Exhibit 99.1

 

		Press Release

For immediate release

Company contact: Jennifer Martin, Director of Investor Relations, 303-312-8155

Bill Barrett Corporation Reports 2010 Results - Another Record Year:

Reserves 1.1 Tcfe and Cash Flow $467 million

DENVER – February 23, 2011 – Bill Barrett Corporation (NYSE: BBG) today reported full-year 2010 operating results highlighted by:

 

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Natural gas and oil production growth, up 8% to 96.5 Bcfe

 

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Proved reserve growth, up 16% to 1.1 Tcfe or 263% production replacement

 

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Discretionary cash flow up, at $467 million or $10.18 per diluted common share

 

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Net income up, at $80.5 million or $1.75 per diluted common share

Chairman, Chief Executive Officer and President Fred Barrett commented: “2010 was another very good year. We realized record cash flows despite an environment of low natural gas prices and certain higher costs. We achieved solid growth while keeping capital spending in line with cash flow. We grew reserves at an impressive all-in finding and development cost of $1.84 per thousand cubic feet equivalent (“Mcfe”) and ended the year with our revolving credit facility undrawn and with the Company in a very strong financial position.

“Going into 2011, we are well positioned to generate solid growth in production and reserves from our key development projects while pursuing several new prospects on the exploration front. We are excited to accelerate activity at West Tavaputs and Blacktail Ridge, each of which offers growth from development plans as well as upside potential. We plan to drill and test a handful of new exploration prospects located throughout the Rocky Mountain region, while we continue our pursuit of Hornfrog and Cottonwood Gulch, each of which have the potential to be sizable extensions of existing programs. At the same time, we continue to consider growth through acquisition, as we evaluate a range of Rocky Mountain opportunities. We will be working hard to make 2011 another record year.”

Natural gas and oil production totaled 96.5 billion cubic feet equivalent (“Bcfe”) in 2010, up 8% from 89.7 Bcfe in 2009. Production growth was predominantly from Gibson Gulch in the Piceance Basin, up 32% from 2009. The Company also enjoyed a 53% increase in oil production, primarily due to increased development drilling at Blacktail Ridge. Including the effects of the Company’s hedging activities and natural gas liquids recovery, the average realized sales price in 2010 was $7.07 per Mcfe, nearly flat with the 2009 average of $7.10. The Company’s 2010 commodity hedging program increased its natural gas and oil revenues by net $135.3 million, or $1.40 per Mcfe of production. For the fourth quarter of 2010, production was 24.2 Bcfe, up 6% from 22.8 Bcfe in the fourth quarter of 2009, and the average realized price was $6.86 per Mcfe, down from $7.02 in the fourth quarter of 2009.

Proved reserves at year-end 2010 were 1.1 trillion cubic feet equivalent (“Tcfe”), up 16% from 964.8 Bcfe at year-end 2009. The Company was again able to realize sizable reserve growth while aligning capital expenditures with discretionary cash flow. Capital expenditures totaled $473.3 million, driving the average all-in finding and development cost (a non-GAAP metric, see Costs Incurred and Reserve Information below) for 2010 to $1.84 per Mcfe.

Discretionary cash flow (a non-GAAP measure, see “Discretionary Cash Flow Reconciliation” below) for 2010 was $467.0 million, or $10.18 per diluted common share, up $7.4 million from $459.6 million, or $10.20 per share in 2009. The year-over-year increase was primarily due to higher production, partially offset by higher per unit operating costs for transportation and production taxes as well as higher cash interest expense. Discretionary cash flow for the fourth quarter of 2010 was $109.9 million, or $2.41 per diluted common share, down 4% compared with $114.3 million, or $2.53 per diluted common share, in the fourth quarter of 2009.

