Bill Barrett (BBG) 8-K Announces Big Growth in Oil Production, DJ Basin Expansion and Reduced Gas Drilling

EXHIBIT 99.1

Press Release

For immediate release

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

Bill Barrett Corporation Reports Second Quarter 2012 Results and

Announces Big Growth in Oil Production, DJ Basin Expansion and Reduced Gas Drilling

DENVER – August 2, 2012 – Bill Barrett Corporation (NYSE: BBG) today reported second quarter 2012 results and announced operational updates highlighted by:

• Oil and natural gas production growth, up 13% to 29.9 Bcfe; oil production up 92% over the second quarter of 2011 and up 32% sequentially.

• Discretionary cash flow (a non-GAAP measure, see below) of $94.7 million or $2.00 per diluted common share.

• Leasehold acquisitions totaling 31,070 net acres in the Denver-Julesburg (“DJ”) Basin, located in the Wattenberg Field northeast extension area (“northeast Wattenberg”), subsequent to quarter-end. Deal terms are not being disclosed.

• Successful Niobrara exploration well in the northeast Wattenberg, with a 24-hour peak IP rate of 798 barrels of oil equivalent per day (“Boe/d”) and an average 30-day rate of 517 Boe/d.

• Successful Shannon formation test well in the Powder River Deep with a 24-hour peak flowing IP rate of 523 Boe/d and 30-day average rate of 429 Boe/d.

• Reduction of development capital allocated to the Piceance Basin, cutting drilling activity from two rigs to zero.

Chairman, Chief Executive Officer and President Fred Barrett commented: “In the second quarter we delivered sizable growth in oil production, up 32% from the first quarter and positioning the Company to meet targeted 75-80% oil production growth for the year. We are also pleased to report new exploration catalysts and expansion of the DJ Basin program. The second quarter was again challenging due to low commodity prices, with May regional natural gas prices hitting a low not seen since September 2008 and NGL prices declining approximately 40% from January to June. In this environment, we continue to focus on building the oil component of our portfolio. We continue to execute in the Uinta Oil Program, and in the DJ we are quickly building a scalable oil play highlighted this quarter by positive exploration results and the acquisition of sizable, contiguous acreage positions adjacent to Wattenberg.

“Importantly, we remain attentive to total capital expenditures, both in keeping total expenditures within an acceptable level compared to expected cash flows and directing our capital to our highest return programs. As a result of the significant decline in NGL prices as well as continued low natural gas prices, we have cut all drilling in Gibson Gulch and have added one rig to the DJ program, which generates some of our best returns. The net effect of these changes will reduce 2012 development capital by approximately $40 million and reduce the 2013 capital expenditure run-rate by approximately $100 million. The Company will maintain flexibility and continue to consider further capital reallocation as it optimizes activities among the Uinta Oil Program and its sizable position in the DJ Basin Niobrara play.

“We aim to drive exceptional oil growth in 2012 and 2013 while taking prudent measures to narrow the funding requirements over the same time period. In parallel, as we said we would do, we will continue to manage our portfolio to enhance value and strengthen our financial position, and we are off to a great start by completing the recent lease financing of certain infrastructure.”

OPERATING AND FINANCIAL RESULTS

Oil and natural gas production totaled 29.9 billion cubic feet equivalent (“Bcfe”) in the second quarter of 2012, up 13% from 26.5 Bcfe in the second quarter of 2011. The Company’s 2012 capital program is targeting 75-80% growth in oil production. Second quarter average oil production of 6,972 barrels of oil per day (“Bbls/d”) is up 92% compared with the second quarter of 2011 and oil production is up 78% year-to-date.

Realized pricing in the second quarter of 2012 remained strong despite low natural gas prices in May of $1.75 per million British thermal units (“MMBtu”) (May CIG IFERC first of month price.) The average realized sales price was $5.97 per thousand cubic feet equivalent (“Mcfe”), which benefitted from increased oil production and included an $0.80 per Mcfe benefit from NGL-related pricing and a $1.33 per Mcfe benefit from realized hedges. The average realized price is down from $7.01 per Mcfe in the second quarter of 2011, due to lower natural gas prices partially offset by slightly higher oil prices. The average realized natural gas price in the second quarter was $4.77 per Mcf and the average realized oil price was $84.86 per barrel (“Bbl”). (See “Selected Operating Highlights” below for more detail.)

