Bill Barrett (BBG) 8-K Production growth, up 16% to 89.7 Bcfe

EXHIBIT 99.1

For immediate release

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

Bill Barrett Corporation Reports 2009 Results: Another Record Year

DENVER – February 23, 2010 – Bill Barrett Corporation (NYSE: BBG) today reported full-year 2009 operating results highlighted by:

• Production growth, up 16% to 89.7 Bcfe

• Proved reserve growth, up 18% to 965 Bcfe

• Proved, probable and possible reserves up 97% to 5.7 Tcfe

• Discretionary cash flow of $459.6 million, or $10.21 per diluted common share and $5.12 per Mcfe

• Net income of $50.2 million, or $1.12 per diluted share, and adjusted net income of $82.7 million, or $1.84 per diluted share

• Finding and development costs that average $1.74 per Mcfe, weighted over three years

• Current available borrowing capacity of $593 million

Chairman and Chief Executive Officer Fred Barrett commented: “Our Company continues to deliver solid growth, maintaining its outstanding multi-year track record. In 2009, we realized record discretionary cash flow (a non-GAAP measure, see “Discretionary Cash Flow Reconciliation” below) of $460 million, substantial production growth of 16%, positive reserve replacement of 264%, and we reduced finding and development costs (See “Costs Incurred and Reserve Information” below) to $1.68 per thousand cubic feet (“Mcfe”) for the year. 2009 results underscore our Company’s position as a low cost operator and confirm the quality and long-term visibility of our asset base.

“We are off to a great start in 2010. Projected production growth of 8% to 12%, combined with hedge positions already in place on approximately 60% of production, is expected to deliver another year of solid cash flow. In addition, we have a very strong balance sheet with current available borrowing capacity of $593 million that positions the Company to take advantage of growth opportunities. Our 2010 capital program is focused on development properties yet will be flexible to additional activity if we choose to pursue accelerated growth either through acquisition, exploration success, or if regulatory approvals are received at West Tavaputs.”

Natural gas and oil production totaled 89.7 billion cubic feet equivalent (“Bcfe”) in 2009 compared with 77.6 Bcfe in 2008. Including the effects of the Company’s hedging activities, the average realized sales price was $7.10 per Mcfe in 2009 compared with $7.81 per Mcfe in 2008. The Company’s 2009 hedging program increased its natural gas and oil revenues by $271.8 million, or $3.03 per Mcfe of production. For the fourth quarter 2009, production totaled 22.8 Bcfe, up 11% compared with 20.6 Bcfe in the fourth quarter of 2008, and the average realized price was $7.02 per Mcfe, up from $6.96 per Mcfe in the fourth quarter of 2008.

Proved reserves at year-end 2009 were 964.8 Bcfe, up 18% from 818.3 Bcfe at year-end 2008. Capital expenditures for 2009 totaled $406.4 million, down significantly from $601.1 million in 2008 as the Company aligned 2009 capital expenditures with discretionary cash flow.

Discretionary cash flow (a non-GAAP measure, see “Discretionary Cash Flow Reconciliation” below) was $459.6 million in 2009, or $10.21 per diluted common share, up $30.5 million compared with $429.1 million, or $9.53 per diluted common share, in 2008. The increase in 2009 is due to: a 16% increase in production; lower general and administrative expenses; lower cash operating costs, which included lower lease operating expense and lower production taxes; partially offset by a lower average realized price. For the fourth quarter of 2009, discretionary cash flow was $114.4 million, or $2.53 per diluted common share, up from $101.8 million, or $2.28 per diluted common share, in the fourth quarter of 2008. Fourth quarter 2009 results benefited from higher production, higher oil prices and certain lower per unit costs.