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Net income for 2010 was $80.5 million, or $1.75 per diluted common share, compared with $50.2 million, or $1.12 per diluted common share, in 2009. The increased net income was primarily due to lower commodity derivative losses and lower impairment, dry hole and abandonment expenses in 2010. Adjusted net income for 2010 (a non-GAAP measure, see “Adjusted Net Income Reconciliation” below) was $78.6 million, or $1.71 per diluted common share, compared with $82.7 million, or $1.84 per diluted common share, in 2009. Adjusted net income removes the effect of non-recurring charges such as unrealized derivative gains and losses, impairment expenses, property sales and one-time items. For the fourth quarter of 2010, net income was a loss of ($7.2) million or ($0.16) per diluted common share. The net loss, compared with earnings of $12.5 million in the fourth quarter of 2009, was primarily the result of higher exploration and impairment, dry hole and abandonment expenses. Adjusted net income for the fourth quarter of 2010 was $3.0 million or $0.07 per diluted common share. Total dry hole expense for 2010 was $26.5 million, or $16.7 million after-tax, and for the fourth quarter of 2010 was $20.1 million, or $12.7 after-tax, and included certain wells in the Paradox and Big Horn Basins.

DEBT AND LIQUIDITY

The Company had no amounts drawn on its revolving credit facility at December 31, 2010. The revolving credit facility has commitments totaling $700.0 million and a borrowing base of $800.0 million. Deducting an outstanding letter of credit for $26.0 million, the Company had $674.0 million of borrowing capacity at December 31, 2010. The Company expects to draw from its revolving credit facility during 2011 as planned capital expenditures are expected to exceed cash flows from operations. The Company also had $172.5 million in 5% convertible senior notes and $250.0 million in 9.875% senior notes outstanding at December 31, 2010.

OPERATIONS

Production, Wells Spud and Capital Expenditures

The following table lists production, wells spud and total capital expenditures by basin for the three and twelve months ended December 31, 2010:

 

		Three Months ended December 31, 2010												Twelve Months ended December 31, 2010
Basin		Average Net Production (Mmcfe/d)				Wells Spud (gross)				Capital Expenditures (millions)				Average Net Production (Mmcfe/d)				Wells Spud (gross)				Capital Expenditures (millions)
Piceance			138				32			$	55.5				131				149			$	269.8
Uinta			71				16				52.5				76				45				142.7
Powder River (CBM)			36				34				2.6				37				71				11.5
Wind River			17				1				3.5				19				1				8.3
Other			1				8				21.3				1				9				41.0
Total			263				91			$	135.4				264				275			$	473.3

Capital expenditures totaled $473.3 million for the full year 2010 and $135.4 million in the fourth quarter of 2010. Capital expenditures included: $432.0 million for drilling, exploration and development, $30.1 million for acquisitions of proved and unevaluated properties and other real estate, $9.1 million for geologic and geophysical costs and $2.1 million for furniture, equipment and other assets. The Company did not have any material acquisitions or divestitures in 2010.

 

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Operating and Drilling Update

The Company anticipates drilling approximately 215 gross development wells in 2011, including approximately 30 coal bed methane (CBM) wells. The Company’s development program will be focused on growth in production and reserves as well as driving operating efficiencies at West Tavaputs. In 2011, the Company also plans a robust exploration program that will include the testing and drilling of several new prospects. The Company currently has five rigs drilling at development programs and expects to commence exploration drilling in the second quarter of 2011.

Uinta Basin, Utah

West Tavaputs – Current net production is approximately 57 million cubic feet equivalent per day (MMcfe/d). Following receipt of the Environmental Impact Statement Record of Decision, the Company re-started activity at West Tavaputs in the fourth quarter of 2010, drilling ten wells during the quarter that will be completed in 2011, and intending to drill approximately 100 wells under the 2011 drilling program. The 2011 program includes two rigs through the year, drilling 8-10 wells per drill pad. In order to attain higher levels of operating efficiencies and to support substantial future production growth, the Company expects to spend approximately $50 million for facilities, water management, roads and increased gathering capacity in 2011. West Tavaputs is the Company’s largest development asset based on its current reserve base of 345 Bcfe proved and 1.3 Tcfe proved, probable and possible reserves (see “Reserve Disclosure” below). Re-starting activity in this area provides a multi-year, high growth program for the Company.