In the second quarter of 2012, oil and NGLs made up 30% of the total sales volumes (see “Disclosure Statements” below) and 59% of pre-hedge revenues. Sales volumes, including the breakdown of natural gas production into quantities sold as dry gas and quantities that receive the benefit of NGL-related pricing from the Company’s election to process natural gas, where it is able to do so, are as follows:

	2Q11		3Q11		4Q11		1Q12		2Q12
Reported Production Volumes:
Oil (Bbls/d)		3,642		4,304		5,066		5,286		6,972
Natural gas, including NGLs (MMcf/d)		269		279		286		278		287
Reported Realized Prices:
Oil (per Bbl)	$	82.40	$	79.79	$	81.48	$	88.42	$	84.86
Natural gas, including NGLs (per Mcf)	$	6.47	$	6.48	$	6.26	$	5.46	$	4.77
Sales* Volumes:
Oil (Bbls/d)		3,642		4,304		5,066		5,286		6,972
Natural gas sold as dry gas (MMcf/d)		234		250		261		257		262
NGLs (Bbls/d)		11,024		11,571		11,476		11,985		11,439

* See “Disclosure Statements” below.

Discretionary cash flow (a non-GAAP measure, see “Discretionary Cash Flow Reconciliation” below) in the second quarter of 2012 was $94.7 million, or $2.00 per diluted common share, down from $122.8 million in the second quarter of 2011. The decline in discretionary cash flow is primarily due to lower realized natural gas prices and increased interest expenses, partially offset by higher production volumes. Discretionary cash flow was $193.6 million for the first half of 2012 compared with $227.5 million for the first half of 2011.

Net income in the second quarter of 2012 was $3.3 million, or $0.07 per diluted common share, down from $32.6 million, or $0.69 per diluted common share, in the second quarter of 2011. Net income was affected by the same factors as discretionary cash flow as well as higher depreciation, depletion and amortization expense, partially offset by higher non-cash gains on derivatives. Impairment charges in the second quarter of 2012 were $18.3 million and were primarily related to the effect of unfavorable market conditions on certain exploration properties.

Net income for the first half of 2012 was $39.2 million compared with $47.9 million in the first half of 2011.

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Adjusted net income for the second quarter of 2012 (a non-GAAP measure, see “Adjusted Net Income Reconciliation” below) was a loss of $2.4 million, or ($0.05) per diluted common share, compared with $27.6 million, or $0.59 per diluted common share, in the second quarter of 2011. Adjusted net income for the first half of 2012 was $7.3 million compared with $46.6 million in the first half of 2011. 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.

DEBT AND LIQUIDITY

At June 30, 2012, the Company’s revolving credit facility had an outstanding balance of $75.0 million on a borrowing base of $900.0 million. After deducting an outstanding letter of credit for $26.0 million, borrowing capacity was $799.0 million. At June 30, 2012, the Company had outstanding a total of $1,150.3 million principal amount in senior debt with no significant maturity before 2016.

Subsequent to quarter-end, the Company completed, or is in the process of completing, lease financing agreements for new and existing compressors and related facilities owned by the Company in the West Tavaputs and Gibson Gulch areas. The funding is expected to total $106 million, with $88 million completed to date. The agreements are with several financial institutions and have an implicit interest rate of less than 3.5% per annum.