Net income was $50.2 million in 2009, or $1.12 per diluted common share, compared with $105.3 million, or $2.34 per diluted common share, in 2008. The decline in net income is driven by higher non-cash charges, primarily $43.7 million of unrealized losses on commodity derivatives. Net income for 2009 also includes: an impairment expense of $19.7 million related to sub-economic performing wells at the Company’s Yellow Jacket prospect in the Paradox Basin and to properties in the North Hill Creek field in the Uinta Basin; one-time benefits to production tax expenses of $5.0 million as a result of amended severance tax returns for 2004 through 2008; and, a gain on the sale of properties of $1.4 million. Adjusting for these items, tax effected, adjusted net income (a non-GAAP measure, see “Adjusted Net Income Reconciliation” below) was $82.7 million. Total dry hole expense for 2009 was $30.7 million, or $17.5 million after tax, and included interests in 14 wells in five exploration areas. Net income for the fourth quarter of 2009 was $12.5 million compared with $6.1 million in the fourth quarter of 2008. Adjusted net income was $20.3 million in the fourth quarter of 2009, nearly flat with $19.9 million in the fourth quarter of 2008.

DEBT AND LIQUIDITY

As of December 31, 2009, the Company had $5.0 million in outstanding borrowings on its revolving credit facility, which were entirely repaid in February 2010. The revolving credit facility has a borrowing base of $630.0 million and bank commitments totaling $592.8 million. Also at December 31, 2009, the Company had outstanding 5% Convertible Senior Notes in the principal amount of $172.5 million and 9.875% Senior Notes due 2016 in the principal amount of $250.0 million. The Company has significant liquidity available from cash flows from operations and the credit facility to fund its planned capital programs.

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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, 2009:

	Three Months ended December 31, 2009				Twelve Months ended December 31, 2009
Basin	Average Net Production (Mmcfe/d)	Wells Spud (gross)	Capital Expenditures (millions)		Average Net Production (Mmcfe/d)	Wells Spud (gross)	Capital Expenditures (millions)
Piceance	106	38	$	51.6	100	119	$	254.8	(1)
Uinta	81	4		13.7	88	20		93.7
Powder River (CBM)	37	16		2.5	33	40		13.9
Wind River	21	0		3.4	23	0		5.1
Paradox	2	0		2.7	1	5		25.2
Other	1	1		4.0	1	2		13.7
Total	248	59	$	77.9	246	186	$	406.4

⁽¹⁾ Includes $60 million for the acquisition of Cottonwood Gulch

Fourth quarter 2009 capital expenditures totaled $77.9 million and full year 2009 expenditures totaled $406.4 million, well within 2009 discretionary cash flow of $459.6 million. Expenditures for 2009 included: $329.3 million for drilling, exploration and development of natural gas and oil properties, $71.8 million for acquisitions of proved and unevaluated properties and other real estate, $3.2 million for geologic and geophysical costs and exploratory dry holes and abandonment, and $2.1 million for furniture, fixtures, equipment and other assets. The Company did not have any material divestitures in 2009.

Operating and Drilling Update

The Company currently has five rigs drilling, with three in the Piceance Basin, one at West Tavaputs and one at Blacktail Ridge. The 2010 drilling program will concentrate on growth at our key development areas.

Piceance Basin, Colorado

Gibson Gulch – Current net production is approximately 106 million cubic feet equivalent per day (MMcfe/d). During 2009, Piceance operations continued to realize improved operating efficiencies, driven primarily by the Company’s water management system, and improved drilling efficiencies, reflected by an average six days drilling time per well, down from nine days in 2008. In addition, the Company elected to process natural gas, which added on average $0.32 per Mcfe to the realized price company-wide for 2009. Piceance operations exemplify our Rocky Mountain expertise and offer strong margins due to low cost operations and the benefit to revenue related to liquids. In 2010, the Company plans to drill 120 to 130 wells in its Gibson Gulch program and realize year-over-year production growth of approximately 30% for the project. The Gibson Gulch program continues to be a key, lower risk development area for the Company and offers flexibility to adjust the number of active rigs dependent upon the Company’s capital strategy.

At December 31, 2009, the Company had an approximate 96% working interest in production from 532 gross wells in its Gibson Gulch program.

Cottonwood Gulch – In June 2009, the Company acquired a 90% working interest in 40,300 undeveloped acres in Cottonwood Gulch. The Company continues to participate in the mediation process for a lawsuit by environmental groups challenging the leases. The property has a signed Record of Decision for an Environmental Impact Statement and Resource Management Plan in effect with the Bureau of Land Management. The Company agreed to delay oil and gas activities during the mediation process.