At December 31, 2010, the Company had an approximate 97% working interest in production from 185 gross wells in its West Tavaputs shallow and deep programs. The West Tavaputs program offers growth in the shallow Mesaverde and Wasatch zones as well as upside opportunity through the shallow Green River oil, Mancos shale and deep formations.

Blacktail Ridge/Lake Canyon – Current net production is approximately 2,300 barrels of oil equivalent per day (“Boe/d”). The Company expects to operate one rig in the area for the full year 2011 and add a second rig during the third quarter. In addition, the Company has identified four horizons that may be conducive to horizontal drilling and plans to drill and complete a first horizontal oil test in the Uteland Butte zone at approximately 4,600 feet depth during the second quarter of 2011. Dependent upon receipt of permits, the Company expects to participate in drilling up to 50 wells in the area in 2011, including 17 wells operated by its partner in Lake Canyon. At December 31, 2010, the Company had an approximate 65% working interest in production from 44 gross wells. The working interests in this area range from 19% to 100%.

Hornfrog – At the Hornfrog natural gas prospect located southeast of West Tavaputs, the Company continues to produce from two wells completed in September of 2010. One of the two wells continues to indicate geologic and production similarities to West Tavaputs. The Company intends to drill four wells in the area in 2011 as part of a drill-to-earn program for a 55% working interest in up to 30,700 gross acres, although timing has been affected by a dispute between the Company’s farmout partner and third parties.

Piceance Basin, Colorado

Gibson Gulch – Current net production is approximately 132 MMcfe/d. During 2011, the Company plans to operate one rig in the area through the second quarter and then discontinue drilling for the remainder of the year. The Gibson Gulch program serves as a “swing area” for the Company as it can substantially modify the drilling program in conjunction with broader capital plans. Due to the Company’s focus at West Tavaputs during the year, activity in this area will be slowed. The Company continues to benefit from its election to process the majority of its Gibson

 

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Gulch natural gas production, which exposes the Company to natural gas liquids pricing. The incremental benefit to production revenues related to natural gas liquids was $0.92 per Mcfe to the Company-wide realized price in the fourth quarter and $0.71 per Mcfe for the full year 2010. Gibson Gulch operations offer strong margins due to low operating costs and the currently higher revenues related to liquids. The program continues to be a key, lower risk development area for the Company.

At December 31, 2010, the Company had an approximate 98% working interest in production from 703 gross wells in its Gibson Gulch program.

Cottonwood Gulch – In June 2009, the Company acquired a 90% working interest in 40,300 gross undeveloped acres in Cottonwood Gulch. The leases were challenged in Federal District Court by environmental groups. Resolution of the case is currently pending with a District Court judge. The Company is working with stakeholders to pursue this opportunity pending resolution.

Powder River Basin, Wyoming

Coal Bed Methane (CBM) – Current CBM net production is approximately 35 MMcf/d and, in 2011, the Company plans to participate in drilling a minimal program in the area of approximately 30 wells. Development of this area requires production of water in order to draw down the formation pressure, which allows the natural gas to detach from the coal and flow into the wellbore, which can take up to three years or, in some cases, longer.

At December 30, 2010, the Company had an approximate 74% working interest in production from 715 gross CBM wells.

Wind River Basin, Wyoming

McRae Gap - The Company has identified approximately 90,800 net undeveloped acres within its acreage position in the area that it considers prospective for shale oil. In the fourth quarter of 2010, the Company drilled a horizontal exploration well into the lower bench of the Niobrara Shale at approximately 8,200 feet depth with an approximate 3,200 foot lateral. Completion of this well is expected in August 2011, which was delayed due to wildlife stipulations that will be in effect through July.

Paradox Basin, Colorado

Yellow Jacket and Green Jacket – At the Yellow Jacket shale gas prospect (100% working interest), the Company continues to produce from three wells. The Company currently is seeking a partner and expects to resume exploration drilling in the area. The Yellow Jacket and Green Jacket prospects include approximately 484,275 gross and 370,200 net undeveloped acres.