OPERATIONS

Production, Wells Spud and Capital Expenditures

The following table lists production, wells spud and total capital expenditures by basin for the three and six months ended June 30, 2012:

	Three Months ended June 30, 2012						Six Months ended June 30, 2012
Basin	Average Net Production (MMcfe/d)		Wells Spud (gross)		Capital Expenditures (millions)		Average Net Production (MMcfe/d)		Wells Spud (gross)		Capital Expenditures (millions)
Uinta:
Uinta Oil Program		28		44	$	74.4		26		65	$	151.4
West Tavaputs		101		4		30.3		101		16		77.9
Piceance		145		39		79.5		140		85		148.6
Denver-Julesburg		9		8		28.7		7		10		56.3
Powder River (CBM)		31		0		0.0		32		2		0.1
Other		15		1		34.4		13		3		48.0
Total		329		96	$	247.3		319		181	$	482.3

Operating and Drilling Update

The Company anticipates drilling or participating in approximately 255 gross/190 net development wells in 2012. The Company’s development program is focused on growth in oil production and reserves. The Company’s current drilling program includes five rigs in the Uinta Oil Program and three rigs in the DJ Basin Niobrara oil play.

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Uinta Basin, Utah

Uinta Oil Program (Blacktail Ridge, Lake Canyon, East Bluebell and South Altamont) –

Current net production is approximately 5,200 Boe/d. The Company currently has five drilling rigs operating in the area and expects to drill up to 67 gross/47 net operated wells in the area in 2012, plus participate in approximately 40 wells operated by its partner in Lake Canyon. During 2012, the Company seeks to increase recoveries and optimize development of this vast, oil-rich resource base. The Company will continue its vertical development program and renew drilling of its horizontal Uteland Butte program. The Company recently drilled horizontal tests in the Black Shale and Wasatch horizons as well as a vertical test of the Mahogany with results expected in the fall of 2012.

At June 30, 2012, the Company had an approximate 71% working interest in production from 160 gross wells. Depending upon elections to participate by partners, the Company expects to have an approximate 50% average working interest in its 2012 drilling program. The working interests for wells in the 2012 program range from 19% to 100%.

West Tavaputs – Current net production is approximately 106 million cubic feet equivalent per day (MMcfe/d). Due to low natural gas prices, the Company has suspended drilling at this dry natural gas program. This program remains one of the Company’s largest, long-term development assets.

At June 30, 2012, the Company had an approximate 97% working interest in production from 300 gross wells in its West Tavaputs shallow and deep programs.

Denver-Julesburg Basin, Colorado and Wyoming

Wattenburg and Chalk Bluffs – Current net production is approximately 1,350 Boe/d. The rapidly growing DJ Program includes development drilling, successful delineation drilling, and improving production through re-fracture stimulation of existing wells. The Company currently has three active rigs in the area, and the full year 2012 program was recently expanded and is expected to include approximately 33 gross/23 net operated wells, all of which will be horizontal and target the “B” and/or “C” bench of the Niobrara formation.

Year-to-date, the Company has added two rigs and 41,400 net acres to its growing DJ Basin program, more than doubling its position. During the second quarter of 2012, the Company initiated drilling on its Briggsdale acreage in northeast Wattenberg. The Niobrara test was drilled to approximately 6,400 feet with a 4,500 foot lateral and 18 fracture stimulation stages and had a 24-hour peak IP rate of 798 Boe/d and average 30-day rate of 517 Boe/d. The Company has completed three additional wells in the Chalk Bluffs and northeast Wattenberg that are currently being evaluated. Including recently acquired leaseholds, the Company has a total of approximately 74,820 net/119,230 gross acres in the play, including approximately 39,040 net acres in the northeast Wattenberg, 13,360 net acres in other portions of the core Wattenberg Field and 22,420 net acres in the Chalk Bluffs/northern Colorado/Wyoming exploration areas.

At June 30, 2012, the Company had an approximate 90% working interest in production from 222 gross wells.

Piceance Basin, Colorado

Gibson Gulch – Current net production is approximately 148 MMcfe/d. As a result of the significant decline in NGL prices starting in the second quarter of 2012, the Company is suspending drilling activity in this program. A portion of our Gibson Gulch natural gas production is processed, at the election of the Company, exposing the Company to NGL pricing. The

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incremental benefit to production revenues related to natural gas liquids was $0.80 per Mcfe to the Company-wide realized price in the second quarter of 2012, down from $1.14 per Mcfe in the first quarter of 2012. 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 and commodity prices. Gibson Gulch operations benefit from low operating costs and revenue contributions from oil and NGLs.