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Uinta Basin, Utah

West Tavaputs – Current net production is approximately 66 MMcfe/d. The Company recommenced drilling in December 2009 with three wells and plans to drill and complete eight additional wells in the first half of 2010, as well as to complete eight wells from the 2009 program. During 2009, the Company continued to improve operating costs at West Tavaputs, primarily through the addition of a salt water disposal well that serves to better manage produced water. Results from 20-acre density wells on the Prickly Pear mesa continued to be positive and the Company expects to continue drilling this acreage with the increased density locations. During 2009, the Company worked closely with groups representing archeological, wildlife and wilderness interests in regards to the development of West Tavaputs. The Company believes it is close to resolution in addressing their interests and concerns and looks forward to working together with the Bureau of Land Management in obtaining the final Environmental Impact Statement and Record of Decision for full-field development of the West Tavaputs project, which is expected in the first half of 2010. The West Tavaputs program offers growth in the shallow Mesaverde and Wasatch zones as well as upside opportunity through the Mancos shale.

At December 31, 2009, the Company had an approximate 97% working interest in production from 166 gross wells in its West Tavaputs shallow and deep programs.

Blacktail Ridge/Lake Canyon – Current net production is approximately 629 barrels of oil equivalent per day (“Boepd”) from 9 wells. The Company drilled one well in 2009 and currently has a rig in the area and plans to participate in up to a 16-well program in 2010. The working interests in this area range from 19% to 100%.

Powder River Basin, Wyoming

Coal Bed Methane (CBM) – Current CBM net production is approximately 36 MMcf/d. The Company plans to participate in a 60 to 70 well program for 2010 beginning in the second half of the year when wildlife stipulations end. The Company drilled 40 wells in 2009 and production increased approximately 45% during the year, benefitting from continued dewatering of wells drilled earlier in addition to an extensive workover program. Development of this area requires dewatering of wells, which takes an average of six to 12 months.

At December 31, 2009, the Company had an approximate 73% working interest in production from 676 gross CBM wells.

Wind River Basin, Wyoming

Cave Gulch/Bullfrog/Other – Current net production from the area is approximately 21 MMcfe/d, including the Bullfrog 33-19 well that was recompleted in December 2009.

Paradox Basin, Colorado

Yellow Jacket – At the Yellow Jacket shale gas prospect (55% working interest), the Koskie 13H-27 well is currently producing 1.1 MMcfe/d from the Gothic shale at 400 psi tubing pressure. This well was completed with a substantially larger fracture stimulation than used on earlier well completions, which has produced better results. The Company will continue to monitor data from this well for the next few months and plans to commence its 2010 confirmation program in the second quarter of 2010 with a minimum of one well. This prospect includes approximately 308,600 gross, and 139,750 net, undeveloped acres plus approximately 178,600 gross, and 127,600 net, undeveloped acres in a similar shale gas prospect in the adjacent Green Jacket area.

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ADDITIONAL FINANCIAL INFORMATION

Guidance

As previously announced, the Company’s 2010 guidance (please reference “Forward-looking Statements” below) includes:

• Capital expenditures of $400 to $425 million before acquisitions

• Oil and natural gas production of 97 to 100 Bcfe

• Lease operating costs per Mcfe of $0.57 to $0.61

• Gathering and transportation costs per Mcfe of $0.75 to $0.80

• General and administrative expenses before non-cash stock-based compensation between $40 and $43 million

Commodity Hedges Update

It is the Company’s strategy to typically hedge 50% to 70% of production through basis to regional sales points for the next 12 months on a rolling basis. Hedging is intended to reduce the risks associated with unpredictable future commodity prices and to provide predictability for a portion of cash flows to support the Company’s capital expenditure program.

For 2010 and 2011, 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:

• For 2010, approximately 60.2 Bcfe at a weighted average blended floor price of $7.67 per Mcfe. These hedges are weighted more heavily through the third quarter of 2010 when seasonal natural gas prices tend to be lower.

• For 2011, approximately 34.8 Bcfe at a weighted average blended floor price of $6.72 per Mcfe.