ADDITIONAL FINANCIAL INFORMATION

Guidance

As previously announced, the Company’s 2011 guidance (please reference “Forward-Looking Statements” below) is as follows:

 

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Capital expenditures of $525 to $565 million (before acquisitions, if any), which includes approximately $50 million in facilities and other project costs to ramp up activity at West Tavaputs and up to 15% of expenditures for exploration activities.

 

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Oil and natural gas production of 103 to 107 Bcfe, up 7% to 11% from 2010.

 

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Lease operating costs per Mcfe of $0.58 to $0.62.

 

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Gathering, transportation and processing costs per Mcfe of $0.89 to $0.94, which reflects higher costs associated with increased firm transportation charges.

 

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General and administrative expenses before non-cash stock-based compensation between $45 and $47 million.

Commodity Hedges Update

It is the Company’s strategy to hedge a portion of its production to reduce the risks associated with unpredictable future commodity prices and to provide predictability for a portion of cash flows in order to support the Company’s capital expenditure program.

For 2011 and 2012, the Company has hedges in place as outlined in the table below. Swap and collar hedge positions are tied to regional sales points and include:

 

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For 2011, approximately 55.2 Bcfe at a weighted average blended floor price of $7.68 per Mcfe.

 

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For 2012, approximately 18.4 Bcfe at a weighted average blended floor price of $5.81 per Mcfe.

As of February 8, 2011:

SWAPS & COLLARS

 

Period		Natural Gas / NGLs								Oil								EQUIVALENT
		Volume MMBtu/d				Price $/ MMBtu				Volume Bbl/d				Price $/Bbl				Volume Mmcfe				Price $/Mcfe
1Q11			153,147			$	6.79				1,866			$	90.20				13,538			$	8.03
2Q11			164,100			$	6.28				2,100			$	90.83				14,722			$	7.55
3Q11			162,840			$	6.26				2,100			$	90.83				14,779			$	7.53
4Q11			131,033			$	6.20				2,100			$	90.83				12,118			$	7.62
1Q12			55,374			$	4.65				500			$	98.37				4,854			$	5.75
2Q12			55,374			$	4.65				500			$	98.37				4,854			$	5.75
3Q12			55,370			$	4.65				500			$	98.37				4,907			$	5.75
4Q12			42,109			$	4.72				500			$	98.37				3,798			$	6.01

In addition, the Company has natural gas basis only hedges in place for 2011 of 20,000 MMBtu/d at a basis differential price between CIG Rocky Mountains and Henry Hub of ($1.72) per MMbtu and for 2012 of 20,000 MMBtu/d at a basis differential price of ($1.22) per MMBtu. These hedges are not in the money.

2010 FOURTH QUARTER AND FULL YEAR RESULTS WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held later this morning to discuss 2010 results. Please join Bill Barrett Corporation executive management at 12:00 p.m. EST/10:00 a.m. MST for the live webcast, accessed at www.billbarrettcorp.com, or join by telephone by calling 866-788-0544 (857-350-1682 international callers) with passcode 19887539. The webcast will remain available on the Company’s website for approximately 30 days, and a replay of the call will be available through February 28, 2011 at call-in number 888-286-8010 (617-801-6888 international) with passcode 15024076. The Company also has tentatively scheduled its 2011 earnings conference calls for May 3rd, August 4th and November 3rd, typically at noon Eastern time/10:00 a.m. Mountain time.

 

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UPCOMING EVENTS

Investor Conferences

Updated investor presentations will be posted to the homepage of the Company’s website at www.billbarrettcorp.com for each event below. Please check the website at 5:00 Mountain time on the business day prior to the investor event for the most recent presentation:

Chief Financial Officer Bob Howard will present at the JP Morgan Global High Yield and Leveraged Finance Conference on Tuesday, March 1, 2011 at 4:40 p.m. Eastern time. The event is not webcast.

Chairman, Chief Executive Officer and President Fred Barrett will present at the Howard Weil 2011 Energy Conference on Monday, March 28, 2011 at 4:20 p.m. Central time. The event is not webcast.