At June 30, 2012, the Company had an approximate 98% working interest in production from 900 gross wells in its Gibson Gulch program.

Exploration Update

Powder River Deep, Powder River Basin, Wyoming –The Company completed a successful horizontal exploration well (working interest 75%) testing the Shannon formation that had a 24-hour peak flowing IP rate of 523 Boe/d and a 30-day average rate of 429 Boe/d, which was 95% oil. The well was drilled to a depth of approximately 8,800 feet and completed with a 4,000 foot lateral and 18 fracture stimulation stages. The Company plans to drill at least three additional horizontal wells in the Powder River Basin by year-end, including tests to the Sussex and Frontier formations, as well as participate in several non-operated tests. The Company has approximately 144,150 gross/64,230 net acres in the prospect.

San Juan Basin, New Mexico –The Company is conducting a 3-dimensional seismic survey in this area and intends to drill up to two horizontal wells by year-end targeting oil in the Tocito-Gallup-Niobrara at approximately 6,500 feet. The Company has approximately 36,000 net acres (including acreage to be earned) in the prospect.

Southern Alberta Basin, Montana –The Company has completed a 3-dimensional seismic survey of the area and, in the third quarter of 2012, intends to drill a horizontal well targeting oil in the Banff-Bakken formation at approximately 3,200 feet. The Company has approximately 94,000 net acres in the prospect.

ADDITIONAL FINANCIAL INFORMATION

Guidance

The Company’s 2012 guidance (please reference “Forward-Looking Statements” below) is as follows. The Company may update guidance as business conditions warrant:

• Capital expenditures of $850 to $900 million, including leasehold acquisitions year-to-date.

• Oil and natural gas production of 118 to 122 Bcfe, up 10% to 14% from 2011, narrowed from 116 to 122 Bcfe.

• Lease operating costs per Mcfe of $0.60 to $0.65, unchanged.

• Gathering, transportation and processing costs per Mcfe of $0.92 to $0.97, unchanged.

• General and administrative expenses before non-cash stock-based compensation cost per Mcfe of $0.45 to $0.49, unchanged.

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.

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For the remainder of 2012 and 2013, 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 the second half of 2012, approximately 41.6 Bcfe, or approximately 70% of production, at a weighted average blended floor price of $6.58 per Mcfe. Approximately 70% of natural gas, 60% of oil and 20% of NGL production/sales is hedged.

• For 2013, approximately 56.1 Bcfe at a weighted average blended floor price of $6.77 per Mcfe. Based on current sales estimates, approximately 55% of natural gas, 30% of oil and 5% of NGL production/sales is hedged.

As of July 20, 2012:

SWAPS & COLLARS
Period	Natural Gas / NGLs				Oil				Equivalent
	Volume MMBtu/d		Price $MMBtu		Volume Bbl/d		Price $/Bbl		Volume Mmcfe		Price $/Mcfe
3Q12		229,089	$	4.39		5,300	$	101.02		22,086	$	6.42
4Q12		198,777	$	4.52		5,300	$	101.02		19,551	$	6.75
1Q13		172,557	$	3.85		5,100	$	99.45		16,872	$	6.25
2Q13		127,529	$	3.97		5,100	$	99.45		13,335	$	6.91
3Q13		127,501	$	3.96		5,100	$	99.45		13,479	$	6.91
4Q13		114,240	$	4.02		5,100	$	99.45		12,370	$	7.18

In addition, the Company has natural gas basis only hedges in place for 2012 of 20,000 MMBtu/d at a basis differential price of ($1.22) per MMBtu. These hedges are not in the money.