As of February 18, 2010:

SWAPS & COLLARS

Period	Natural Gas/NGLs			Oil			Equivalent
	Volume MMBtu/d	Price $/MMBtu		Volume Bbl/d	Price $/Bbl		Volume Mmcfe	Price $/Mcfe
1Q10	185,315	$	6.85	966	$	79.65	15,684	$	7.73
2Q10	187,502	$	6.79	1,000	$	79.88	16,058	$	7.67
3Q10	187,464	$	6.79	1,000	$	79.88	16,231	$	7.66
4Q10	140,056	$	6.67	1,000	$	79.88	12,266	$	7.60
1Q11	122,500	$	6.31	—		—	10,023	$	6.94
2Q11	112,500	$	5.98	—		—	9,307	$	6.58
3Q11	112,500	$	5.98	—		—	9,409	$	6.58
4Q11	72,717	$	6.18	—		—	6,082	$	6.80

In addition, the Company has natural gas basis only hedges in place, none of which are currently in the money, including:

• For 2010: 12,940,000 MMBtu at an average differential of ($2.42) per MMBtu.

• For 2011: 7,300,000 MMBtu at an average differential of ($1.72) per MMBtu.

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FOURTH QUARTER AND YEAR-END 2009 WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held later this morning to discuss fourth quarter and year-end 2009 results. Please join Bill Barrett Corporation executive management at noon Eastern time/10:00 a.m. Mountain time for the live webcast, accessed atwww.billbarrettcorp.com, or join by telephone by calling 866-713-8566 (617-597-5325 international callers) with passcode 11510914. 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 26, 2010 at call-in number 888-286-8010 (617-801-6888 international) with passcode 79944965. The Company has also tentatively scheduled its 2010 earnings conference calls for May 4, August 3 and November 2, each at noon Eastern time/10:00 a.m. Mountain time.

UPCOMING EVENTS

Investor Conferences

Updated investor presentations are posted on the homepage of the Company’s website atwww.billbarrettcorp.com. None of the following conference presentations is webcast, but please check the website at 5:00 p.m. Mountain time the business day prior to the investor event for the most recent presentation.

Chief Financial Officer Bob Howard plans to present at the 2010 J.P Morgan Global High Yield and Leveraged Finance Conference on March 1, 2010 at 10:15 a.m. Eastern time.

President and Chief Operating Officer Joe Jaggers will participate in an E&P panel discussion at the Simmons & Company International Tenth Annual Energy Conference on March 3, 2010 at 11:00 a.m. Pacific time.

Chairman and Chief Executive Officer Fred Barrett plans to present at the Howard Weil 38^th Annual Energy Conference on March 22, 2010 at 4:20 p.m. Central time.

DISCLOSURE STATEMENTS

Reserve Disclosure

The Securities and Exchange Commission (“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 press release. The estimates are consistent with the guidelines outlined in the SPE/WPC/AAPG/SPEE Petroleum Resources Management System. The estimates are not prepared or reviewed by third party engineers and do not conform to SEC guidelines for estimating proved and possible reserves. Our probable and possible reserve estimate methodology differs from the new SEC guidelines including our use of commodity pricing. Rather than the SEC simple 12-month average of the 2009 first day of the month oil and gas prices, we use strip pricing, which we use internally for planning and budgeting purposes. Because these estimates were not prepared in accordance with SEC Guidelines, they may not be included in SEC filings. 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. The

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Company’s methods for estimating probable and possible reserves may differ from methods used by other companies to disclose non-proved reserves and our estimate may not be comparable to similarly titled measures provided by other companies. U.S. investors are urged to consider closely the disclosure in our Annual Report on Form 10-K, as filed for the year ended December 31, 2009, available on the Company’s website atwww.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 atwww.sec.gov.

Forward-Looking Statements

This press release contains forward-looking statements, including statements regarding projected results and future events. In particular, the Company is providing “2010 Guidance,” which contain projections for certain 2010 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, 2009 filed with the SEC, and other filings including our Current Reports on Form 8-K, 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, exploration drilling and testing results, the ability to receive drilling and other permits and regulatory approvals, the outcome of negotiation with the wilderness and other groups and government approval for development projects, governmental regulations, availability and costs of financing to fund the Company’s operations, availability of third party gathering, transportation and processing, market conditions, oil and gas price volatility, risks related to hedging activities including counterparty viability, 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, surface access and costs, uncertainties inherent in oil and gas production operations and estimating reserves, unexpected future capital expenditures, competition, risks associated with operating in one major geographic area, the success of the Company’s risk management activities, the speculative actual recovery of estimated potential volumes, 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. In addition, the Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances.

