BILL BARRETT CORP - FORM 10-Q

BILL BARRETT CORP - FORM 10-Q - November 2, 2010

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EXCEL - IDEA: XBRL DOCUMENT - BILL BARRETT CORP	Financial_Report.xls
EX-32.1 - SECTION 1350 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - BILL BARRETT CORP	dex321.htm
EX-31.2 - RULE 13A-14(A)/15D-14(A) CERTIFICATION OF CHIEF FINANCIAL OFFICER - BILL BARRETT CORP	dex312.htm
EX-31.1 - RULE 13A-14(A)/15D-14(A) CERTIFICATION OF CHIEF EXECUTIVE OFFICER - BILL BARRETT CORP	dex311.htm
EX-32.2 - SECTION 1350 CERTIFICATION OF CHIEF FINANCIAL OFFICER - BILL BARRETT CORP	dex322.htm

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, 2010

¨	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). x Yes ¨ No

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

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 46,407,701 shares of $0.001 par value common stock outstanding on October 22, 2010.

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	23
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	41
	Item 4.	Controls and Procedures	42

PART II. OTHER INFORMATION

	Item 1.	Legal Proceedings	43
	Item 1A.	Risk Factors	43
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
	Item 3.	Defaults Upon Senior Securities	45
	Item 5.	Other Information	45
	Item 6.	Exhibits	46
SIGNATURES			47

PART I. FINANCIAL INFORMATION

ITEM 1.

Financial Statements.

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


	September 30, 2010			December 31, 2009
	(in thousands, except share and per share data)
Assets:
Current Assets:
Cash and cash equivalents	$	71,772		$	54,405
Accounts receivable, net of allowance for doubtful accounts of $700 for September 30, 2010 and $886 for December 31, 2009		62,653			62,573
Prepayments and other current assets		14,833			4,600
Derivative assets		99,864			58,461

Total current assets		249,122			180,039
Property and Equipment — At cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		2,671,920			2,360,200
Unevaluated oil and gas properties, excluded from amortization		255,841			274,819
Oil and gas properties held for sale		0			5,604
Furniture, equipment and other		26,538			24,727

		2,954,299			2,665,350
Accumulated depreciation, depletion, amortization and impairment		(1,164,500	)		(1,006,090	)

Total property and equipment, net		1,789,799			1,659,260
Derivative Assets		12,197			17,181
Deferred Financing Costs and Other Noncurrent Assets		19,015			9,643

Total	$	2,070,133		$	1,866,123

Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	76,381		$	71,992
Amounts payable to oil and gas property owners		25,601			20,155
Production taxes payable		37,706			34,584
Derivative and other current liabilities		248			9,354
Deferred income taxes		31,275			17,207

Total current liabilities		171,211			153,292
Note Payable to Bank		0			5,000
Senior Notes		239,434			238,478
Convertible Senior Notes		163,088			158,772
Asset Retirement Obligations		51,186			46,785
Liabilities Associated with Assets Held for Sale		0			1,579
Deferred Income Taxes		279,231			218,307
Derivatives and Other Noncurrent Liabilities		5,751			15,355
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 150,000,000 shares; 46,271,612 and 45,475,585 shares issued and outstanding at September 30, 2010 and December 31, 2009, respectively, with 848,134 and 686,421 shares subject to restrictions, respectively		45			45
Additional paid-in capital		811,626			792,418
Retained earnings		269,419			181,682
Treasury stock, at cost: zero shares at September 30, 2010 and December 31, 2009		0			0
Accumulated other comprehensive income		79,142			54,410

Total stockholders’ equity		1,160,232			1,028,555

Total	$	2,070,133		$	1,866,123

See notes to unaudited condensed consolidated financial statements.

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(in thousands, except share and per share amounts)
Operating and Other Revenues:
Oil and gas production	$	185,007		$	161,719		$	534,956		$	479,455
Commodity derivative loss		(4,934	)		(13,693	)		(2,922	)		(48,612	)
Other		558			734			3,032			1,547

Total operating and other revenues		180,631			148,760			535,066			432,390
Operating Expenses:
Lease operating expense		13,001			13,005			39,023			34,921
Gathering, transportation and processing expense		17,301			16,260			51,758			40,012
Production tax expense		8,193			6,547			25,524			11,850
Exploration expense		3,841			630			4,796			2,172
Impairment, dry hole costs and abandonment expense		4,653			19,103			8,520			29,834
Depreciation, depletion and amortization		69,192			66,742			191,626			189,459
General and administrative expense		13,985			14,634			41,729			41,274

Total operating expenses		130,166			136,921			362,976			349,522

Operating Income		50,465			11,839			172,090			82,868
Other Income and Expense:
Interest and other income		231			44			356			294
Interest expense		(11,170	)		(9,746	)		(32,492	)		(20,098	)

Total other income and expense		(10,939	)		(9,702	)		(32,136	)		(19,804	)

Income before Income Taxes		39,526			2,137			139,954			63,064
Provision for Income Taxes		14,964			1,419			52,217			25,325

Net Income	$	24,562		$	718		$	87,737		$	37,739

Net Income Per Common Share, Basic	$	0.54		$	0.02		$	1.95		$	0.84

Net Income Per Common Share, Diluted	$	0.54		$	0.02		$	1.92		$	0.84

Weighted Average Common Shares Outstanding, Basic		45,206,251			44,758,492			45,066,505			44,703,050
Weighted Average Common Shares Outstanding, Diluted		45,790,760			45,109,085			45,595,153			44,899,440

See notes to unaudited condensed consolidated financial statements.

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 (Loss)
	(in thousands)
Balance — December 31, 2008	$	45	$	775,652		$	131,464	$	0		$	192,072		$	1,099,233
Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding		0		880			0		(2,065	)		0			(1,185	)	$	0
APIC pool for excess tax benefits related to share-based compensation		0		52			0		0			0			52			0
Stock-based compensation		0		17,899			0		0			0			17,899			0
Retirement of treasury stock		0		(2,065	)		0		2,065			0			0			0
Comprehensive income (loss):
Net income		0		0			50,218		0			0			50,218			50,218
Effect of derivative financial instruments, net of $80,468 of taxes		0		0			0		0			(137,662	)		(137,662	)		(137,662	)

Total comprehensive income (loss)																	$	(87,444	)

Balance — December 31, 2009	$	45	$	792,418		$	181,682	$	0		$	54,410		$	1,028,555
Exercise of options, vesting of restricted stock and shares exchanged for exercise and tax withholding		0		10,578			0		(3,649	)		0			6,929		$	0
APIC pool for excess tax benefits related to share-based compensation		0		(52	)		0		0			0			(52	)		0
Stock-based compensation		0		12,331			0		0			0			12,331			0
Retirement of treasury stock		0		(3,649	)		0		3,649			0			0			0
Comprehensive income:
Net income		0		0			87,737		0			0			87,737			87,737
Effect of derivative financial instruments, net of $14,601 of taxes		0		0			0		0			24,732			24,732			24,732

Total comprehensive income																	$	112,469

Balance — September 30, 2010	$	45	$	811,626		$	269,419	$	0		$	79,142		$	1,160,232

See notes to unaudited condensed consolidated financial statements.

BILL BARRETT CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Nine Months Ended September 30,
	2010			2009
	(in thousands)
Operating Activities:
Net Income	$	87,737		$	37,739
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		191,626			189,459
Deferred income taxes		60,350			20,871
Impairment, dry hole costs and abandonment expense		8,520			29,834
Unrealized derivative (gain) loss		(16,005	)		46,166
Stock compensation and other non-cash charges		12,201			13,075
Amortization of debt discounts and deferred financing costs		8,831			5,953
Gain on sale of properties		(999	)		(34	)
APIC pool for excess tax benefits related to share-based compensation		52			0
Change in operating assets and liabilities:
Accounts receivable		(80	)		19,845
Prepayments and other assets		(10,303	)		(1,842	)
Accounts payable, accrued and other liabilities		(9,943	)		12,913
Amounts payable to oil and gas property owners		5,446			(5,435	)
Production taxes payable		3,122			4,273

Net cash provided by operating activities		340,555			372,817
Investing Activities:
Additions to oil and gas properties, including acquisitions		(313,481	)		(372,820	)
Additions of furniture, equipment and other		(2,091	)		(3,287	)
Proceeds from sale of properties and other investing activities		2,133			2,714

Net cash used in investing activities		(313,439	)		(373,393	)
Financing Activities:
Proceeds from credit facility		20,000			100,000
Principal payments on credit facility		(25,000	)		(321,000	)
Proceeds from issuance of senior notes		0			237,930
Proceeds from sale of common stock		10,508			628
Deferred financing costs and other		(15,257	)		(6,494	)

Net cash (used in) provided by financing activities		(9,749	)		11,064

Increase in Cash and Cash Equivalents		17,367			10,488
Beginning Cash and Cash Equivalents		54,405			43,063

Ending Cash and Cash Equivalents	$	71,772		$	53,551

See notes to unaudited condensed consolidated financial statements.

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

September 30, 2010

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, 2010, the Company’s results of operations for the three and nine months ended September 30, 2010 and 2009 and cash flows for the nine months ended September 30, 2010 and 2009. Operating results for the three and nine months ended September 30, 2010 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, 2009 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 5% Convertible Senior Notes due 2028 (“Convertible Notes”) in computing dilutive earnings per share, volumes of natural gas and oil reserves used in calculating depreciation, depletion and amortization (“DD&A”), 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 and stock-based payment awards.

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. 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 12.4% and 9.9% for the three months ended September 30, 2010 and 2009, respectively, and 12.0% and 7.1% for the nine months ended September 30, 2010 and 2009, which include interest and amortization of discounts and deferred financing fees on the Company’s Convertible Notes, its 9.875% Senior Notes due 2016 (“Senior Notes”) and its credit facility. The Company capitalized interest costs of $1.1 million and $1.5 million for the three months ended September 30, 2010 and 2009, respectively, and $3.5 million and $3.4 million for the nine months ended September 30, 2010 and 2009, 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.

Unevaluated oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive and are assigned proved reserves. 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.

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

Unevaluated oil and gas properties are assessed periodically for impairment 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, 2010 and 2009, 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 DD&A, and non-cash impairments relating to the Company’s natural gas and oil producing activities, including net capitalized costs associated with properties that were held for sale as of December 31, 2009 of $5.6 million in total proved properties, which is net of accumulated DD&A and non-cash impairments (see Note 5 for further information on properties held for sale):


	As of September 30, 2010			As of December 31, 2009
	(in thousands)
Proved properties	$	436,567		$	432,286
Wells and related equipment and facilities		2,007,377			1,724,269
Support equipment and facilities		221,215			199,952
Materials and supplies		6,761			9,297

Total proved oil and gas properties		2,671,920			2,365,804
Accumulated depreciation, depletion, amortization and impairment		(1,152,182	)		(995,807	)

Total proved oil and gas properties, net	$	1,519,738		$	1,369,997

Unevaluated properties	$	159,304		$	154,837
Wells and facilities in progress		96,537			119,982

Total unevaluated oil and gas properties, excluded from amortization	$	255,841		$	274,819

Net changes in capitalized exploratory well costs for the nine months ended September 30, 2010 are reflected in the following table (in thousands):


Beginning of period	$	51,494
Additions to capitalized exploratory well costs pending the determination of proved reserves		39,832
Reclassifications of wells, facilities and equipment based on the determination of proved reserves		(58,224	)
Exploratory well costs charged to dry hole costs and abandonment expense (1)		(6,393	)

End of period	$	26,709

(1)	Excludes expired leasehold abandonment expense of $2.1 million.

The following table presents costs of exploratory wells for which drilling has been completed for a period of greater than one year and which are included in unevaluated oil and gas properties as of September 30, 2010, pending determination of whether the wells will be assigned proved reserves:


	Time Elapsed Since Drilling Completed
	1-2 Years		3-5 Years		Total
Costs of wells for which drilling has been completed (in thousands)	$	1,202	$	21,516	$	22,718
Number of wells for which drilling has been completed		15		47		62

As of September 30, 2010, exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling were $22.7 million, of which $8.6 million was related to 36 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.

In addition to wells in the Powder River Basin, the Company has four exploratory wells for a total of $14.1 million in exploratory well costs that have been capitalized for greater than one year. Three wells are located in the Paradox Basin and one well in the Big Horn Basin. The exploratory well costs are suspended pending the completion of an economic evaluation including, but not limited to, results of additional appraisal drilling, facilities, infrastructure, well test analysis, additional geological and geophysical data and approval of a development plan.