SECOND QUARTER 2012 RESULTS WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held later this morning to discuss second quarter 2012 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 800-215-2410 (617-597-5410 international callers) with passcode 53483447. The webcast will remain available on the Company’s website for approximately 30 days, and a replay of the call will be available through August 9, 2012 at call-in number 888-286-8010 (617-801-6888 international) with passcode 26026826. The Company also has tentatively scheduled its remaining 2012 earnings conference calls for August 2 and November 1, 2012, typically at noon Eastern time/10:00 a.m. Mountain time.

QUARTERLY REPORT ON FORM 10-Q

The Company plans to file today its Quarterly Report on Form 10-Q for the quarter ended June 30, 2012. The 10-Q will be posted to the Company’s website atwww.billbarrettcorp.com and found under “SEC Reports”.

UPCOMING EVENTS

Updated investor presentations will be posted to the homepage of the Company’s website atwww.billbarrettcorp.com for each event below. Webcast events will also be accessible on the homepage of the Company’s website:

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Investor Conferences

Chairman, Chief Executive Officer and President Fred Barrett will present at the Enercom Oil and Gas Conference on August 15, 2012 at 3:35 p.m. Mountain time. The event will be webcast. The presentation for this event will be posted at 5:00 Mountain time on Monday, August 13, 2012.

Chairman, Chief Executive Officer and President Fred Barrett will present at the Barclays CEO Energy Conference on September 6, 2012 at 7:45 a.m. Eastern time. The event will be webcast. The presentation for this event will be posted at 5:00 Mountain time on Tuesday, September 4, 2012.

DISCLOSURE STATEMENTS

Calculation of Natural Gas Liquids as a Percent of Sales Volumes

The Company’s natural gas production is based on wellhead volumes and its natural gas revenue includes the incremental revenue benefit from third party purchasers and processors when the company elects to receive NGL values from certain volumes of natural gas. Many oil and gas producing companies report NGL volumes and revenues separately from natural gas volumes and revenues. In order to provide a metric that is comparable to other oil and gas production companies, the Company is providing the percentage of total company sales volumes by product including oil, natural gas and NGL revenues received from our gas purchasers or processors. The NGL volumes identified by our gas purchasers or processors are converted to an oil equivalent based on 42 gallons per barrel and compared to overall gas equivalent production based on a 1 barrel to 6 Mcf ratio.

Forward-Looking Statements

This press release contains forward-looking statements, including statements regarding projected results and future events. In particular, the Company is providing “2012 Guidance,” which contains projections for certain 2012 operational and financial results, as well as planned drilling activity. 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, 2011 filed with the SEC, 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 that may affect these forward-looking statements.

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, oil, NGL and natural gas price volatility, the ability to receive drilling and other permits and rights-of-way, regulatory approvals, economic and competitive conditions, legislative or regulatory changes including initiatives related to hydraulic fracturing, derivative and hedging activities, declines in the values of our oil and gas properties resulting in impairments, changes in estimates of proved reserves, higher than expected costs and expenses, exploration and development drilling and testing results, compliance with environmental and other regulations, costs and availability of third party facilities for gathering, processing, refining and transportation, performance of acquired properties, 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, unexpected future capital expenditures, 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

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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.

ABOUT BILL BARRETT CORPORATION

Bill Barrett Corporation (NYSE: BBG), headquartered in Denver, Colorado, explores for and develops oil and natural gas 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 June 30,				Six Months Ended June 30,
			2012		2011		2012		2011
Production Data:
Natural gas (MMcf)				26,094		24,506		51,412		45,941
Oil (MBbls)				634		331		1,115		628
Combined volumes (MMcfe)				29,898		26,492		58,102		49,709
Daily combined volumes (Mmcfe/d)				329		291		319		275
Average Prices (before the effects of realized hedges):
Natural gas (per Mcf)	(1	)	$	3.40	$	5.91	$	3.83	$	5.77
Oil (per Bbl)				78.89		89.40		83.62		85.52
Combined (per Mcfe)				4.64		6.59		5.00		6.41
Average Realized Prices (after the effects of realized hedges):
Natural gas (per Mcf)	(1	)	$	4.77	$	6.47	$	5.11	$	6.57
Oil (per Bbl)				84.86		82.40		86.39		80.53
Combined (per Mcfe)				5.97		7.01		6.18		7.09
Average Costs (per Mcfe):
Lease operating expense			$	0.64	$	0.53	$	0.65	$	0.55
Gathering, transportation and processing expense				0.87		0.81		0.92		0.82
Production tax expense				0.23		0.37		0.23		0.37
Depreciation, depletion and amortization				2.87		2.60		2.75		2.70
General and administrative expense, excluding non-cash stock-based compensation	(2	)		0.38		0.41		0.43		0.48