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 websitewww.billbarrettcorp.com.

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BILL BARRETT CORPORATION

Selected Operating Highlights

(Unaudited)

	Three Months Ended December 31,				Twelve Months Ended December 31,
	2009		2008		2009		2008
Production Data:
Natural gas (MMcf)		21,626		19,449		85,485		73,623
Oil (MBbls)		193		188		710		661
Combined volumes (MMcfe)		22,784		20,577		89,745		77,589
Daily combined volumes (MMcfed)		248		224		246		212
Average Prices (before the effects of realized hedges):
Natural gas (per Mcf)	$	4.98	$	4.09	$	3.86	$	7.05
Oil (per Bbl)		65.53		42.54		49.56		83.27
Combined (per Mcfe)		5.28		4.25		4.07		7.40
Average Prices (includes the effects of realized hedges):
Natural gas (per Mcf)	$	6.79	$	6.86	$	6.96	$	7.61
Oil (per Bbl)		67.76		51.88		59.03		69.55
Combined (per Mcfe)		7.02		6.96		7.10		7.81
Average Costs (per Mcfe):
Lease operating expense	$	0.51	$	0.58	$	0.52	$	0.57
Gathering, transportation and processing expense		0.73		0.47		0.63		0.51
Production tax expense (1)		0.06		0.34		0.15		0.57
Depreciation, depletion and amortization		2.82		2.75		2.83		2.66
General and administrative expense, excluding stock-based compensation (2)		0.38		0.50		0.42		0.52

(1) Production tax expense for the three and twelve months ended December 31, 2009 includes a one-time benefit to reduce prior periods as a result of an agreement with the State of Colorado regarding the calculation of severance taxes. Exclusive of the one-time items, the production tax expense per unit would have been $0.07 and $0.20 for the three- and twelve-month 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,
	2009			2008			2009			2008
(in thousands, except per share amounts)
Operating and Other Revenues:
Oil and gas production (1)	$	168,384		$	142,122		$	647,839		$	605,881
Commodity derivative gain (loss) (1)		(5,955	)		4,273			(54,567	)		7,920
Other		3,344			380			4,891			4,110
Total operating and other revenues		165,773			146,775			598,163			617,911
Operating Expenses:
Lease operating		11,571			11,927			46,492			44,318
Gathering, transportation and processing		16,596			9,596			56,608			39,342
Production tax (2)		1,347			7,005			13,197			44,410
Exploration		1,055			5,204			3,227			8,139
Impairment, dry hole costs and abandonment		22,451			26,447			52,285			32,065
Depreciation, depletion and amortization		64,114			56,518			253,573			206,316
General and administrative (3)		8,747			10,330			37,940			40,454
Non-cash stock-based compensation (3)		4,377			4,656			16,458			16,752
Total operating expenses		130,258			131,683			479,780			431,796
Operating Income		35,515			15,092			118,383			186,115
Other Income and Expense:
Interest and other income		144			364			438			2,036
Interest expense		(10,549	)		(5,678	)		(30,647	)		(19,717	)
Total other income and expense		(10,405	)		(5,314	)		(30,209	)		(17,681	)
Income before Income Taxes		25,110			9,778			88,174			168,434
Provision for Income Taxes		12,631			3,657			37,956			63,175
Net Income	$	12,479		$	6,121		$	50,218		$	105,259
Net Income Per Common Share
Basic	$	0.28		$	0.14		$	1.12		$	2.37
Diluted	$	0.28		$	0.14		$	1.12		$	2.34
Weighted Average Common Shares Outstanding
Basic		44,782			44,531			44,723			44,432
Diluted		45,276			44,637			45,036			45,037

(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 period indicated:

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2009			2008			2009			2008
Included in oil and gas production revenue:
Realized gains on cash flow hedges	$	49,070		$	54,560		$	282,734		$	31,900
Included in commodity derivative loss:
Realized gains (losses) on derivatives not designated cash flow hedges	$	(8,456	)	$	1,025		$	(10,902	)	$	62
Unrealized ineffectiveness gains (losses) recognized on derivatives designated cash flow hedges		149			3,682			(5,572	)		6,803
Unrealized gains (losses) on derivatives not designated cash flow hedges		2,352			(434	)		(38,093	)		1,055
Total commodity derivative gain (loss)	$	(5,955	)	$	4,273		$	(54,567	)	$	7,920