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

Management believes these projects with suspended exploratory drilling costs have the potential for sufficient quantities of hydrocarbons to justify their development and is actively pursuing efforts to assess whether reserves can be attributed to their respective areas. If additional information becomes available that raises substantial doubt regarding the economic or operational viability of any of these projects, the associated costs will be expensed.

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 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, 2010 and 2009, the Company did not recognize any non-cash impairment charges.

The provision for 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.

New Accounting Pronouncements. In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-06, Improving Disclosures about Fair Value Measurements, which amends Accounting Standards Codification 820, Fair Value Measurements and Disclosures. The intent of this update is to improve disclosure requirements related to fair value measurements and disclosures. New disclosures are required regarding transfers in and out of Levels 1 and 2 and activity within Level 3 fair value measurements, as well as clarification of existing disclosures regarding the level of disaggregation of derivative contracts and disclosures about fair value measurement inputs and valuation techniques. With the exception of disclosures regarding purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements, the new disclosures and clarifications of existing disclosures were effective as of January 1, 2010, and all new disclosure requirements have been incorporated. The disclosures regarding the roll forward of activity in Level 3 fair value measurements are effective for the Company beginning January 1, 2011. The adoption of these disclosure requirements is not expected to 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 per share of common stock is calculated by dividing net income attributable to common stock 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, 2010 and 2009. The dilutive earnings per share excludes the anti-dilutive effect of 160,214 and 102,935 shares of stock options and nonvested performance-based equity shares of common stock for the three months ended September 30, 2010 and 2009, respectively, and 222,747 and 249,532 shares of stock options and nonvested equity shares of common stock for the nine months ended September 30, 2010 and 2009, respectively.

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,
	2010		2009		2010		2009
Net income	$	24,562	$	718	$	87,737	$	37,739
Adjustments to net income for dilution		0		0		0		0

Net income adjusted for the effect of dilution	$	24,562	$	718	$	87,737	$	37,739

Basic weighted-average common shares outstanding in period		45,206		44,758		45,067		44,703
Add dilutive effects of stock options and nonvested equity shares of common stock		585		351		528		196

Diluted weighted-average common shares outstanding in period		45,791		45,109		45,595		44,899

Basic income per common share	$	0.54	$	0.02	$	1.95	$	0.84

Diluted income per common share	$	0.54	$	0.02	$	1.92	$	0.84

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

4. Supplemental Disclosures of Cash Flow Information

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


	Nine Months Ended September 30,
	2010			2009
Cash paid for interest, net of amount capitalized	$	32,009		$	15,310
Cash paid for income taxes, net of refunds received		2,696			4,454
Supplemental disclosures of non-cash investing and financing activities:
Current liabilities that are reflected in investing activities		47,412			35,359
Current liabilities that are reflected in financing activities		0			206
Net increase (decrease) in asset retirement obligations		311			(493	)
Treasury stock acquired from employee stock option exercises		70			2,047
Retirement of treasury stock		(3,649	)		(2,047	)

5. Dispositions and Property Held for Sale

At December 31, 2009, the Company had properties held for sale in its North Hill Creek field located in the Uinta Basin. In March 2010, the Company completed the sale of these properties. The Company received $3.1 million in cash proceeds and recognized a $0.9 million pre-tax loss, which is included in other operating revenues in the Unaudited Condensed Consolidated Statements of Operations for the nine months ended September 30, 2010.

6. Long-Term Debt

The Company’s outstanding debt is summarized below (in thousands):


		As of September 30, 2010							As of December 31, 2009
	Maturity Date	Principal		Unamortized Discount			Carrying Amount		Principal		Unamortized Discount			Carrying Amount
Credit Facility (1)	April 1, 2014	$	0	$	0		$	0	$	5,000	$	0		$	5,000
Senior Notes (2)	July 15, 2016	$	250,000	$	(10,566	)	$	239,434	$	250,000	$	(11,522	)	$	238,478
Convertible Notes (3)	March 15, 2028 (4)	$	172,500	$	(9,412	)	$	163,088	$	172,500	$	(13,728	)	$	158,772

(1)	The recorded value of the credit facility approximates its fair value due to its floating rate structure.

(2)	The aggregate estimated fair value of the Senior Notes was approximately $273.1 million as of September 30, 2010 based on quoted market trades of these instruments.

(3)

The aggregate fair value of the Convertible Notes was approximately $175.5 million as of September 30, 2010. Because there is no active, public market for the Convertible Notes, the fair value was based on market-based parameters of the various components of the Convertible Notes and over-the-counter trades.

(4)	The Company currently expects to call the Convertible Notes to be redeemed in 2012 or that the holders will put the Convertible Notes to the Company.

Revolving Credit Facility

On March 16, 2010, the Company amended its credit facility (the “Amended Credit Facility”) and extended the maturity date to April 1, 2014. 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 2.0% to 3.0% or an alternate base rate (“ABR”), based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus 1.0%, plus applicable margins ranging from 1.0% to 2.0%. The borrowing base is required to be redetermined twice per year. On September 24, 2010, the borrowing base was reaffirmed at $800.0 million with commitments from 19 lenders of $700.0 million, based on June 30, 2010 reserves and hedge position. The Company pays annual commitment fees of 0.5% 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 currently is in compliance with all financial covenants and has complied with all financial covenants for all prior periods.

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

As of September 30, 2010, the Company did not have a balance outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit was issued under the Amended Credit Facility, effective May 4, 2010, which reduced the borrowing capacity of the Amended Credit Facility by $26.0 million to $674.0 million.

5% Convertible Senior Notes due 2028

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, including the Senior Notes. Interest is payable semi-annually in arrears on March 15 and September 15 of each year. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility.

9.875% Senior Notes Due 2016

The Senior Notes, which were issued on July 8, 2009, 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. Interest is payable in arrears semi-annually on January 15 and July 15 beginning January 15, 2010. The Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility and the Convertible Notes. 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 currently in compliance with all financial covenants and has complied with all financial covenants for all prior periods.

The following table summarizes the cash portion of interest expense related to the Amended Credit Facility, Convertible Notes and Senior Notes along with the non-cash portion resulting from the amortization of the debt discount and transaction costs through interest expense (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Amended Credit Facility (1)
Cash interest	$	1,002	$	807	$	2,424	$	4,423
Non-cash interest	$	779	$	223	$	1,962	$	663
Senior Notes (2)
Cash interest	$	6,172	$	5,623	$	18,516	$	5,623
Non-cash interest	$	593	$	489	$	1,698	$	489
Convertible Notes (3)
Cash interest	$	2,156	$	2,156	$	6,469	$	6,469
Non-cash interest	$	1,795	$	1,666	$	5,170	$	4,795

(1)	Cash interest includes amounts related to interest and commitment fees paid on the line of credit and participation and fronting fees paid on the letter of credit.

(2)	The stated interest rate for the Senior Notes is 9.875% per annum with an effective interest rate of 11.3% per annum.

(3)

The stated interest rate for the Convertible Notes is 5% per annum with an effective interest rate of 9.7% per annum. The effective interest rate of the Convertible Notes includes amortization of the debt discount, which represents the fair value of the equity conversion feature at the time of issue.

7. Asset Retirement Obligations

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The associated liability is classified in current and long-term liabilities in the Unaudited Condensed Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the Unaudited Condensed Consolidated Statement of Operations.

A reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2010 is as follows (in thousands):


Beginning of period	$	49,067
Liabilities incurred		2,922
Liabilities settled		(2,768	)
Accretion expense		2,600
Revisions to estimate		0

End of period	$	51,821
Less: current asset retirement obligations		635

Long-term asset retirement obligations	$	51,186

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

8. Fair Value Measurements

Assets and Liabilities Measured on a Recurring Basis

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 other financial and non-financial assets and liabilities that are measured on a recurring basis are measured and reported at fair value.

The following tables sets forth by level within the fair value hierarchy the Company's financial assets and financial liabilities as of September 30, 2010 and December 31, 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.


As of September 30, 2010	Level 1		Level 2			Level 3		Total
	(in thousands)
Assets
Deferred Compensation Plan	$	123	$	0		$	0	$	123
Commodity Derivatives	$	0	$	112,061		$	0	$	112,061
Liabilities
Commodity Derivatives	$	0	$	(5,251	)	$	0	$	(5,251	)

As of December 31, 2009	Level 1		Level 2			Level 3		Total
	(in thousands)
Assets
Commodity Derivatives	$	0	$	75,642		$	0	$	75,642
Liabilities
Commodity Derivatives	$	0	$	(24,158	)	$	0	$	(24,158	)

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.

Level 1 Fair Value Measurements—The Company maintains a non-qualified deferred compensation plan (as discussed in more detail in Note 13) which allows certain management employees to defer receipt of a portion of their compensation. The Company maintains assets for the deferred compensation plan in a rabbi trust. The assets of the rabbi trust are invested in publicly traded mutual funds and are recorded in other current and other long-term assets on the Unaudited Condensed Consolidated Balance Sheets. These financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs.

Level 2 Fair Value Measurements—The fair value of the natural gas and crude oil forwards and options are estimated using a combined income and market valuation methodology with a mid-market pricing convention based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. The Company did not make any adjustments to the obtained curves. The pricing services publish observable market information from multiple brokers and exchanges. No proprietary models are used by the pricing services for the inputs. The Company utilized the counterparties’ valuations to assess the reasonableness of the Company’s valuations.

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

Level 3 Fair Value Measurements—As of September 30, 2010, and for the nine months ended September 30, 2010, the Company did not have assets or liabilities measured under a Level 3 fair value hierarchy.

Assets and Liabilities Measured on a Non-recurring Basis

The Company utilizes fair value on a non-recurring basis to perform impairment tests as required on our property and equipment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3. Additionally, the Company uses fair value to determine the inception value of its asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition and would generally be classified within Level 3.

9. Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues by reducing its exposure to commodity price fluctuations. The Company has entered into financial commodity swap and collar contracts to fix the floor and ceiling prices related to the sale of a portion of the Company’s production. The Company does not enter into derivative instruments for speculative or trading purposes.

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 or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil and gas production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sale exception as mentioned above, are recorded at fair market value and included in the Unaudited Condensed Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative instruments in the Unaudited Condensed Consolidated Balance Sheets as of September 30, 2010:


	Derivative Assets			Derivative Liabilities
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
	(in thousands)
Derivatives Designated as Cash Flow Hedges

Current

Commodity Contracts	Derivative Assets	$	112,474	Derivative Assets (2)	$	46
Commodity Contracts	Derivative and Other Current Liabilities (1)(3)		95	Derivative and Other Current Liabilities (3)		120
Long Term
Commodity Contracts	Derivative Assets		12,220	Derivative Asset (2)		0
Commodity Contracts	Derivatives and Other Noncurrent Liabilities (1)(4)		2,395	Derivatives and Other Noncurrent Liabilities (4)		17

Total derivatives designated as hedging instruments		$	127,184		$	183

Derivatives Not Designated as Cash Flow Hedges

Current
Commodity Contracts	Derivative Assets	$	656	Derivative Assets (2)	$	13,220
Long Term
Commodity Contracts	Derivative Assets		17	Derivative Assets (2)		40
Commodity Contracts	Derivative and Other Noncurrent Liabilities (1)(4)		0	Derivatives and Other Noncurrent Liabilities (4)		7,604

Total derivates not designated as hedging instruments		$	673		$	20,864

Total Derivatives		$	127,857		$	21,047

(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.

(3)	This line item on the Unaudited Condensed Consolidated Balance Sheets also includes $0.2 million of other current liabilities.

(4)	This line item on the Unaudited Condensed Consolidated Balance Sheets also includes $0.5 million of other noncurrent liabilities.

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

For derivative instruments that qualify and are designated as cash flow hedges, changes in fair value, to the extent the hedges are effective, are recognized in accumulated other comprehensive income (“AOCI”) until the forecasted transaction occurs. The Company will reclassify the appropriate cash flow hedge amounts from AOCI to oil and gas production revenues in the Unaudited Condensed Consolidated Statements of Operations as the hedged production quantity is sold. Based on projected market prices as of September 30, 2010, the amount to be reclassified from AOCI to net income in the next 12 months would be an after-tax net gain of approximately $70.0 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 loss in the Unaudited Condensed Consolidated Statements of Operations. 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, 2010 and the Unaudited Condensed Consolidated Statement of Operations for the three months ended September 30, 2010:


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 Gain (Loss) on Ineffective Hedges	Amount of Gain (Loss) Recognized in Income on Ineffective Hedges (before tax)
	(in thousands)
Commodity Contracts	$	3,352	Oil and Gas Production	$	51,841	Commodity Derivative Loss	$	(781	)

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, 2010 and the Unaudited Condensed Consolidated Statement of Operations for the nine months ended September 30, 2010:


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 Gain (Loss) on Ineffective Hedges	Amount of Gain (Loss) Recognized in Income on Ineffective Hedges (before tax)
	(in thousands)
Commodity Contracts	$	24,732	Oil and Gas Production	$	122,739	Commodity Derivative Loss	$	(1,047	)

During the derivative’s term, if 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 and losses, based on the effective portion of the derivative at that date, recorded in AOCI will remain in AOCI 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, and all subsequent mark-to-market gains and losses are recorded in earnings and all accumulated gains or losses recorded in AOCI related to the hedging instrument are also reclassified to earnings.