DISCLOSURE STATEMENTS

Forward-Looking Statements

This press release contains forward-looking statements, including statements regarding projected results and future events. In particular, the Company is providing “2011 Guidance,” which contains projections for certain 2011 operational and financial results. These forward-looking statements are based on management’s judgment as of this date and include certain risks and uncertainties. Please refer to the Company’s Annual Report on Form 10-K for the year-ended December 31, 2010, expected to be filed with the SEC today, and other filings including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, for a list of certain risk factors.

Actual results may differ materially from Company projections and can be affected by a variety of factors outside the control of the Company including, among other things, market conditions, oil and gas price volatility, exploration drilling and testing results, the ability to receive drilling and other permits, regulatory approvals, governmental laws and regulations and changes in enforcement of those laws and regulations, new laws and regulations, risks related to and costs of hedging activities including counterparty viability, surface access and costs, availability of third party gathering, transportation and processing, the availability and cost of services and materials, the ability to obtain industry partners to jointly explore certain prospects and the willingness and ability of those partners to meet capital obligations when requested, availability and costs of financing to fund the Company’s operations, uncertainties inherent in oil and gas production operations and estimating reserves, the speculative actual recovery of estimated potential volumes, unexpected future capital expenditures, competition, risks associated with operating in one major geographic area, the success of the Company’s risk management activities, title to properties, litigation, environmental liabilities, and other factors discussed in the Company’s reports filed with the SEC. Bill Barrett Corporation encourages readers to consider the risks and uncertainties associated with projections and other forward-looking statements. In addition, the Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances.

 

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Reserve Disclosure

The SEC, under its recently revised guidelines, permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. The Company does not plan to include probable and possible reserve estimates in its filings with the SEC.

The Company has provided internally generated estimates for probable and possible reserves in this release. The estimates conform to SEC guidelines. They are not prepared or reviewed by third party engineers. Our probable and possible reserve estimates are determined using strip pricing which we use internally for planning and budgeting purposes. The Company's estimate of probable and possible reserves is provided in this release because management believes it is useful, additional information that is widely used by the investment community in the valuation, comparison and analysis of companies. U.S. investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2010, available on the Company's website at www.billbarrettcorp.com or from the corporate offices at 1099 18th Street, Suite 2300, Denver, CO 80202. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or at www.sec.gov.

ABOUT BILL BARRETT CORPORATION

Bill Barrett Corporation (NYSE: BBG), headquartered in Denver, Colorado, explores for and develops natural gas and oil in the Rocky Mountain region of the United States. Additional information about the Company may be found on its website www.billbarrettcorp.com.

 

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BILL BARRETT CORPORATION

Selected Operating Highlights

(Unaudited)

 

						Three Months Ended December 31,								Twelve Months Ended December 31,
						2010				2009				2010				2009
Production Data:
Natural gas (MMcf)							22,459				21,626				89,964				85,485
Oil (MBbls)							294				193				1,089				710
Combined volumes (MMcfe)							24,223				22,784				96,498				89,745
Daily combined volumes (Mmcfe/d)							263				248				264				246
Average Prices (before the effects of realized hedges):
Natural gas (per Mcf)						$	5.06			$	4.98			$	5.26			$	3.86
Oil (per Bbl)							71.97				65.53				67.93				49.56
Combined (per Mcfe)							5.56				5.28				5.67				4.07
Average Prices (after the effects of realized hedges):
Natural gas (per Mcf)						$	6.47			$	6.79			$	6.74			$	6.96
Oil (per Bbl)							71.05				67.76				69.91				59.03
Combined (per Mcfe)							6.86				7.02				7.07				7.10
Average Costs (per Mcfe):
Lease operating expense						$	0.54			$	0.51			$	0.54			$	0.52
Gathering, transportation and processing expense							0.72				0.73				0.72				0.63
Production tax expense			(1	)			0.30				0.06				0.34				0.15
Depreciation, depletion and amortization							2.84				2.82				2.70				2.83
General and administrative expense, excluding non-cash stock-based compensation			(2	)			0.43				0.38				0.42				0.42

 

(1)

Production tax expense for the twelve months ended December 31, 2010 and the three and twelve months ended December 31, 2009 includes a one-time benefit to reduce and re-estimate prior periods as a result of amended returns filed with the States of Utah and Colorado regarding the calculation of severance taxes. Exclusive of the one-time benefits, the production tax expense per Mcfe would have been $0.36 for 2010 and $0.07 and $0.20, respectively, for the 2009 periods.