(1) Natural gas average prices include the effect of NGL revenues.

(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						Six Months Ended
			June 30,						June 30,
			2012			2011			2012			2011
(in thousands, except per share amounts)
Operating and Other Revenues:
Oil and gas production	(1	)	$	159,490		$	194,328		$	336,532		$	366,525
Other				862			3,021			2,996			3,259
Total operating and other revenues				160,352			197,349			339,528			369,784
Operating Expenses:
Lease operating				19,030			14,075			37,668			27,374
Gathering, transportation and processing				25,862			21,338			53,214			40,674
Production tax				6,892			9,781			13,099			18,347
Exploration				4,062			697			4,501			2,048
Impairment, dry hole costs and abandonment				21,075			1,093			21,639			1,376
Depreciation, depletion and amortization				85,942			68,847			160,025			134,241
General and administrative	(2	)		11,314			10,739			25,114			23,806
Non-cash stock-based compensation	(2	)		3,722			4,018			8,362			8,647
Total operating expenses				177,899			130,588			323,622			256,513
Operating Income/ (Loss)				(17,547	)		66,761			15,906			113,271
Other Income and Expense:
Interest income and other income				113			102			1,676			165
Interest expense				(23,912	)		(12,321	)		(45,502	)		(24,363	)
Commodity derivative gain (loss)	(1	)		47,024			(2,907	)		91,771			(14,019	)
Total other income and expense				23,225			(15,126	)		47,945			(38,217	)
Income before Income Taxes				5,678			51,635			63,851			75,054
Provision for Income Taxes				2,380			18,999			24,660			27,203
Net Income			$	3,298		$	32,636		$	39,191		$	47,851
Net Income Per Common Share
Basic			$	0.07		$	0.70		$	0.83		$	1.03
Diluted			$	0.07		$	0.69		$	0.83		$	1.02
Weighted Average Common Shares Outstanding
Basic				47,202			46,416			47,143			46,255
Diluted				47,245			47,108			47,335			46,929

(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:

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
Included in oil and gas production revenue:
Certain realized gains on hedges	$	20,798	$	19,776		$	46,263	$	47,699
Included in commodity derivative gain (loss):
Realized gain (loss) on derivatives not designated as cash flow hedges	$	18,916	$	(8,590	)	$	22,719	$	(13,994	)
Unrealized ineffectiveness gain recognized on derivatives designated as cash flow hedges		—		888			—		1,050
Unrealized gain (loss) on derivatives not designated as cash flow hedges		28,108		4,795			69,052		(1,075	)
Total commodity derivative gain (loss)	$	47,024	$	(2,907	)	$	91,771	$	(14,019	)

(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 Condensed Balance Sheets

(Unaudited)

			As of June 30, 2012		As of December 31, 2011
(in thousands)
Assets:
Cash and cash equivalents			$	20,834	$	57,331
Other current assets	(1	)		181,795		189,012
Property and equipment, net				2,700,032		2,406,764
Other noncurrent assets				52,785		34,823
Total assets			$	2,955,446	$	2,687,930
Liabilities and Stockholders’ Equity:
Current liabilities	(1	)	$	199,651	$	233,198
Notes payable to bank				75,000		70,000
Senior notes				1,041,973		641,198
Convertible senior notes				25,344		171,042
Other long-term liabilities	(1	)		378,096		353,654
Stockholders’ equity				1,235,382		1,218,838
Total liabilities and stockholders’ equity			$	2,955,446	$	2,687,930