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

Some of the Company’s commodity derivatives instruments do not qualify or are not designated as cash flow hedges but are, to a degree, an economic offset to the Company’s commodity price exposure. If a commodity derivative instrument does not qualify or is not designated as a cash flow hedge, the change in the fair value of the derivative is recognized in commodity derivative 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 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 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 is an appropriate part of a 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 loss in the Unaudited Condensed Consolidated Statements of Operations. The Company has also entered into swap contracts to hedge the amount received related to natural gas liquids (“NGL”) resulting from the processing of its natural gas. The NGL hedges were not designated as cash flow hedges, and the changes in fair value of these derivative instruments was recorded in earnings.

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, 2010:


Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives for the Three Months Ended September 30, 2010			Amount of Gain (Loss) Recognized in Income on Derivatives for the Nine Months Ended September 30, 2010
		(in thousands)
Commodity Contracts	Commodity Derivative Loss	$	(4,153	)	$	(1,875	)

As of September 30, 2010, the Company had financial instruments in place to hedge the following volumes for the periods indicated:


	October – December 2010		For the year 2011		For the year 2012
Oil (Bbls)		184,000		146,000		0
Natural Gas (MMbtu)		13,481,500		43,777,500		915,000
Natural Gas Basis (MMbtu)		2,005,000		7,300,000		7,320,000
Natural Gas Liquids (Gallons)		22,550,000		14,475,000		0

The Company was a party to various swap and collar contracts for natural gas and NGL, including basis only swaps that settled during the three and nine months ended September 30, 2010 and 2009. As a result, the Company recognized a net increase in natural gas production revenues related to these contracts of $44.6 million and $101.4 million in the three and nine months ended September 30, 2010, respectively, and an increase of revenues of $68.6 million and $225.9 million related to these contracts in the three and nine months ended September 30, 2009, respectively. The Company was also a party to various swap and collar contracts for oil, recognizing an increase to oil production revenues related to these contracts of $1.3 million and $2.4 million in the three and nine months ended September 30, 2010, respectively, and an increase of revenues of $1.2 million and $6.3 million related to these contracts in the three and nine months ended September 30, 2009, respectively.

The table below summarizes the realized and unrealized gains and losses the Company recognized in the Unaudited Condensed Consolidated Statements of Operations related to its commodity derivative instruments for the periods indicated (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Realized gain on derivatives designated as cash flow hedges (1)	$	51,841		$	71,210		$	122,739		$	234,664

Realized loss on derivatives not designated as cash flow hedges (2)	$	(5,941	)	$	(1,423	)	$	(18,927	)	$	(2,446	)
Unrealized ineffectiveness gain (loss) recognized on derivatives designated as cash flow hedges (2)		(781	)		741			(1,047	)		(5,721	)
Unrealized gain (loss) on derivatives not designated as cash flow hedges (2)		1,788			(13,011	)		17,052			(40,445	)

Total commodity derivative loss	$	(4,934	)	$	(13,693	)	$	(2,922	)	$	(48,612	)

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

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

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

Derivative financial instruments that hedge the price of oil and gas 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 12 different counterparties. 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 creditworthiness 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. The Company’s derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”) or other contracts. Typical terms for these contracts 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 to the defaulting counterparty or its affiliated lender under the Amended Credit Facility or other general obligations against monies owed for derivative contracts.

10. Income Taxes

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return in accordance with the FASB’s rules on income taxes. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on technical merits. During the nine months ended September 30, 2010, 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, 2010, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense related to unrecognized tax benefits recognized during the three or nine months ended September 30, 2010.

Income tax expense for the three and nine months ended September 30, 2010 and 2009 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 the effect of 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 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, 2010, all treasury stock held by the Company was retired.

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

12. Accumulated Other Comprehensive Income

The components of AOCI and related tax effects for the nine months ended September 30, 2010 were as follows:


	Gross			Tax Effect			Net of Tax
	(in thousands)
Accumulated other comprehensive income—December 31, 2009	$	87,280		$	(32,870	)	$	54,410
Unrealized change in fair value of cash flow hedges		162,072			(60,620	)		101,452
Reclassification adjustment for realized gains on hedges included in net income		(122,739	)		46,019			(76,720	)

Accumulated other comprehensive income—September 30, 2010	$	126,613		$	(47,471	)	$	79,142

13. Equity Incentive Compensation Plans and Other Employee Benefits

The Company maintains various stock-based compensation plans and other employee benefits as discussed below. Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period).

Performance Share Program. On May 9, 2007, the Compensation Committee of the Board of Directors of the Company approved a performance share program (the “2007 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 2007 Program and during each subsequent year of the 2007 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 the 2007 Program.

As new goals are established each year for the performance-based awards, 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.

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 were available for vesting if all stretch goals for 2009 were met. Based upon the Company’s performance in 2009, 50% of the total performance shares (including the supplemental grant) vested in February 2010.

In February 2010, the Compensation Committee approved a new performance share program (the “2010 Program”) pursuant to the Company’s 2008 Stock Incentive Plan (the “2008 Incentive Plan”). A total of 325,000 shares under the 2008 Incentive Plan were set aside for the 2010 Program. The 2010 Program has the same four-year term and vesting provisions as the 2007 Program. For the year ending December 31, 2010, the performance goals consist of finding and development costs per Mcfe (weighted at 37.5%), combined lease operating expenses and general and administrative expenses (weighted at 25%) and production growth (weighted at 37.5%). Based upon the number of shares expected to vest through February 2011, the Company did not recognize any non-cash stock-based compensation cost associated with these shares for the three and nine months ended September 30, 2010.

In 2010, the Company also issued nonvested equity awards that are subject to a market performance-based vesting condition, which is based on the Company’s total stockholder return (“TSR”) ranking relative to a defined peer group’s individual TSR. The aggregate grant date fair value of the market-based awards was determined using the Monte Carlo simulation method. The fair value of the market-based awards is amortized ratably over the four year requisite service period. All compensation expense related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

Stock Options and Nonvested Equity Shares. The following tables present the equity awards granted pursuant to the Company’s various stock compensation plans:


	Three Months Ended September 30, 2010				Nine Months Ended September 30, 2010
	Number of options		Weighted Average Price Per Share		Number of Options		Weighted Average Price Per Share
Options to purchase shares of common stock		56,000	$	34.44		588,306	$	31.32


	Three Months Ended September 30, 2010				Nine Months Ended September 30, 2010
	Number of shares		Weighted Average Grant Date Fair Value		Number of shares		Weighted Average Grant Date Fair Value
Nonvested equity shares		30,550	$	34.64		249,236	$	31.09
Nonvested performance-based equity shares		16,000	$	34.82		242,465	$	31.20
Market performance-based equity shares		4,000	$	32.99		60,611	$	29.31

Total shares granted		50,500				552,312

The following table presents the non-cash stock-based compensation related to equity awards for the three and nine months ended September 30, 2010 and 2009 (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Common stock options	$	1,795	$	1,889	$	5,970	$	5,660
Nonvested equity shares		1,697		1,768		5,087		5,171
Nonvested performance-based equity shares		0		717		182		1,518
Market performance-based equity shares		79		0		230		0

Total non-cash stock-based compensation	$	3,571	$	4,374	$	11,469	$	12,349

Unrecognized compensation cost as of September 30, 2010 was $28.0 million 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 2.4 years. This amount includes $1.2 million related to the market-based nonvested equity shares that is expected to be recognized ratably through February 2014.

Other Employee Benefits-401(k) Savings Plan. The Company has an employee-directed 401(k) savings plan (the “401(k) Plan”) for all eligible employees over the age of 21. Employees become eligible the quarter following the beginning of their employment. Under the 401(k) Plan, employees may make voluntary contributions based upon a percentage of their pretax income.

The Company matches 100% of each employee’s contribution, up to 6% of the employee’s pretax income, with 50% of the match made with the Company’s common stock. The Company’s cash and common stock contributions and shares of common stock are fully vested upon the date of match. The Company made matching cash and common stock contributions of $0.3 million for the three months ended September 30, 2010 and 2009. The Company made matching cash and common stock contributions of $1.3 million for the nine months ended September 30, 2010 and 2009.

Director Fees. The Company’s non-employee, or 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 fees. The following table summarizes common stock issued as payment for directors’ fees and the amount of non-cash stock-based compensation cost recognized associated with the issuance of those shares:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Director fees (shares)		2,575		1,606		7,419		7,253
Stock-based compensation (in thousands)	$	93	$	53	$	242	$	193

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

Deferred Compensation Plan. In February 2010, the Compensation Committee approved a non-qualified deferred compensation plan for certain employees and officers whose eligibility to participate in the plan was determined by the Compensation Committee of the Company’s Board of Directors. The plan became effective on April 3, 2010. The Company makes cash matching contributions on behalf of eligible employees up to 6% of the employee’s cash compensation once the contribution limits are reached on the Company’s 401(k) Plan. All amounts deferred and matched under the plan vest immediately.

Participants earn a return on their deferred compensation based on investment earnings of participant-selected mutual funds. Participants’ deferred compensation amounts are not directly invested in these investment vehicles; however, the Company tracks the performance of each participant’s investment selections and adjusts the deferred compensation liability accordingly. Changes in the market value of the participants’ investment selections are recorded as an adjustment to deferred compensation liabilities, with an offset to compensation expense included within general and administrative expenses in the Unaudited Condensed Consolidated Statements of Operations. Deferred compensation, including accumulated earnings on the participant-directed investment selections, is distributable in cash at participant-specified dates or upon retirement, death, disability, change in control or termination of employment.

The table below summarizes the activity in the plan during the nine months ended September 30, 2010 and the Company’s ending deferred compensation liability as of September 30, 2010 (in thousands):


Beginning deferred compensation liability balance	$	0
Employee contributions		74
Company matching contributions		47
Participant earnings		2

Ending deferred compensation liability balance	$	123

Amount to be paid within one year	$	18
Remaining balance to be paid beyond one year	$	105

The Company is not obligated to fund the liability. It has, however, established a rabbi trust to offset the deferred compensation liability and protect the interest of the plan participants. The trust assets are invested in publicly-traded mutual funds. The investments in the rabbi trust seek to offset the change in the value of the related liability. As a result, there is no expected impact on earnings or earnings per share from the changes in market value of the investment assets because the changes in market value of the trust assets are offset by changes in the value of the deferred compensation plan liability. The gains and losses from changes in fair value of the investments are included in interest and other income in the Unaudited Condensed Consolidated Statements of Operations.

The following table represents the Company’s activity in the investment assets held in the rabbi trust during the nine months ended September 30, 2010:


Beginning investment balance	$	0
Investment purchases		121
Earnings		2

Ending investment balance	$	123

14. Guarantor Subsidiaries

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 Unaudited Condensed Consolidated Financial Statements. Investments in the subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Company and the Guarantor Subsidiaries are reflected in the Intercompany Eliminations column.