(2)

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 cash required for general and administrative expenses. Management also believes that this disclosure may allow for a more accurate comparison to the Company's peers that may have higher or lower costs associated with equity grants.

 

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BILL BARRETT CORPORATION

Consolidated Statements of Operations

(Unaudited)

 

						Three Months Ended December 31,								Twelve Months Ended December 31,
						2010				2009				2010				2009
(in thousands, except per share amounts)
Operating and Other Revenues:
Oil and gas production			(1	)		$	173,496			$	168,384			$	708,452			$	647,839
Commodity derivative loss			(1	)			(7,657	)			(5,955	)			(10,579	)			(54,567	)
Other							(2,441	)			3,344				591				4,891
Total operating and other revenues							163,398				165,773				698,464				598,163
Operating Expenses:
Lease operating							13,017				11,571				52,040				46,492
Gathering, transportation and processing							17,331				16,596				69,089				56,608
Production tax			(2	)			7,214				1,347				32,738				13,197
Exploration							4,325				1,055				9,121				3,227
Impairment, dry hole costs and abandonment							36,144				22,451				44,664				52,285
Depreciation, depletion and amortization							69,039				64,114				260,665				253,573
General and administrative			(3	)			10,324				8,747				40,884				37,940
Non-cash stock-based compensation			(3	)			5,739				4,377				16,908				16,458
Total operating expenses							163,133				130,258				526,109				479,780
Operating Income							265				35,515				172,355				118,383
Other Income and Expense:
Interest and other income							46				144				402				438
Interest expense							(11,810	)			(10,549	)			(44,302	)			(30,647	)
Total other income and expense							(11,764	)			(10,405	)			(43,900	)			(30,209	)
Income (loss) before Income Taxes							(11,499	)			25,110				128,455				88,174
Provision (benefit) for Income Taxes							(4,264	)			12,631				47,953				37,956
Net Income (loss)						$	(7,235	)		$	12,479			$	80,502			$	50,218
Net Income Per Common Share
Basic						$	(0.16	)		$	0.28			$	1.78			$	1.12
Diluted						$	(0.16	)		$	0.28			$	1.75			$	1.12
Weighted Average Common Shares Outstanding
Basic							45,666				44,782				45,218				44,732
Diluted							45,666				45,276				45,887				45,036

 

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

 

 

(2)

Production tax expense for the twelve months ended December 31, 2010 and the three and twelve months ended December 31, 2009 includes a one-time benefit to reduce and re-estimate prior periods as a result of amended returns filed with the States of Utah and Colorado regarding the calculation of severance taxes.

(3)

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 cash required for general and administrative expenses. Management also believes that this disclosure may allow for a more accurate comparison to the Company's peers that may have higher or lower costs associated with equity grants.

 

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BILL BARRETT CORPORATION

Consolidated Condensed Balance Sheets

(Unaudited)

 

						As of December 31, 2010				As of December 31, 2009
(in thousands)
Assets:
Cash and cash equivalents						$	58,690			$	54,405
Other current assets			(1	)			148,958				125,634
Property and equipment, net							1,811,819				1,659,260
Other noncurrent assets			(1	)			19,033				26,824
Total assets						$	2,038,500			$	1,866,123
Liabilities and Stockholders’ Equity:
Current liabilities			(1	)		$	165,957			$	153,292
Notes payable under bank credit facility							—				5,000
Senior notes							239,766				238,478
Convertible senior notes							164,633				158,772
Other long-term liabilities			(1	)			327,182				282,026
Stockholders’ equity							1,140,962				1,028,555
Total liabilities and stockholders’ equity						$	2,038,500			$	1,866,123

 

(1)

At December 31, 2010, the estimated fair value of all of our commodity derivative instruments was a net asset of $56.4 million, comprised of: $64.9 million current assets; $0.9 million current liabilities; and $7.6 million non-current liabilities. This amount will fluctuate quarterly based on estimated future commodity prices and the current hedge position.

