our 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 our 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 our 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 our 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 our Annual Report on Form 10-K for the year ended December 31, 2005.]

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10.13*	Form of Restricted Common Stock Award Agreement for 2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10-19 to our Annual Report on Form 10-K for the year ended December 31, 2005.]
10.14(a)*	Form of Performance Vesting Restricted Stock Agreement for 2004 Stock Incentive Plan. [Incorporated by reference to Exhibit 10-19 to our Annual Report on Form 10-K for the year ended December 31, 2005.]
10.14(b)*	Form of Performance Vesting Restricted Stock Agreement for 2004 Stock Incentive Plan (2009 Temporary Supplemental Grant). [Incorporated by reference to Exhibit 10.14(b) to our Quarterly Report on Form 10-Q for the three months ended March 31, 2009.]
10.15*	2008 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on May 16, 2008.]
10.16*	Form of Stock Option Agreement for 2008 Stock Incentive Plan. [Incorporated by reference to Exhibit 10.16 to our Annual Report on Form 10-K for the year ended December 31, 2008.]
10.17*	Severance Plan. [Incorporated by reference to Exhibit 10.23 to Amendment No. 4 to our 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 3, 2009	By:	/s/    FREDRICK J. BARRETT
		Fredrick J. Barrett
		Chairman of the Board of Directors and Chief Executive Officer
		(Principal Executive Officer)
Date: November 3, 2009	By:	/s/    ROBERT W. HOWARD
		Robert W. Howard
		Chief Financial Officer
		(Principal Financial Officer)

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