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

Condensed Consolidating Balance Sheets (Unaudited)


	September 30, 2010 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Assets:
Current assets	$	248,601		$	521		$	0	$	249,122
Property and equipment, net		1,704,829			84,970			0		1,789,799
Intercompany receivable (payable)		64,648			(64,648	)		0		0
Investment in subsidiaries		(6,251	)		0			6,251		0
Noncurrent assets		31,212			0			0		31,212

Total assets	$	2,043,039		$	20,843		$	6,251	$	2,070,133

Liabilities and Stockholders’ Equity:
Current liabilities	$	170,425		$	786		$	0	$	171,211
Long-term debt		402,522			0			0		402,522
Deferred income taxes		253,625			25,606			0		279,231
Other noncurrent liabilities		56,235			702			0		56,937
Stockholders’ equity		1,160,232			(6,251	)		6,251		1,160,232

Total liabilities and stockholders’ equity	$	2,043,039		$	20,843		$	6,251	$	2,070,133


	December 31, 2009 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Assets:
Current assets	$	179,718		$	321		$	0	$	180,039
Property and equipment, net		1,570,183			89,077			0		1,659,260
Intercompany receivable (payable)		67,202			(67,202	)		0		0
Investment in subsidiaries		(4,673	)		0			4,673		0
Noncurrent assets		26,824			0			0		26,824

Total assets	$	1,839,254		$	22,196		$	4,673	$	1,866,123

Liabilities and Stockholders’ Equity:
Current liabilities	$	152,655		$	637		$	0	$	153,292
Long-term debt		402,250			0			0		402,250
Deferred income taxes		192,685			25,622			0		218,307
Other noncurrent liabilities		63,109			610			0		63,719
Stockholders’ equity		1,028,555			(4,673	)		4,673		1,028,555

Total liabilities and stockholders’ equity	$	1,839,254		$	22,196		$	4,673	$	1,866,123

Condensed Consolidating Statements of Income (Unaudited)


	Three Months Ended September 30, 2010 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Operating and other revenues	$	178,200		$	2,431		$	0	$	180,631
Operating costs and expenses		112,751			3,430			0		116,181
General and administrative		13,985			0			0		13,985
Interest and other income (expense)		(10,939	)		0			0		(10,939	)

Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		40,525			(999	)		0		39,526
Income tax expense		14,964			0			0		14,964
Equity in earnings (loss) of subsidiaries		(999	)		0			999		0

Net income (loss)	$	24,562		$	(999	)	$	999	$	24,562

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010


	Nine Months Ended September 30, 2010 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Operating and other revenues	$	525,616		$	9,450		$	0	$	535,066
Operating costs and expenses		310,219			11,028			0		321,247
General and administrative		41,729			0			0		41,729
Interest and other income (expense)		(32,136	)		0			0		(32,136	)

Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		141,532			(1,578	)		0		139,954
Income tax expense		52,217			0			0		52,217
Equity in earnings (loss) of subsidiaries		(1,578	)		0			1,578		0

Net income (loss)	$	87,737		$	(1,578	)	$	1,578	$	87,737


	Three Months Ended September 30, 2009 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Operating and other revenues	$	146,932		$	1,828		$	0	$	148,760
Operating costs and expenses		118,671			3,616			0		122,287
General and administrative		14,634			0			0		14,634
Interest and other income (expense)		(9,702	)		0			0		(9,702	)

Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		3,925			(1,788	)		0		2,137
Income tax expense		1,419			0			0		1,419
Equity in earnings (loss) of subsidiaries		(1,788	)		0			1,788		0

Net income (loss)	$	718		$	(1,788	)	$	1,788	$	718


	Nine Months Ended September 30, 2009 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Operating and other revenues	$	427,279		$	5,111		$	0	$	432,390
Operating costs and expenses		299,026			9,222			0		308,248
General and administrative		41,274			0			0		41,274
Interest and other income (expense)		(19,804	)		0			0		(19,804	)

Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		67,175			(4,111	)		0		63,064
Income tax expense		25,325			0			0		25,325
Equity in earnings (loss) of subsidiaries		(4,111	)		0			4,111		0

Net income (loss)	$	37,739		$	(4,111	)	$	4,111	$	37,739

BILL BARRETT CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

September 30, 2010

Condensed Consolidating Statements of Cash Flows (Unaudited)


	Nine Months Ended September 30, 2010 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Cash flows from operating activities	$	336,928		$	3,627		$	0	$	340,555
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions		(312,272	)		(1,209	)		0		(313,481	)
Additions to furniture, fixtures and other		(1,803	)		(288	)		0		(2,091	)
Proceeds from sale of properties and other investing activities		2,133			0			0		2,133
Cash flows from financing activities:
Proceeds from debt		20,000			0			0		20,000
Principal payments on debt		(25,000	)		0			0		(25,000	)
Intercompany transfers		2,130			(2,130	)		0		0
Other financing activities		(4,749	)		0			0		(4,749	)

Change in cash and cash equivalents		17,367			0			0		17,367
Beginning cash and cash equivalents		54,405			0			0		54,405

Ending cash and cash equivalents	$	71,772		$	0		$	0	$	71,772


	Nine Months Ended September 30, 2009 (in thousands)
	Parent Issuer			Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
Cash flows from operating activities	$	371,707		$	1,110		$	0	$	372,817
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions		(371,589	)		(1,231	)		0		(372,820	)
Additions to furniture, fixtures and other		(2,130	)		(1,157	)		0		(3,287	)
Proceeds from sale of properties and other investing activities		2,714			0			0		2,714
Cash flows from financing activities:
Proceeds from debt		337,930			0			0		337,930
Principal payments on debt		(321,000	)		0			0		(321,000	)
Intercompany transfers		(1,278	)		1,278			0		0
Other financing activities		(5,866	)		0			0		(5,866	)

Change in cash and cash equivalents		10,488			0			0		10,488
Beginning cash and cash equivalents		43,063			0			0		43,063

Ending cash and cash equivalents	$	53,551		$	0		$	0	$	53,551

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, the following risks and uncertainties:

•

volatility of market prices received for natural gas, natural gas liquids (“NGL”) and oil;

•

regulatory approvals;

•

legislative or regulatory changes;

•

economic and competitive conditions;

•

debt and equity market conditions;

•

derivative activities;

•

exploration risks such as drilling unsuccessful wells;

•

future processing volumes and pipeline throughput;

•

reductions in the borrowing base under the Amended Credit Facility;

•

the potential for production decline rates from our wells to be greater than we expect;

•

changes in estimates of proved reserves;

•

potential failure to achieve expected production from existing and future exploration or development projects;

•

declines in the values of our natural gas and oil properties resulting in impairments;

•

capital expenditures and other contractual obligations;

•

liabilities resulting from litigation concerning alleged damages related to environmental issues, personal injury, royalties, marketing, title to properties, validity of leases, or other matters that may not be covered by an effective indemnity or insurance;

•

higher than expected costs and expenses including production, drilling and well equipment costs;

•

occurrence of property acquisitions or divestitures;

•

ability to obtain adequate pipeline transportation capacity for our production;

•

changes in tax rates; 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, 2009 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. Readers should not place undue reliance on these forward-looking statements, which reflect management’s views only as of the date hereof. Other than as required under the securities laws, we do not undertake any obligation to publicly correct or update any forward-looking statements whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise.

Overview

Bill Barrett Corporation (“we,” “our” or “us”) explores for and develops oil and natural gas in the Rocky Mountain region of the United States. We intend to increase stockholder value by profitably growing reserves and production, primarily through drilling our development properties. We seek high quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of natural gas and oil production at market prices and the settlement of commodity hedges.

We were formed in January 2002 and are incorporated in the State of Delaware. 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.

Results of Operations

The financial information for the three and nine months ended September 30, 2010 and 2009 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, 2010 Compared to Nine Months Ended September 30, 2009


	Nine Months Ended September 30,						Increase (Decrease)
	2010			2009			Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil and gas production	$	534,956		$	479,455		$	55,501			12	%
Commodity derivative loss		(2,922	)		(48,612	)		45,690			94	%
Other		3,032			1,547			1,485			96	%
Operating Expenses
Lease operating expense		39,023			34,921			4,102			12	%
Gathering, transportation and processing expense		51,758			40,012			11,746			29	%
Production tax expense		25,524			11,850			13,674			115	%
Exploration expense		4,796			2,172			2,624			121	%
Impairment, dry hole costs and abandonment expense		8,520			29,834			(21,314	)		(71	)%
Depreciation, depletion and amortization		191,626			189,459			2,167			1	%
General and administrative expense (1)		30,560			29,193			1,367			5	%
Non-cash stock-based compensation expense (1)		11,169			12,081			(912	)		(8	)%

Total operating expenses	$	362,976		$	349,522		$	13,454			4	%
Production Data:
Natural gas (MMcf)		67,505			63,859			3,646			6	%
Oil (MBbls)		795			517			278			54	%
Combined volumes (MMcfe)		72,275			66,961			5,314			8	%
Daily combined volumes (MMcfe/d)		265			245			20			8	%
Average Prices (2):
Natural gas (per Mcf)	$	6.83		$	7.02		$	(0.19	)		(3	)%
Oil (per Bbl)		69.49			55.76			13.73			25	%
Combined (per Mcfe)		7.14			7.12			0.02			0	%
Average Costs (per Mcfe):
Lease operating expense	$	0.54		$	0.52		$	0.02			4	%
Gathering, transportation and processing expense		0.72			0.60			0.12			20	%
Production tax expense		0.35			0.18			0.17			94	%
Depreciation, depletion and amortization		2.65			2.83			(0.18	)		(6	)%
General and administrative expense (3)		0.42			0.44			(0.02	)		(5	)%

(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 $41.7 million and $41.3 million for the nine months ended September 30, 2010 and 2009, 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 include the impact of all of our realized financial hedges in the form of commodity hedging transactions. Our average realized price calculation includes all cash settlements for commodity derivatives, whether or not they qualify for hedge accounting. Our realized hedging transactions increased natural gas production revenues by $101.4 million and $225.9 million for the nine months ended September 30, 2010 and 2009, respectively, and increased oil production revenues by $2.4 million and $6.3 million for the nine months ended September 30, 2010 and 2009, respectively. Before the effects of hedging, the average prices we received for natural gas and oil were as follows:


	Nine Months Ended September 30,
	2010		2009
Natural gas (per Mcf)	$	5.32	$	3.48
Oil (per Bbl)	$	66.43	$	43.59

(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 $0.58 and $0.62 for the nine months ended September 30, 2010 and 2009, respectively.

Production Revenues and Volumes. Production revenues increased to $535.0 million for the nine months ended September 30, 2010 from $479.5 million for the nine months ended September 30, 2009 due to an 8% increase in production and a 3% increase in natural gas and oil prices after the effects of realized cash flow hedges (excluding basis only swaps) on a per Mcfe basis. The net increase in production added approximately $39.3 million of production revenues, while the net increase in prices added approximately $16.2 million of production revenues. During the nine months ended September 30, 2010, we realized an increase in production revenues of approximately $46.3 million, or $0.64 per Mcfe, as compared to an increase of $16.1 million, or $0.24 per Mcfe, for the nine months ended September 30, 2009 related to NGL values for a portion of our gas production in the Piceance Basin. In the future there is no assurance that the amount received related to NGL resulting from the processing of natural gas will exceed the additional cost of processing or the price of natural gas.

Total production volumes for the nine months ended September 30, 2010 of 72.3 Bcfe increased from 67.0 Bcfe for the nine months ended September 30, 2009 due to increased production in the Piceance and Powder River Basins. The increase in production in these basins was partially offset by a decrease in production in the Uinta and Wind River Basins. Additional information concerning production is in the following table:


	Nine Months Ended September 30, 2010						Nine Months Ended September 30, 2009						% 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		427		32,810		35,372		313		24,814		26,692	36%	32%	33%
Uinta Basin		327		19,234		21,196		162		23,776		24,748	102%	(19)%	(14)%
Wind River Basin		16		5,220		5,316		22		6,328		6,460	(27)%	(18)%	(18)%
Powder River Basin		0		10,098		10,098		0		8,682		8,682	0%	16%	16%
Other		25		143		293		20		259		379	25%	(45)%	(23)%

Total		795		67,505		72,275		517		63,859		66,961	54%	6%	8%

The production increase in the Piceance Basin was the result of our continued development activities with initial sales from 157 new gross wells from October 1, 2009 to September 30, 2010. The production increase in the Powder River Basin was the result of our continued development activities with initial sales from 41 new gross wells from October 1, 2009 to September 30, 2010. Although we have reduced our current year development activities in the Powder River Basin, our production has benefited from prior year development programs due to the extended dewatering process of the coal bed methane wells. The production decrease in the Uinta Basin is due to natural production declines as well as a limited development program compared to prior years in our West Tavaputs field with initial sales from only 33 new gross wells from October 1, 2009 to September 30, 2010, partially offset by higher volumes from our Blacktail Ridge/Lake Canyon development. 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, 2010, approximately 74% of our natural gas volumes (excluding basis only swaps, which were equivalent to 14% of our natural gas volumes) and 48% of our oil volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $101.4 million and an increase in oil revenues of $2.4 million after settlements for all commodity derivatives, including basis only and NGL swaps. During the nine months ended September 30, 2009, approximately 75% of our natural gas volumes (excluding basis only swaps, which were equivalent to 3% of our natural gas volumes) and 52% of our oil volumes were subject to financial hedges, which resulted in an increase in natural 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. The decrease in revenues related to hedging natural gas resulted from the expiration of hedges entered into at higher prices and the inability to enter into new hedges at those prices as natural gas prices have fallen since entering into those hedges. This trend is expected to continue based on future strip prices and hedge quotes.