 

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BILL BARRETT CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)

 

		Three Months Ended December 31,								Twelve Months Ended December 31,
		2010				2009				2010				2009
(in thousands)
Operating Activities:
Net income (loss)		$	(7,235	)		$	12,479			$	80,502			$	50,218
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization			69,039				64,114				260,665				253,573
Impairment, dry hole costs and abandonment expenses			36,144				22,451				44,664				52,285
Unrealized derivative (gain) loss			418				(2,501	)			(15,587	)			43,665
Deferred income taxes			(2,989	)			10,996				57,361				31,867
Stock compensation and other non-cash charges			6,779				4,623				19,032				17,698
Amortization of debt discounts and deferred financing costs			3,200				2,457				12,031				8,410
(Gain) loss on sale of properties			193				(1,352	)			(806	)			(1,386	)
Change in assets and liabilities:
Accounts receivable			(9,941	)			(15,991	)			(10,021	)			3,854
Prepayments and other assets			3,364				920				(6,939	)			(922	)
Accounts payable, accrued and other liabilities			12,755				7,133				2,812				20,046
Amounts payable to oil & gas property owners			(5,798	)			8,523				(352	)			3,088
Production taxes payable			704				(5,925	)			3,826				(1,652	)
Net cash provided by operating activities		$	106,633			$	107,927			$	447,188			$	480,744
Investing Activities:
Additions to oil and gas properties, including acquisitions			(131,390	)			(77,591	)			(444,871	)			(450,411	)
Additions of furniture, equipment and other			(2,016	)			(684	)			(4,107	)			(3,971	)
Proceeds from sale of properties and other investing activities			528				1,034				2,661				3,748
Net cash used in investing activities		$	(132,878	)		$	(77,241	)		$	(446,317	)		$	(450,634	)
Financing Activities:
Proceeds from credit facility			—				—				20,000				100,000
Principal payments on credit facility			—				(28,000	)			(25,000	)			(349,000	)
Proceeds from issuance of senior notes			—				—				—				237,930
Deferred financing costs and other			(36	)			(2,084	)			(15,293	)			(8,578	)
Proceeds from sale of common stock			13,199				252				23,707				880
Net cash provided by (used in) financing activities		$	13,163			$	(29,832	)		$	3,414			$	(18,768	)
Increase (Decrease) in Cash and Cash Equivalents			(13,082	)			854				4,285				11,342
Beginning Cash and Cash Equivalents			71,772				53,551				54,405				43,063
Ending Cash and Cash Equivalents		$	58,690			$	54,405			$	58,690			$	54,405

 

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BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow & Adjusted Net Income

(Unaudited)

Discretionary Cash Flow Reconciliation

 