(2) Production tax expense for 2009 includes a one-time benefit to reduce prior periods as a result of an agreement with the State of Colorado regarding certain calculations 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, 2009		As of December 31, 2008
(in thousands)
Assets:
Cash and cash equivalents	$	54,405	$	43,063
Other current assets (1)		125,634		270,311
Property and equipment, net		1,659,260		1,561,819
Other noncurrent assets (1)		26,824		119,300
Total assets	$	1,866,123	$	1,994,493
Liabilities and Stockholders’ Equity:
Current liabilities (1)	$	153,292	$	225,794
Notes payable under bank credit facility		5,000		254,000
Senior notes (2)		238,478		—
Convertible senior notes		158,772		153,411
Other long-term liabilities (1)		282,026		262,055
Stockholders' equity		1,028,555		1,099,233
Total liabilities and stockholders’ equity	$	1,866,123	$	1,994,493

(1) At December 31, 2009, the estimated fair value of all of our commodity derivative instruments was a net asset of $51.5 million, comprised of: $58.5 million current assets; $17.2 million non-current assets; $9.4 million current liabilities; and $14.8 million non-current liabilities. This amount will fluctuate quarterly based on estimated future commodity prices.

(2) The 9.875% Senior Notes were issued at a 95.172% discount to par and have a principal amount of $250.0 million.

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BILL BARRETT CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2009			2008			2009			2008
(in thousands)
Operating Activities:
Net income	$	12,479		$	6,121		$	50,218		$	105,259
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		64,114			56,518			253,573			206,316
Impairment, dry hole costs and abandonment costs		22,451			26,447			52,285			32,065
Unrealized derivative loss (gain)		(2,501	)		(3,248	)		43,665			(7,858	)
Deferred income taxes		10,996			3,974			31,867			62,565
Excess tax benefit from option exercises		(52	)		—			(52	)		—
Stock compensation and other non-cash charges		4,675			4,957			17,750			18,117
Amortization of deferred financing costs		2,457			1,801			8,410			5,619
Loss (gain) on sale of properties		(1,352	)		2			(1,386	)		(1,132	)
Change in assets and liabilities:
Accounts receivable		(15,991	)		(15,568	)		3,854			(16,047	)
Prepayments and other assets		920			4,309			(922	)		(324	)
Accounts payable, accrued and other liabilities		7,133			(11,280	)		20,046			(7,908	)
Amounts payable to oil & gas property owners		8,523			(3,718	)		3,088			(5,142	)
Production taxes payable		(5,925	)		(7,556	)		(1,652	)		11,417
Net cash provided by operating activities	$	107,927		$	62,759		$	480,744		$	402,947
Investing Activities:
Additions to oil and gas properties, including acquisitions		(77,591	)		(183,670	)		(450,411	)		(568,445	)
Additions of furniture, equipment and other		(684	)		(2,795	)		(3,971	)		(4,752	)
Proceeds from sale of properties		1,034			51			3,748			2,405
Net cash used in investing activities	$	(77,241	)	$	(186,414	)	$	(450,634	)	$	(570,792	)
Financing Activities:
Proceeds from credit facility		—			80,000			100,000			147,300
Principal payments on credit facility		(28,000	)		—			(349,000	)		(167,300	)
Proceeds from issuance of senior convertible notes		—			—			—			172,500
Proceeds from issuance of 9.875% senior notes		—			—			237,930			—
Deferred financing costs		(62	)		(3	)		(6,502	)		(5,167	)
Proceeds from sale of common stock		252			11			880			4,082
Other		(2,022	)		(694	)		(2,076	)		(792	)
Net cash provided by (used in) financing activities	$	(29,832	)	$	79,314		$	(18,768	)	$	150,623
Increase (Decrease) in Cash and Cash Equivalents		854			(44,341	)		11,342			(17,222	)
Beginning Cash and Cash Equivalents		53,551			87,404			43,063			60,285
Ending Cash and Cash Equivalents	$	54,405		$	43,063		$	54,405		$	43,063

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BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow & Adjusted Net Income from Net Income

(Unaudited)