Commodity Derivative Loss. The “commodity derivative loss” line item on the Unaudited Condensed Consolidated Statements of Operations is comprised of ineffectiveness on cash flow hedges and realized and unrealized gains and losses on hedges that do not qualify for cash flow hedge accounting or were not designated as cash flow hedges. Ineffectiveness on cash flow hedges relates to slight differences between the contracted location and the actual delivery location. Unrealized gains and losses represent the change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting, which includes our basis only and NGL swaps. As those instruments settle, their settlement will be presented as realized gains and losses within this same line item.

The overall change in commodity derivative loss to $2.9 million for the nine months ended September 30, 2010 from a loss of $48.6 million for the nine months ended September 30, 2009 is due to an increase in unrealized gains primarily resulting from changes in the fair value of our basis only swaps, offset by realized losses primarily related to settlements of our basis only swaps.

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


	Nine Months Ended September 30,
	2010			2009
	(in thousands)
Realized loss on derivatives not designated as cash flow hedges	$	(18,927	)	$	(2,446	)
Unrealized ineffectiveness loss recognized on derivatives designated as cash flow hedges		(1,047	)		(5,721	)
Unrealized gain (loss) on derivatives not designated as cash flow hedges		17,052			(40,445	)

Total commodity derivative loss	$	(2,922	)	$	(48,612	)

Other Operating Revenues. Other operating revenues increased to $3.0 million for the nine months ended September 30, 2010 from $1.5 million for the nine months ended September 30, 2009. Other operating revenues for the nine months ended September 30, 2010 consisted of gains realized from the sale of properties of $1.0 million and gathering, compression and salt water disposal fees from third parties of $2.0 million. Other operating revenues for the nine months ended September 30, 2009 consisted only of gathering, compression and salt water disposal fees from third parties.

Lease Operating Expense. Lease operating expense increased to $0.54 per Mcfe for the nine months ended September 30, 2010 from $0.52 per Mcfe for the nine months ended September 30, 2009. The following table displays the lease operating expense by basin:


	Nine Months Ended September 30, 2010				Nine Months Ended September 30, 2009				%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		(per Mcfe)
Piceance Basin	$	11,373	$	0.32	$	10,933	$	0.41	(22)%
Uinta Basin		12,998		0.61		8,401		0.34	79%
Wind River Basin		4,264		0.80		3,897		0.60	33%
Powder River Basin		9,527		0.94		10,949		1.26	(25)%
Other		861		2.94		741		1.96	50%

Total	$	39,023	$	0.54	$	34,921	$	0.52	4%

Lease operating expense decreased in the Piceance Basin to $0.32 per Mcfe for the nine months ended September 30, 2010 from $0.41 per Mcfe for the nine months ended September 30, 2009 primarily due to decreased compression costs associated with the Bailey Compressor Station and reduced property tax expense. The increase in lease operating expense in the Uinta Basin to $0.61 per Mcfe for the nine months ended September 30, 2010 from $0.34 per Mcfe for the nine months ended September 30, 2009 was the result of $2.2 million of remediation efforts related to a condensate leak at the Dry Canyon Compressor Station (see further discussion below) as well as increased water handling, workover activity, and natural production declines resulting in higher lease operating expense on a per Mcfe basis. Additionally, higher inherent costs related to our increased oil production in the Lake Canyon and Blacktail Ridge fields contributed to higher lease operating expense in the Uinta Basin. Lease operating expense increased in the Wind River Basin to $0.80 per Mcfe for the nine months ended September 30, 2010 from $0.60 per Mcfe for the nine months ended September 30, 2009 as a result of increased workover activity and natural production declines resulting in higher lease operating expense on a per Mcfe basis. Lease operating expense decreased in the Powder River Basin to $0.94 per Mcfe for the nine months ended September 30, 2010 from $1.26 per Mcfe for the nine months ended September 30, 2009 primarily as a result of a reduction in the number of diesel fuel power generators used in the basin as these generators were replaced with electrical service from a local utility, reducing the amount of diesel fuel costs. In addition, lease operating expense per Mcfe decreased in the Powder River Basin due to increased production or first production from wells that were previously in the dewatering stage.

As noted above, in March 2010, a condensate leak was detected at the Dry Canyon Compressor Station in the Uinta Basin. The leak has been contained and remediation efforts have been ongoing since the leak occurred. Remediation of the area resulted in an additional $2.2 million in lease operating expense for the nine months ended September 30, 2010, including the cost of future estimated remediation work.

Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense increased to $0.72 per Mcfe for the nine months ended September 30, 2010 from $0.60 per Mcfe for the nine months ended September 30, 2009. The following table displays the gathering, transportation and processing expense by basin:


	Nine Months Ended September 30, 2010				Nine Months Ended September 30, 2009				%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		(per Mcfe)
Piceance Basin	$	24,890	$	0.70	$	15,288	$	0.57	23%
Uinta Basin		14,667		0.69		14,964		0.60	15%
Wind River Basin		78		0.01		39		0.01	0%
Powder River Basin		12,016		1.19		9,518		1.10	8%
Other		107		0.37		203		0.54	(31)%

Total	$	51,758	$	0.72	$	40,012	$	0.60	20%

Gathering, transportation and processing expense increased in the Piceance Basin to $0.70 per Mcfe for the nine months ended September 30, 2010 from $0.57 per Mcfe for the nine months ended September 30, 2009. The increase was primarily attributable to utilization of firm transportation on the Rockies Express Pipeline (“REX”). For the nine months ended September 30, 2010, the majority of gas we transported on REX was supplied from the Piceance Basin as compared to the majority of the supply coming from the Uinta Basin for the nine months ended September 30, 2009. Gathering, transportation and processing expense per Mcfe in the Uinta Basin increased to $0.69 per Mcfe for the nine months ended September 30, 2010 from $0.60 per Mcfe for the nine months ended September 30, 2009. This increase was a result of additional contracts to gather, process and transport our West Tavaputs gas from the Uinta Basin, which more than offset the lower REX utilization. Also contributing to the increase in both basins were higher fees associated with REX due to the completion of the final two segments of the pipeline, which gives us access to gas sales delivery points farther east. The Powder River Basin’s gathering, transportation and processing expense per Mcfe increased to $1.19 per Mcfe for the nine months ended September 30, 2010 from $1.10 per Mcfe for the nine months ended September 30, 2009 due to additional firm transportation contracts.

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 contracts are for gas production in the Piceance and Uinta 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, transportation and processing expense is $0.18 and $0.17 per Mcfe of firm transportation expense for the nine months ended September 30, 2010 and 2009, respectively, along with $0.04 and $0.05 per Mcfe of processing expense from long-term contracts for the nine months ended September 30, 2010 and 2009, respectively. The increase in firm transportation expense to $0.18 per Mcfe for the nine months ended September 30, 2010 from $0.17 per Mcfe for the nine months ended September 30, 2009 was the result of additional long-term transportation contracts executed with various pipelines for our natural gas production in the Powder River and Uinta Basins as well as higher REX fees as mentioned above.

Production Tax Expense. Total production taxes increased to $25.5 million for the nine months ended September 30, 2010 from $11.9 million for the nine months ended September 30, 2009. The increase in production taxes is primarily related to increased natural gas and oil prices. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense for the nine months ended September 30, 2010 includes a one-time reduction of $2.2 million related to amended 2004 through 2009 State of Utah annual severance tax calculations. Production tax expense for the nine months ended September 30, 2009 includes a one-time reduction of $4.8 million related to the 2004 through 2008 State of Colorado annual severance tax calculations. Because these items are nonrecurring, if the reductions associated with the Utah and Colorado severance taxes are excluded in order to provide a more consistent comparison, production taxes as a percentage of natural gas and oil sales before hedging adjustments were 6.7% for the nine months ended September 30, 2010 and 6.8% for the nine months ended September 30, 2009.

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 increased to $4.8 million for the nine months ended September 30, 2010 from $2.2 million for the nine months ended September 30, 2009. Exploration expense for the nine months ended September 30, 2010 consisted of $3.5 million for a well drilled for data gathering purposes, $0.3 million for seismic programs, $0.1 million for evaluation of non-acquired assets and $0.9 million for delay rentals and other exploration costs. 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 for evaluation of non-acquired assets and $1.0 million for delay rentals and other exploration costs.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense decreased to $8.5 million during the nine months ended September 30, 2010 from $29.8 million during the nine months ended September 30, 2009. For the nine months ended September 30, 2010, abandonment expense associated with exploratory drilling locations was $0.5 million, expired leasehold costs were $2.1 million and dry hole costs were $5.9 million. The $5.9 million in dry hole costs were associated with the partial expensing of one exploratory well in the Blacktail Ridge prospect of the Uinta Basin and the expensing of two exploratory wells in the Yellow Jacket prospect of the Paradox Basin. 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 in 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, 2010 and 2009, 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 $191.6 million for the nine months ended September 30, 2010 compared to $189.5 million for the nine months ended September 30, 2009. The increase of $2.1 million was primarily the result of an increase in production offset by a lower weighted average DD&A rate. There was an 8% increase in production on an Mcfe basis for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009, resulting in $14.5 million of additional depletion expense, which was offset by a lower DD&A rate accounting for a $12.4 million reduction in DD&A expense.

During the nine months ended September 30, 2010, the weighted average DD&A rate was $2.65 per Mcfe. For the nine months ended September 30, 2009, the weighted average DD&A rate was $2.83 per Mcfe. Under successful efforts accounting, DD&A expense is separately computed for each producing area based on proved reserves in each geologic and reservoir delineation. The capital expenditures for proved properties for each area compared to the proved reserves corresponding to each producing area determine a weighted average DD&A rate for current production. Future DD&A rates will be adjusted to reflect future capital expenditures and proved reserve changes in specific areas.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $30.6 million in the nine months ended September 30, 2010 from $29.2 million in the nine months ended September 30, 2009. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 25 for a reconciliation and explanation. This increase was primarily due to an increase in employee compensation and benefit programs for the nine months ended September 30, 2010 as well as an increase in costs associated with our efforts, and industry-wide efforts, to educate the public concerning the benefits of natural gas. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, decreased to $0.42 per Mcfe for the nine months ended September 30, 2010 from to $0.44 per Mcfe for the nine months ended September 30, 2009 due to increased production for the nine months ended September 30, 2010.

Non-cash charges for stock-based compensation were $11.2 million and $12.1 million for the nine months ended September 30, 2010 and 2009, respectively. Non-cash stock-based compensation expense for each of the nine months ended September 30, 2010 and 2009 related primarily to vesting of our stock option awards and nonvested shares of common stock issued to employees.

The components of non-cash stock-based compensation for the nine months ended September 30, 2010 and 2009 are shown in the following table:


	Nine Months Ended September 30,
	2010		2009
	(in thousands)
Stock options and nonvested equity shares of common stock	$	10,444	$	11,414
Shares issued for 401(k) plan		483		474
Shares issued for directors’ fees		242		193

Total	$	11,169	$	12,081

Interest Expense. Interest expense increased to $32.5 million for the nine months ended September 30, 2010 from $20.1 million for the nine months ended September 30, 2009. Although our weighted average outstanding debt balance decreased for the nine months ended September 30, 2010 to $403.2 million from $433.0 million for the nine months ended September 30, 2009, our effective interest rate was higher for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 primarily due to our 9.875% Senior Notes due 2016 (“Senior Notes”) issued in July 2009. Our weighted average interest rate for the nine months ended September 30, 2010, including interest and amortization of discounts and deferred financing fees on our credit facility amended March 16, 2010 (“Amended Credit Facility”), 5% Convertible Notes due 2028 (“Convertible Notes”) and Senior Notes, was 12.0% compared to 7.1% for the nine months ended September 30, 2009.

Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than nine months to be readied for their intended use. We capitalized interest costs of $3.5 million and $3.4 million for the nine months ended September 30, 2010 and 2009, respectively.

Income Tax Expense. Income tax expense totaled $52.2 million for the nine months ended September 30, 2010 compared to $25.3 million for the nine months ended September 30, 2009, resulting in effective tax rates of 37.3% and 40.2%, respectively. The increase in income tax expense is primarily the result of the variations in revenue and expense components, and the resulting increase, of pre-tax net income as discussed above. The effective tax rate will vary from period to period due to changes in the composition of income between state tax jurisdictions resulting from our activity. For both the 2010 and 2009 periods, our effective tax rate differs from the federal statutory rate primarily because we recorded stock-based compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes.