		Three Months Ended December 31,								Twelve Months Ended December 31,
		2010				2009				2010				2009
(in thousands, except per share amounts)
Net Income (loss)		$	(7,235	)		$	12,479			$	80,502			$	50,218
Adjustments to reconcile to discretionary cash flow:
Depreciation, depletion and amortization			69,039				64,114				260,665				253,573
Impairment, dry hole and abandonment expenses			36,144				22,451				44,664				52,285
Exploration expense			4,325				1,055				9,121				3,227
Unrealized derivative (gain) loss			418				(2,501	)			(15,587	)			43,665
Deferred income taxes			(2,989	)			10,996				57,361				31,867
Stock compensation and other non-cash charges			6,779				4,623				19,032				17,698
Amortization of debt discounts and deferred financing costs			3,200				2,457				12,031				8,410
(Gain) loss on sale of properties			193				(1,352	)			(806	)			(1,386	)
Discretionary Cash Flow		$	109,874			$	114,322			$	466,983			$	459,557
Per share, diluted		$	2.41			$	2.53			$	10.18			$	10.20
Per Mcfe		$	4.54			$	5.02			$	4.84			$	5.12
Adjusted Net Income Reconciliation
		Three Months Ended December 31,								Twelve Months Ended December 31,
		2010				2009				2010				2009
(in thousands except per share amounts)
Net Income (loss)		$	(7,235	)		$	12,479			$	80,502			$	50,218
Adjustments to net income:
Unrealized derivative (gain) loss			418				(2,501	)			(15,587	)			43,665
Impairment expense			15,616				19,654				15,616				19,654
Gain (loss) on sale of properties			193				(1,352	)			(806	)			(1,386	)
One time items:
Production tax expense			—				(187	)			(2,184	)			(4,983	)
Subtotal Adjustments			16,227				15,614				(2,961	)			56,950
Effective tax rate			37	%			50	%			37	%			43	%
Tax effected adjustments			10,223				7,807				(1,865	)			32,461
Adjusted Net Income		$	2,988			$	20,286			$	78,637			$	82,679
Per share, diluted		$	0.07			$	0.45			$	1.71			$	1.84
Per Mcfe		$	0.12			$	0.89			$	0.81			$	0.92

The non-GAAP (Generally Accepted Accounting Principles in the United States of America) measures of discretionary cash flow and adjusted net income are presented because management believes that they provide useful additional information to investors for analysis of the Company’s ability to internally generate funds for exploration, development and acquisitions as well as adjusting net income for unusual items to allow for a more consistent comparison from period to period. In addition, these measures are widely used by professional research analysts and others in the valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions.

These measures should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, profitability, cash flow or liquidity measures prepared in accordance with GAAP. Because discretionary cash flow and adjusted net income exclude some, but not all, items that affect net income and net cash provided by operating activities and may vary among companies, the amounts presented may not be comparable to similarly titled measures of other companies.

 

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BILL BARRETT CORPORATION

Costs Incurred and Reserve Information

(Unaudited)

 

		2010				2009				2008
($ in millions)
TOTAL CAPITAL EXPENDITURES		$	473.3			$	406.4			$	601.1
Furniture, fixtures and equipment and real estate			(3.8	)			(3.7	)			(4.8	)
Asset retirement obligation			1.3				(1.2	)			8.2
TOTAL COSTS INCURRED (1)		$	470.8			$	401.5			$	604.5
TOTAL COSTS INCURRED DISCLOSURE
Exploration costs		$	82.8			$	185.4			$	342.9
Development costs			358.3				147.2				214.0
Acquisition costs:
Unproved properties			25.2				70.1				33.1
Proved properties			3.2				—				6.3
Asset retirement obligation			1.3				(1.2	)			8.2
TOTAL COSTS INCURRED			470.8				401.5				604.5
less: Asset retirement obligation			(1.3	)			1.2				(8.2	)
less: (Proceeds)/adjusted proceeds received from JV partners			1.5				—				—
less: Capitalized interest			(4.2	)			(4.6	)			(2.0	)
Adjusted costs incurred (1)		$	466.8			$	398.1			$	594.3
RESERVE ADDITIONS (Bcfe)
Extensions, discoveries and other additions			185.1				177.3				196.2
Revisions of previous estimates based on performance			39.8				101.5				146.4
Revisions of previous estimates based on price			27.4				(42.8	)			(7.3	)
Purchases of reserves in place			1.4				0.5				3.1
RESERVE ADDITIONS			253.7				236.5				338.4
SALES INFORMATION
Property sales		$	4.4			$	3.7			$	2.4
Sales of reserves (Bcfe)			3.7				0.2				0.1

 

(1)

Finding and developments cost is a non-GAAP metric commonly used in the exploration and production industry. The calculation presented by the Company of $1.84 per Mcfe is the quotient of “Adjusted costs incurred” divided by “Reserve additions.” The calculation may not be comparable to similarly titled measures provided by other companies.

 

13