Discretionary Cash Flow Reconciliation

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2009			2008			2009			2008
(in thousands, except per share amounts)
Net Income	$	12,479		$	6,121		$	50,218		$	105,259
Adjustments to reconcile to discretionary cash flow:
Depreciation, depletion and amortization		64,114			56,518			253,573			206,316
Impairment, dry hole costs and abandonment costs		22,451			26,447			52,285			32,065
Exploration expense		1,055			5,204			3,227			8,139
Unrealized derivative loss (gain)		(2,501	)		(3,248	)		43,665			(7,858	)
Deferred income taxes		10,996			3,974			31,867			62,565
Stock compensation and other non-cash charges		4,675			4,957			17,750			18,117
Amortization of deferred financing and discount on convertible notes		2,457			1,801			8,410			5,619
Loss (gain) on sale of properties		(1,352	)		2			(1,386	)		(1,132	)
Discretionary Cash Flow	$	114,374		$	101,776		$	459,609		$	429,090
Per share, diluted	$	2.53		$	2.28		$	10.21		$	9.53
Per Mcfe	$	5.02		$	4.95		$	5.12		$	5.53

Adjusted Net Income Reconciliation

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2009			2008			2009			2008
(in thousands except per share amounts)
Net Income	$	12,479		$	6,121		$	50,218		$	105,259
Adjustments to net inome:
Unrealized derivative loss (gain)		(2,501	)		(3,248	)		43,665			(7,858	)
Impairment expense		19,654			25,322			19,654			25,322
Loss (gain) on sale of properties		(1,352	)		2			(1,386	)		(1,132	)
One time items:
Production tax expense		(187	)		—			(4,983	)		—
Subtotal Adjustments		15,614			22,076			56,950			16,332
Effective tax rate		50	%		37	%		43	%		38	%
Tax effected adjustments		7,807			13,820			32,461			10,206
Adjusted Net Income	$	20,286		$	19,941		$	82,679		$	115,465
Per share, diluted	$	0.45		$	0.45		$	1.84		$	2.56
Per Mcfe	$	0.89		$	0.97		$	0.92		$	1.49

The non-GAAP (Generally Accepted Accounting Principles) 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 easier 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)

	2009			2008			2007
($ in millions)
TOTAL CAPITAL EXPENDITURES	$	406.4		$	601.1		$	443.7
Furniture, fixtures and equipment and real estate		(3.7	)		(4.8	)		(4.9	)
Asset retirement obligation		(1.2	)		8.2			1.0
TOTAL COSTS INCURRED	$	401.6		$	604.5		$	439.8
TOTAL COSTS INCURRED DISCLOSURE
Exploration costs	$	185.4		$	342.9		$	250.7
Development costs		147.2			214.0			162.5
Acquisition costs:
Unproved properties		70.1			33.1			23.6
Proved properties		—			6.3			2.0
Asset retirement obligation		(1.2	)		8.2			1.0
TOTAL COSTS INCURRED		401.5			604.5			439.8
less: Asset retirement obligation		1.2			(8.2	)		(1.0	)
less: Proceeds received from JV partners (1)		—			—			(12.1	)
less: Deferred tax component of CH4 acquisition		—			—			1.6
less: Capitalized interest		(4.6	)		(2.0	)		(1.6	)
Adjusted costs incurred (2)	$	398.1		$	594.3		$	426.7
RESERVE ADDITIONS (Bcfe)
Extensions, discoveries and other additions		177.3			196.2			175.7
Revisions of previous estimates		101.5			146.4			34.8
Revisions of previous estimates based on price		(42.8	)		(7.3	)		19.4
Purchases of reserves in place		0.5			3.1			2.7
RESERVE ADDITIONS		236.5			338.4			232.6
SALES INFORMATION
Property sales (1)	$	3.7		$	2.4		$	84.4
Sales of reserves (Bcfe)		0.2			0.1			42.2

(1) The sum of proceeds from joint venture partners and property sales equals “Proceeds from sales of properties” from the Consolidated Statement of Cash Flows.

(2) Finding and developments cost is a non-GAAP metric commonly used in the exploration and production industry. The calculation presented by the Company on page 1 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. The quotient of $1.68 per Mcfe is slightly revised from the estimate of $1.69 per Mcfe provided on January 21, 2010.

13