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009


	Three Months Ended September 30,						Increase (Decrease)
	2010			2009			Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating and Other Revenues
Oil and gas production	$	185,007		$	161,719		$	23,288			14	%
Commodity derivative loss		(4,934	)		(13,693	)		8,759			64	%
Other		558			734			(176	)		(24	)%
Operating Expenses
Lease operating expense		13,001			13,005			(4	)		0	%
Gathering, transportation and processing expense		17,301			16,260			1,041			6	%
Production tax expense		8,193			6,547			1,646			25	%
Exploration expense		3,841			630			3,211			510	%
Impairment, dry hole costs and abandonment expense		4,653			19,103			(14,450	)		(76	)%
Depreciation, depletion and amortization		69,192			66,742			2,450			4	%
General and administrative expense (1)		10,557			10,291			266			3	%
Non-cash stock-based compensation expense (1)		3,428			4,343			(915	)		(21	)%

Total operating expenses	$	130,166		$	136,921		$	(6,755	)		(5	)%
Production Data:
Natural gas (MMcf)		23,540			21,711			1,829			8	%
Oil (MBbls)		322			180			142			79	%
Combined volumes (MMcfe)		25,472			22,791			2,681			12	%
Daily combined volumes (MMcfe/d)		277			248			29			12	%
Average Prices (2):
Natural gas (per Mcf)	$	6.67		$	6.86		$	(0.19	)		(3	)%
Oil (per Bbl)		68.57			63.30			5.27			8	%
Combined (per Mcfe)		7.03			7.03			0.00			0	%
Average Costs (per Mcfe):
Lease operating expense	$	0.51		$	0.57		$	(0.06	)		(11	)%
Gathering, transportation and processing expense		0.68			0.71			(0.03	)		(4	)%
Production tax expense		0.32			0.29			0.03			10	%
Depreciation, depletion and amortization		2.72			2.93			(0.21	)		(7	)%
General and administrative expense (3)		0.41			0.45			(0.04	)		(9	)%

(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 $14.0 million and $14.6 million for the three months ended September 30, 2010 and 2009, 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 include the impact of all of our realized financial hedges in the form of commodity hedging transactions. Our average realized price calculation includes all cash settlements for commodity derivatives, whether or not they qualify for hedge accounting. Our realized hedging transactions increased natural gas production revenues by $44.6 million and $68.6 million for the three months ended September 30, 2010 and 2009, respectively, and increased oil production revenues by $1.3 million and $1.2 million for the three months ended September 30, 2010 and 2009, respectively. Before the effects of hedging, the average prices we received for natural gas and oil were as follows:


	Three Months Ended September 30,
	2010		2009
Natural gas (per Mcf)	$	4.77	$	3.70
Oil (per Bbl)	$	64.65	$	56.53

(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 $0.55 and $0.64 for the three months ended September 30, 2010 and 2009, respectively.

Production Revenues and Volumes. Production revenues increased to $185.0 million for the three months ended September 30, 2010 from $161.7 million for the three months ended September 30, 2009, primarily due to a 12% increase in production and a 2% increase in natural gas and oil prices after the effects of realized cash flow hedges (excluding basis only swaps) on a per Mcfe basis. The net increase in production added approximately $19.5 million of production revenues, while the net increase in prices added approximately $3.8 million of production revenues. During the three months ended September 30, 2010, we realized an increase in production revenues of approximately $16.6 million, or $0.65 per Mcfe, as compared to an increase of $8.9 million, or $0.39 per Mcfe for the three months ended September 30, 2009 related to NGL values for a portion of our gas production in the Piceance Basin. In the future there is no assurance that the amount received related to NGL resulting from the processing of natural gas will exceed the additional cost of processing or the price of natural gas.

Total production volumes for the three months ended September 30, 2010 of 25.5 Bcfe increased from 22.8 Bcfe for the three months ended September 30, 2009 primarily due to increased production in the Piceance Basin. The increase in production in this basin was partially offset by a decrease in production in the Uinta and Wind River Basins. Additional information concerning production is in the following table:


	Three Months Ended September 30, 2010						Three Months Ended September 30, 2009						% 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		164		12,119		13,103		105		8,467		9,097	56%	43%	44%
Uinta Basin		144		6,488		7,352		58		8,069		8,417	148%	(20)%	(13)%
Wind River Basin		7		1,658		1,700		11		1,829		1,895	(36)%	(9)%	(10)%
Powder River Basin		0		3,206		3,206		0		3,273		3,273	0%	(2)%	(2)%
Other		7		69		111		6		73		109	17%	(5)%	2 %

Total		322		23,540		25,472		180		21,711		22,791	79%	8%	12%

The production increase in the Piceance Basin was the result of our continued development activities with initial sales from 157 new gross wells from October 1, 2009 to September 30, 2010. The production decrease in the Uinta Basin is due to natural production declines as well as a limited development program compared to prior years in our West Tavaputs field with initial sales from only 33 new gross wells from October 1, 2009 to September 30, 2010, partially offset by higher volumes from our Blacktail Ridge/Lake Canyon development. 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, 2010, approximately 72% of our natural gas volumes (excluding basis only swaps, which was equivalent to 13% of our natural gas volumes) and 50% of our oil volumes were subject to financial hedges, which resulted in an increase in gas revenues of $44.6 million and an increase in oil revenues of $1.3 million after settlements for all commodity derivatives, including basis only and NGL swaps. During the three months ended September 30, 2009, approximately 72% of our natural gas volumes (excluding basis only swaps, which were equivalent to 4% of our natural gas volumes) and 56% of our oil volumes were subject to financial hedges, 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, including basis only swaps. The decrease in revenues related to hedging natural gas resulted from the expiration of hedges entered into at higher prices and the inability to enter into new hedges at those prices as natural gas prices have fallen since entering into those hedges. This trend is expected to continue based on future strip prices and hedge quotes.

The overall change in commodity derivative loss to $4.9 million for the three months ended September 30, 2010 from a loss of $13.7 million for the three months ended September 30, 2009 was primarily due to an unrealized gain of $1.8 million for the three months ended September 30, 2010 compared to an unrealized loss of $13.0 million for the three months ended September 30, 2009 primarily as a result of changes in the fair value of our basis only swaps, offset by realized losses primarily related to settlements of our basis only swaps.

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


	Three Months Ended September 30,
	2010			2009
	(in thousands)
Realized loss on derivatives not designated as cash flow hedges	$	(5,941	)	$	(1,423	)
Unrealized ineffectiveness gain (loss) recognized on derivatives designated as cash flow hedges		(781	)		741
Unrealized gain (loss) on derivatives not designated as cash flow hedges		1,788			(13,011	)

Total commodity derivative loss	$	(4,934	)	$	(13,693	)

Lease Operating Expense. Lease operating expense decreased to $0.51 per Mcfe for the three months ended September 30, 2010 from $0.57 per Mcfe for the three months ended September 30, 2009. The following table displays the lease operating expense by basin:


	Three Months Ended September 30, 2010				Three Months Ended September 30, 2009				%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		(per Mcfe)
Piceance Basin	$	3,933	$	0.30	$	4,030	$	0.44	(32)%
Uinta Basin		4,093		0.56		3,357		0.40	40%
Wind River Basin		1,528		0.90		1,458		0.77	17%
Powder River Basin		3,206		1.00		3,994		1.22	(18)%
Other		241		2.17		166		1.52	43%

Total	$	13,001	$	0.51	$	13,005	$	0.57	(11)%

Lease operating expense decreased in the Piceance Basin to $0.30 per Mcfe for the three months ended September 30, 2010 from $0.44 per Mcfe for the three months ended September 30, 2009 primarily due to decreased compression costs associated with the Bailey Compressor Station, reduced property tax expense and reduced workover activity. The increase in lease operating expense in the Uinta Basin to $0.56 per Mcfe for the three months ended September 30, 2010 from $0.40 per Mcfe for the three months ended September 30, 2009 was the result of increased workover activity and road maintenance expense as well as natural production declines resulting in higher lease operating expense on a per Mcfe basis. Additionally, higher inherent costs related to our increased oil production in the Lake Canyon and Blacktail Ridge fields contributed to higher lease operating expense in the Uinta Basin. Lease operating expense increased in the Wind River Basin to $0.90 per Mcfe for the three months ended September 30, 2010 from $0.77 per Mcfe for the three months ended September 30, 2009 as a result of increased compression expense due to a compressor overhaul completed in the current period as well as natural production declines resulting in higher lease operating expense on a per Mcfe basis. Lease operating expense decreased in the Powder River Basin to $1.00 per Mcfe for the three months ended September 30, 2010 from $1.22 per Mcfe for the three months ended September 30, 2009 primarily as a result of a reduction in the number of diesel fuel power generators used in the basin as these generators were replaced with electrical service from a local utility, reducing the amount of diesel fuel cost, and a reduction in the use of contract labor due to fewer workovers.

Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense decreased to $0.68 per Mcfe for the three months ended September 30, 2010 from $0.71 per Mcfe for the three months ended September 30, 2009. The following table displays the gathering and transportation expense by basin:


	Three Months Ended September 30, 2010				Three Months Ended September 30, 2009				%Increase/(Decrease)
	($ in thousands)		($ per Mcfe)		($ in thousands)		($ per Mcfe)		(per Mcfe)
Piceance Basin	$	8,942	$	0.68	$	7,056	$	0.78	(13)%
Uinta Basin		4,616		0.63		5,509		0.65	(3)%
Wind River Basin		20		0.01		10		0.01	0%
Powder River Basin		3,677		1.15		3,655		1.12	3%
Other		46		0.41		30		0.28	46%

Total	$	17,301	$	0.68	$	16,260	$	0.71	(4)%

Gathering, transportation and processing expense per Mcfe decreased in the Piceance Basin to $0.68 per Mcfe for the three months ended September 30, 2010 from $0.78 per Mcfe for the three months ended September 30, 2009. The decrease is primarily attributable to the utilization of gas processing due to capacity limitations. For the three months ended September 30, 2010, approximately 85% of the Piceance production was processed by a third party processor, with the additional 15% production gathered and transported without processing. For the three months ended September 30, 2009, approximately 99% of the Piceance production was processed by a third party processor.

Included in the above gathering and transportation expense is $0.18 and $0.19 per Mcfe of firm transportation expense for the three months ended September 30, 2010 and 2009, respectively, along with $0.04 and $0.05 per Mcfe of processing expense from long-term contracts for the three months ended September 30, 2010 and 2009, respectively. The decrease in firm transportation expense to $0.18 per Mcfe for the three months ended September 30, 2010 from $0.19 per Mcfe for the three months ended September 30, 2009 was the result of increased utilization on previously executed long-term transportation contracts for our natural gas production in the Piceance Basin.

Production Tax Expense. Total production taxes increased to $8.2 million for the three months ended September 30, 2010 from $6.5 million for the three months ended September 30, 2009. The increase in production taxes was primarily related to increased natural gas and oil prices. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. As the proportion of our production changes from area to area, our production tax rate will vary depending on the value of production produced from each area and the production tax rates in effect for those areas. As a result, production taxes as a percentage of natural gas and oil sales before hedging adjustments were 6.2% for the three months ended September 30, 2010 and 7.2% for the three months September 30, 2009.

Exploration Expense. Exploration expense increased to $3.8 million for the three months ended September 30, 2010 from $0.6 million for the three months ended September 30, 2009. Exploration expense for the three months ended September 30, 2010 consisted of $3.5 million for a well drilled for data gathering purposes and $0.3 million for delay rentals and other costs across all basins. 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, $0.2 million for evaluation of non-acquired assets and $0.3 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 decreased to $4.7 million during the three months ended September 30, 2010 from $19.1 million during the three months ended September 30, 2009. For the three months ended September 30, 2010, abandonment expense associated with exploratory drilling locations was $0.2 million, expired leasehold costs were $0.6 million and dry hole costs were $3.9 million. The $3.9 million of dry hole costs are primarily associated with two wells within the Yellow Jacket prospect of the Paradox Basin. 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 in the Paradox Basin, each of which were tested and determined to be non-commercial. For the three months ended September 30, 2010 and 2009, we did not incur any impairment charges related to the net carrying value of our development areas.

Depreciation, Depletion and Amortization. DD&A was $69.2 million for the three months ended September 30, 2010 compared to $66.7 million for the three months ended September 30, 2009. The increase of $2.5 million was a result of a 12% increase in production for the three months ended September 30, 2010 compared to the three months ended September 30, 2009 offset by a decrease in the DD&A rate. The increase in production accounted for $7.9 million of additional DD&A expense, while the overall decrease in the DD&A rate accounted for a $5.4 million reduction in DD&A expense. During the three months ended September 30, 2010, the weighted average DD&A rate was $2.72 per Mcfe. For the three months ended September 30, 2009, the weighted average DD&A rate was $2.93 per Mcfe.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, increased to $10.6 million in the three months ended September 30, 2010 from $10.3 million in the three months ended September 30, 2009. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 30 for a reconciliation and explanation. This increase was primarily due to an increase in employee compensation and benefit programs for the three months ended September 30, 2010 as well as an increase in costs associated with our efforts, and industry-wide efforts, to educate the public concerning the benefits of natural gas. On a per Mcfe basis, general and administrative expense, excluding non-cash stock-based compensation, decreased to $0.41 per Mcfe for the three months ended September 30, 2010 from $0.45 per Mcfe for the three months ended September 30, 2009 due to increased production for the three months ended September 30, 2010.

Non-cash charges for stock-based compensation were $3.4 million for the three months ended September 30, 2010 compared to $4.3 million for the three months ended September 30, 2009. Non-cash stock-based compensation expense for each of the three months ended September 30, 2010 and 2009 related primarily to vesting of our stock option awards and nonvested shares of common stock issued to employees.

The components of non-cash stock-based compensation for the three months ended September 30, 2010 and 2009 are shown in the following table:


	Three Months Ended September 30,
	2010		2009
	(in thousands)
Stock options and nonvested equity shares of common stock	$	3,212	$	4,167
Shares issued for 401(k) plan		123		123
Shares issued for directors’ fees		93		53

Total	$	3,428	$	4,343

Interest Expense. Interest expense increased to $11.2 million for the three months ended September 30, 2010 from $9.7 million for the three months ended September 30, 2009. Although our weighted average outstanding debt balance decreased for the three months ended September 30, 2010 to $401.9 million from $446.9 million for the three months ended September 30, 2009, our effective interest rate was higher for the three months ended September 30, 2010 compared to the three months ended September 30, 2009 primarily due to our Senior Notes issued in July 2009 and increased fees associated with the amendment of our Amended Credit Facility that was completed in March 2010. Our weighted average interest rate for the three months ended September 30, 2010, including interest and amortization of discounts and deferred financing fees on our Amended Credit Facility, Convertible Notes and Senior Notes, was 12.4% compared to 9.9% for the three months ended September 30, 2009. We capitalized interest costs of $1.1 million and $1.5 million for the three months ended September 30, 2010 and 2009, respectively.

Income Tax Expense. Income tax expense totaled $15.0 million for the three months ended September 30, 2010 compared to $1.4 million for the three months ended September 30, 2009, resulting in effective tax rates of 37.9% and 66.4%, respectively. The increase in income tax expense is primarily the result of the variations in revenue and expense components, and the resulting increase, of pre-tax net income as discussed above. The lower operating income for the three months ended September 30, 2009 had little impact on permanent differences affecting the tax rate calculation, thus increasing the overall effective tax rate for that period. Additionally, the effective tax rate will vary from period to period due to changes in the composition of income between state tax jurisdictions resulting from our activity. For both the 2010 and 2009 periods, our effective tax rate differs from the federal statutory rate primarily because we recorded stock-based compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes.

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, 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 reserves 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. 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 hedge positions provide relative certainty on a significant portion of our cash flows from operations through 2010 and 2011 even with the general decline in the prices of natural gas and oil 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 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 that we may use for future securities offerings.

At September 30, 2010, we had cash and cash equivalents of $71.8 million with a zero balance outstanding under our Amended Credit Facility. Under our Amended Credit Facility, we have a borrowing base of $800.0 million with commitments from 19 lenders for a total of $700.0 million, which was reaffirmed on September 24, 2010 based on June 30, 2010 reserves and hedge position. Our borrowing capacity is reduced by $26.0 million to $674.0 million due to an outstanding irrevocable letter of credit.

Cash Flow from Operating Activities

For the nine months ended September 30, 2010, we generated $340.6 million of cash provided by operating activities, a decrease of $32.3 million over the same period in 2009. Cash provided by operating activities decreased primarily due to higher cash operating expenses, including lease operating expense, gathering, transportation and processing expense, production tax expense and general and administrative expense, which were slightly offset by higher production volumes and realized commodity sales prices. Cash provided by operating activities further decreased 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, NGL and oil. 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, NGL and oil prices, we have entered into financial commodity swap and cashless collar contracts (purchased put options and written call options) to receive fixed prices for a portion of our production revenue. The cashless collars are used to establish floor and ceiling prices on anticipated future natural gas and oil production revenue. We typically hedge a fixed price for natural gas at our sales points (New York Mercantile Exchange (“NYMEX”) less basis) to mitigate the risk of differentials to the NYMEX Henry Hub Index. In addition to the swaps and collars, we also have 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. At September 30, 2010, we had in place natural gas, NGL and crude oil financial collars, swaps and basis only swaps covering portions of our 2010, 2011 and 2012 production revenue.

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 value and 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 hedges are effective, are recognized in accumulated other comprehensive income (“AOCI”) until the forecasted transaction occurs. The ineffective portion of hedge derivatives is reported in commodity derivative loss in the Unaudited Condensed Consolidated Statements of Operations. Realized gains and losses on cash flow hedges are transferred from AOCI 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.

During the term of a derivative instrument, if 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 AOCI will remain in AOCI 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 and all subsequent mark-to-market gains and losses are recorded in earnings, and all accumulated gains or losses recorded in AOCI related to the hedging instrument are also reclassified to earnings.

Some of our derivatives do not qualify for hedge accounting or are not designated as cash flow hedges 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 loss in the Unaudited Condensed Consolidated Statements of Operations. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the underlying physical 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 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 an appropriate part of a 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.

We have also entered into swap contracts to hedge a portion of the amount received related to NGL resulting from the processing of our gas. Our NGL hedges were not designated as cash flow hedges, and the fair value of these derivative instruments were recorded in earnings.

At September 30, 2010, the estimated fair value of all of our commodity derivative instruments was a net asset of $106.8 million comprised of current and noncurrent assets and liabilities, including a fair value liability of $18.6 million for basis only swaps and a fair value liability of $1.6 million for NGL swaps. We will reclassify the appropriate cash flow hedge amounts from AOCI 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 relating to cash flow hedges as of September 30, 2010 to be reclassified from AOCI to earnings in the next 12 months would be a gain of approximately $70.0 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, 2010 was a loss of $0.8 million and $1.0 million, respectively, and a gain of $0.7 million and a loss of $5.7 million for the three and nine months ended September 30, 2009, respectively, which was reported in commodity derivative 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 (amounts in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Realized gain on derivatives designated as cash flow hedges (1)	$	51,841		$	71,210		$	122,739		$	234,664

Realized loss on derivatives not designated as cash flow hedges (2)	$	(5,941	)	$	(1,423	)	$	(18,927	)	$	(2,446	)
Unrealized ineffectiveness gain (loss) recognized on derivatives designated as cash flow hedges (2)		(781	)		741			(1,047	)		(5,721	)
Unrealized gain (loss) on derivatives not designated as cash flow hedges (2)		1,788			(13,011	)		17,052			(40,445	)

Total commodity derivative loss	$	(4,934	)	$	(13,693	)	$	(2,922	)	$	(48,612	)

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

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

The following table summarizes all of our hedges in place as of September 30, 2010:


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:
October - December 2010
Natural gas		620,000		MMBtu	$	6.00	$	10.41		N/A		N/A			NWPL	$	1,602
Natural gas		385,000		MMBtu	$	4.90	$	5.67		N/A		N/A			CIGRM		545
Natural gas		310,000		MMBtu	$	7.00	$	11.00		N/A		N/A			TCO		957
Oil		36,800		Bbls	$	80.00	$	148.13		N/A		N/A			WTI		272
2011
Natural gas		2,140,000		MMBtu	$	4.75	$	6.00		N/A		N/A			CIGRM		2,204
Swap Contracts:
October - December 2010
Natural gas		7,762,500		MMBtu		N/A		N/A	$	6.54		N/A			CIGRM		23,399
Natural gas		3,970,000		MMBtu		N/A		N/A	$	5.90		N/A			NWPL		8,945
Natural gas		124,000		MMBtu		N/A		N/A	$	7.47		N/A			PEPL		486
Natural gas		310,000		MMBtu		N/A		N/A	$	9.43		N/A			DA		1,708
Natural gas liquids (3)		22,550,000		Gallons		N/A		N/A	$	0.93		N/A			Mt. Belvieu		(1,092	)
Oil		147,200		Bbls		N/A		N/A	$	82.64		N/A			WTI		211
2011
Natural gas		25,235,000		MMBtu		N/A		N/A	$	6.20		N/A			CIGRM		56,435
Natural gas		16,402,500		MMBtu		N/A		N/A	$	5.71		N/A			NWPL		28,631
Natural gas liquids (3)		14,475,000		Gallons		N/A		N/A	$	1.04		N/A			Mt. Belvieu		(533	)
Oil		146,000		Bbls		N/A		N/A	$	87.63		N/A			WTI		404
2012
Natural gas		915,000		MMBtu		N/A		N/A	$	5.96		N/A			CIGRM		1,206
Basis Only Swap Contracts (2):
October - December 2010
Natural gas		1,230,000		MMBtu		N/A		N/A		N/A	$	(2.49	)		NWPL		(2,593	)
Natural gas		775,000		MMBtu		N/A		N/A		N/A	$	(2.45	)		CIGRM		(1,545	)
2011
Natural gas		7,300,000		MMBtu		N/A		N/A		N/A	$	(1.72	)		NWPL		(9,173	)
2012
Natural gas		3,660,000		MMBtu		N/A		N/A		N/A	$	(1.24	)		NWPL		(2,763	)
Natural gas		3,660,000		MMBtu		N/A		N/A		N/A	$	(1.20	)		CIGRM		(2,496	)

Total																$	106,810

The following table includes all hedges entered into subsequent to September 30, 2010 through October 22, 2010:

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:

October - December 2010

Natural gas liquids (4)

1,000,000

Gallons

N/A

0.59

N/A

Mt. Belvieu

Oil

18,300

Bbls

N/A

83.75

N/A

WTI

2011

Natural gas liquids (4)

5,700,000

Gallons

N/A

1.50

N/A

Mt. Belvieu

Oil

109,500

Bbls

N/A

86.00

N/A

WTI

(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. Mt. Belvieu refers to the average daily price as quoted by Oil Price Information Service (“OPIS”) for Mont Belvieu spot gas liquid prices. 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.

(3)	Weighted average fixed price includes purity ethane, propane, normal butane, isobutene and natural gasoline hedges.

(4)	Weighted average fixed price includes propane, normal butane, isobutene and natural gasoline hedges.

By removing the price volatility related to a portion of our natural gas production for 2010, 2011 and 2012 and a portion of our oil production for 2010 and 2011, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

By using derivative instruments that are not traded 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, all of our derivative contracts are documented with an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”) or other contracts that 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.

We believe all of our counterparties 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 22, 2010, we do not have any past due receivables from any of our counterparties.

Depending on the impact of new regulations to be promulgated under the Dodd-Frank Wall Street Reform and Consumer Protection Act signed into law on July 21, 2010, we expect the cost of entering into financial hedging transactions to increase. In addition, there may be fewer counterparties able to make markets in financial hedging transactions, which could limit our ability to enter into hedges and further increase the costs of our hedges.

Capital Expenditures

Our capital expenditures are summarized in the following tables:


	Nine Months Ended September 30,
Basin/Area	2010		2009
	(in millions)
Piceance	$	214.3	$	203.2
Uinta		90.2		80.1
Paradox		4.4		22.5
Powder River		8.9		11.4
Wind River		4.8		1.7
Other		15.3		9.6

Total	$	337.9	$	328.5


	Nine Months Ended September 30,
	2010		2009
	(in millions)
Acquisitions of proved and unevaluated properties and other real estate	$	12.1	$	68.9
Drilling, development, exploration and exploitation of natural gas and oil properties (1)		319.5		255.5
Geologic and geophysical costs		4.8		2.2
Furniture, fixtures and equipment		1.5		1.9

Total (2)	$	337.9	$	328.5

(1)	Includes related gathering and facilities costs.

(2)	For the nine months ended September 30, 2010, we received $2.3 million of proceeds principally from the sale of interests in oil and gas properties, which are not deducted from the capital expenditures presented above.

Our current estimate is for capital expenditures of $475 to $485 million in 2010, of which $337.9 million has been spent as of September 30, 2010. On July 30, 2010, the U.S. Bureau of Land Management (“BLM”) published in the Federal Register the Record of Decision on the Environmental Impact Statement that authorizes full-field development of our West Tavaputs development area in the Uinta Basin. Our current estimate above includes additional capital to be spent in West Tavaputs as a result of this approval.

We believe that we have sufficient available liquidity through 2010 and 2011 to fund our capital expenditures budget from cash flow from operations and the Amended Credit Facility. 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 success or lack of success in drilling activities, the timing of regulatory approvals, acquisitions and divestitures, in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

Financing Activities

The Company’s outstanding debt is summarized below (in thousands):


		As of September 30, 2010							As of December 31, 2009
	Maturity Date	Principal		Unamortized Discount			Carrying Amount		Principal		Unamortized Discount			Carrying Amount
Amended Credit Facility (1)	April 1, 2014	$	0	$	0		$	0	$	5,000	$	0		$	5,000
Senior Notes (2)	July 15, 2016	$	250,000	$	(10,566	)	$	239,434	$	250,000	$	(11,522	)	$	238,478
Convertible Notes (3)	March 15, 2028 (4)	$	172,500	$	(9,412	)	$	163,088	$	172,500	$	(13,728	)	$	158,772

(1)	The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure.

(2)	The aggregate estimated fair value of the Senior Notes was approximately $273.1 million as of September 30, 2010 based on quoted market trades of these instruments.

(3)

(4)	We currently expect to call the Convertible Notes to be redeemed in 2012 or that the holders will put the Convertible Notes to us.

Revolving Credit Facility

On March 16, 2010, we amended our credit facility (the “Amended Credit Facility”) and extended the maturity date to April 1, 2014. 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 2.0% to 3.0% or an alternate base rate (“ABR”), based upon the greater of the prime rate, the federal funds effective rate plus 0.5% or the adjusted one month LIBOR plus 1.0%, plus applicable margins ranging from 1.0% to 2.0%. The borrowing base is required to be redetermined twice per year. On September 24, 2010, the borrowing base was reaffirmed at $800.0 million with commitments from 19 lenders of $700.0 million, based on June 30, 2010 reserves and hedge position. We pay annual commitment fees of 0.5% of the unused amount of our commitments. 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. The Amended Credit Facility also contains certain financial covenants. We currently are in compliance with all financial and other covenants, and we have complied with all financial covenants for all prior periods.

As of September 30, 2010, we did not have a balance outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit was issued under the Amended Credit Facility effective May 4, 2010, which reduced the borrowing capacity of the Amended Credit Facility by $26.0 million to $674.0 million.

5% Convertible Senior Notes due 2028

The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior indebtedness, including the Senior Notes. Interest is payable semi-annually in arrears on March 15 and September 15 of each year. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility.

9.875% Senior Notes Due 2016

The Senior Notes, which were issued on July 8, 2009, are 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. Interest is payable in arrears semi-annually on January 15 and July 15 beginning January 15, 2010. The Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility and the Convertible Notes. 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 currently are in compliance with all financial covenants, and we have complied with all financial covenants for all prior periods.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Credit Facility (1)
Cash interest	$	1,002	$	807	$	2,424	$	4,423
Non-cash interest	$	779	$	223	$	1,962	$	663
Senior Notes (2)
Cash interest	$	6,172	$	5,623	$	18,516	$	5,623
Non-cash interest	$	593	$	489	$	1,698	$	489
Convertible Notes (3)
Cash interest	$	2,156	$	20,156	$	6,469	$	6,469
Non-cash interest	$	1,795	$	1,666	$	5,170	$	4,795

(1)	Cash interest includes amounts related to interest and commitment fees paid on the line of credit and participation and fronting fees paid on the letter of credit.

(2)	The stated interest rate for the Senior Notes is 9.875% per annum with an effective interest rate of 11.3% per annum.

(3)

The stated interest rate for the Convertible Notes is 5% per annum with an effective interest rate of 9.7% per annum. The effective interest rate of the Convertible Notes includes the amortization of the debt discount, which represents the fair value of the equity conversion feature at the time of issue.

Shelf Registration Statement. We have on file with the SEC an effective universal shelf registration statement to allow us to offer an indeterminate amount of equity or debt securities in the future. Under the registration statement, we may periodically offer from time to time; debt securities, common stock, preferred stock, warrants and other securities or any combination of such securities in amounts, prices and on terms announced when and if the securities are offered. However, the issuance of additional securities in periods of market volatility may be less likely. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of any such offering.

Contractual Obligations. A summary of our contractual obligations as of September 30, 2010 is provided in the following table:


	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	(in thousands)
Notes payable (1)	$	553	$	553	$	553	$	553	$	553	$	1,425	$	4,190
Convertible Notes (2)		8,625		176,693		0		0		0		0		185,318
Senior Notes (3)		24,688		24,688		24,688		24,688		24,688		269,544		392,984
Purchase commitments (4)(8)		9,419		0		0		0		0		0		9,419
Drilling and rig commitments (5)(8)		6,703		13,497		0		0		0		0		20,200
Office and office equipment leases and other (10)		1,198		1,898		1,929		1,960		1,991		6,774		15,750
Firm transportation and processing agreements (8) (9)		45,904		54,258		55,200		53,892		53,261		231,209		493,724
Asset retirement obligations (6)		635		8,864		1,247		551		2,014		38,510		51,821
Derivative liability (7)		25		3,902		1,324		0		0		0		5,251

Total	$	97,750	$	284,353	$	84,941	$	81,644	$	82,507	$	547,462	$	1,178,657

(1)

We currently have a zero balance outstanding on 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. However, we have a $26.0 million letter of credit that accrues interest at 2.0% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term for the letter of credit is April 30, 2018.

(2)

On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. For purposes of contractual obligations, we assume that the holders of our Convertible Notes will not exercise the conversion feature, and we will therefore repay the $172.5 million in cash in 2012. We currently expect to call the Convertible Notes for redemption or have them put to us in 2012. We also are obligated to make annual interest payments of $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 of $24.7 million.

(4)

We have one take-or-pay carbon dioxide (“CO2”) purchasing agreement that expires in October 2011 and has a minimum volume commitment to purchase CO2 at a contracted price, subject to annual escalation. The contract provides CO2 used in fracturing operations in our Uinta Basin area. Should we not take delivery of the minimum volume required, we would be obligated to pay for the deficiency. At this time, our planned volumes needed exceed the minimum requirement, and we do not anticipate any deficiency payments.

(5)

We currently have four drilling rigs under contract; the contracts expire in 2011. All other rigs currently performing work for us are on a well-by-well basis, and therefore can be released without penalty at the conclusion of drilling on the current well. These latter types of drilling obligations have not been included in the table above.

(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, 2009 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(7)

Derivative liabilities represent the net fair value for oil and gas commodity derivatives presented as liabilities in our Unaudited Condensed Consolidated Balance Sheets as of September 30, 2010. 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, 2009 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 will record in our financial statements 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 13 years and require us to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by us.

(10)	The lease for our principal offices in Denver was renewed in September 2010 and now extends through 2019.

Trends and Uncertainties

For a discussion of trends and uncertainties that may affect our financial condition or liquidity, 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, 2009. Other than as discussed above and except for trends described in the risk factor section contained in Part II, Item 1A of this Form 10-Q, no material change to such trends and uncertainties has occurred during the nine months ended September 30, 2010.

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, 2009 and the notes to the Unaudited Condensed Consolidated Financial Statements included in Item 1 of this Quarterly Report on 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 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, NGL and oil 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 derivative contracts in place for the nine months ended September 30, 2010, our annual income before income taxes would have decreased by approximately $1.9 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.4 million for each $1.00 per barrel decrease in crude oil prices.

We routinely enter into and anticipate entering into financial hedges relating to a portion of our projected production revenue through various financial transactions, which hedge future prices received. These financial transactions may include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty and cashless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we and the counterparty to the collars would be required to settle the difference. These financial hedging activities are intended to support natural gas and oil prices at targeted levels and to manage our exposure to natural gas and oil price fluctuations. In addition to the swaps and collars discussed above, we also entered into basis only swaps. With a basis only swap, we have fixed the difference between the NYMEX price and the price received for our natural gas production at the specific delivery location to mitigate against the risk of large differences between NYMEX (Henry Hub) and our primary sales points, CIGRM and NWPL. 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.

As of October 22, 2010, we have financial instruments in place to hedge the following volumes for the periods indicated. Further detail of these hedges is provided 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.”


	October - December 2010		For the year 2011		For the year 2012
Oil (Bbls)		202,300		255,500		0
Natural Gas (MMbtu)		13,481,500		43,777,500		915,000
Natural Gas Basis (MMbtu)		2,005,000		7,300,000		7,320,000
Natural Gas Liquids (Gallons)		23,550,000		20,175,000		0

Interest Rate Risks

At September 30, 2010, we had a zero balance outstanding under our Amended Credit Facility with an average outstanding debt balance of $3.0 million for the nine months ended September 30, 2010, 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, 2010 was 2.2%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the nine months ended September 30, 2010 would have resulted in an estimated $0.02 million increase in interest expense assuming a similar average debt level to the nine months ended September 30, 2010. In addition, we had $172.5 million principal amount of Convertible Notes and $250.0 million principal amount of Senior Notes outstanding at September 30, 2010, which have a fixed cash interest rate of 5.0% and 9.875% per annum, respectively.

Item 4.

Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Based on an evaluation carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2010.

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, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings.

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

Item 1A.

Risk Factors.

Other than as set forth below and in Item 1A of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, 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, 2009, referred to as our 2009 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 2009 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.

Risks Related to the Oil and Natural Gas Industry and Our Business

Drilling for and producing oil and natural gas are risky activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our drilling activities subject us to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be curtailed, delayed or canceled or subject us to liabilities as a result of other factors, including:

•

unusual or unexpected geological formations or other features;

•

pressures;

•

fires;

•

blowouts;

•

loss of drilling fluid circulation;

•

title problems;

•

facility or equipment malfunctions;

•

leaks of natural gas, oil, condensate, natural gas liquids and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling and completion operations or in the gathering and transportation of hydrocarbons, malfunctions of pipelines, measurement equipment, or processing or other facilities in the Company’s operations or at delivery points to third parties;

•

other hazards, including those associated with high-sulfur content, or sour gas, such as an accidental discharge of hydrogen sulfide gas;

•

unexpected operational events;

•

shortages or delivery delays of equipment and services;

•

objections from surface owners and nearby surface owners in the areas where we operate;

•

compliance with environmental and other governmental requirements and related lawsuits; and

•

adverse weather conditions.

The occurrence of these events could also impact third parties, including persons living near our operations, our employees and employees of our contractors, leading to injuries, death, environmental damage, property damage or suspension of operations. As a result, we face the possibility of liabilities from these events that could adversely affect our business, financial condition or results of operations as well as adverse publicity that could lead to delays in or cessation of our operations and loss of related assets or revenues.

Additionally, the coalbeds in the Powder River Basin from which we produce methane gas frequently contain water, which may hamper our ability to produce gas in commercial quantities. The amount of coalbed methane that can be commercially produced depends upon the coal quality, the original gas content of the coal seam, the thickness of the seam, the reservoir pressure, the rate at which gas is released from the coal and the existence of any natural fractures through which the gas can flow to the well bore. Coalbeds, however, frequently require production of water in order for the gas to detach from the coal and flow to the well bore. The life of a coalbed well typically can range from five to 11 years depending on the coal seam compared to up to 30 years for a non-coalbed well. Our ability to remove and economically dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce coalbed methane in commercial quantities.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and inability to book future reserves.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate natural gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies, and the proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process. The adoption of future federal or state laws or implementing regulation imposing reporting obligation on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to perform or even prohibit hydraulic fracturing, complete natural gas wells, increase our costs of compliance and doing business, and preventing us from accessing, developing and booking reserves in the future.

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, 2010:


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, 2010		3,154	$	32.01		0		0
August 1 – 31, 2010		417		36.54		0		0
September 1 – 30, 2010		1,490		35.75		0		0

Total		5,061	$	33.48		0		0

(1)

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

Item 3.

Defaults upon Senior Securities.

Not applicable.

Item 5.

Other Information.

Not applicable.

Item 6.

Exhibits.


Exhibit Number		Description of Exhibits

3.1		Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.4 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 Deutsch 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.]

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.

101		The following materials from the Bill Barrett Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, formatted in XBRL (eXtensible Business Reporting Language) include (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Stockholders’ Equity and Comprehensive Income, (iv) the Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.*

Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited. Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these Sections.

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 2 , 2010	By:	/S/ FREDRICK J. BARRETT
		Fredrick J. Barrett
		Chairman of the Board of Directors, Chief Executive Officer and President
		(Principal Executive Officer)

Date: November 2, 2010	By:	/S/ ROBERT W. HOWARD
		Robert W. Howard
		Chief Financial Officer
		(Principal Financial Officer)

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