(1) At June 30, 2012, the estimated fair value of all of our commodity derivative instruments was a net asset of $106.1 million, comprised of: $84.1 million current assets; $22.1 million non-current assets; and ($0.1) 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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
(in thousands)
Operating Activities:
Net income	$	3,298		$	32,636		$	39,191		$	47,851
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		85,942			68,847			160,025			134,241
Impairment, dry hole costs and abandonment expense		21,075			1,093			21,639			1,376
Unrealized derivative (gain)\loss		(28,108	)		(5,683	)		(69,052	)		25
Deferred income taxes		2,380			18,999			24,660			27,203
Stock compensation and other non-cash charges		4,318			5,254			7,640			10,345
Amortization of debt discounts and deferred financing costs		1,685			3,251			5,002			6,420
Gain on sale of properties		—			(2,288	)		—			(2,009	)
Change in assets and liabilities:
Accounts receivable		2,929			(18,415	)		18,136			(22,114	)
Prepayments and other assets		(7,257	)		(1,860	)		(6,066	)		2,069
Accounts payable, accrued and other liabilities		3,581			13,010			(8,853	)		(3,314	)
Amounts payable to oil & gas property owners		(2,106	)		8,365			(5,383	)		7,461
Production taxes payable		(5,293	)		319			(7,695	)		1,685
Net cash provided by operating activities	$	82,444		$	123,528		$	179,244		$	211,239
Investing Activities:
Additions to oil and gas properties, including acquisitions		(229,901	)		(278,630	)		(460,059	)		(383,802	)
Additions of furniture, equipment and other		(1,912	)		(2,052	)		(4,241	)		(2,772	)
Proceeds from sale of properties and other investing activities		246			2,204			134			1,860
Net cash used in investing activities	$	(231,567	)	$	(278,478	)	$	(464,166	)	$	(384,714	)
Financing Activities:
Proceeds from debt		75,000			145,000			525,000			145,000
Principal payments on debt		—			—			(267,156	)		—
Deferred financing costs and other		(737	)		(129	)		(10,087	)		(3,437	)
Proceeds from stock option exercises		—			8,725			668			13,078
Net cash provided by financing activities	$	74,263		$	153,596		$	248,425		$	154,641
Decrease in Cash and Cash Equivalents		(74,860	)		(1,354	)		(36,497	)		(18,834	)
Beginning Cash and Cash Equivalents		95,694			41,210			57,331			58,690
Ending Cash and Cash Equivalents	$	20,834		$	39,856		$	20,834		$	39,856

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BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow & Adjusted Net Income

(Unaudited)

Discretionary Cash Flow Reconciliation

	Three Months Ended  June 30,						Six Months Ended  June 30,
	2012			2011			2012			2011
(in thousands, except per share amounts)
Net Income	$	3,298		$	32,636		$	39,191		$	47,851
Adjustments to reconcile to discretionary cash flow:
Depreciation, depletion and amortization		85,942			68,847			160,025			134,241
Impairment, dry hole and abandonment expense		21,075			1,093			21,639			1,376
Exploration expense		4,062			697			4,501			2,048
Unrealized derivative (gain)/loss		(28,108	)		(5,683	)		(69,052	)		25
Deferred income taxes		2,380			18,999			24,660			27,203
Stock compensation and other non-cash charges		4,318			5,254			7,640			10,345
Amortization of debt discounts and deferred financing costs		1,685			3,251			6,603			6,420
Gain on extinguishment of debt		—			—			(1,601	)		—
Gain on sale of properties		—			(2,288	)		—			(2,009	)
Discretionary Cash Flow	$	94,652		$	122,806		$	193,606		$	227,500
Per share, diluted	$	2.00		$	2.61		$	4.09		$	4.85
Per Mcfe	$	3.17		$	4.64		$	3.33		$	4.58

Adjusted Net Income Reconciliation

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
(in thousands except per share amounts)
Net Income	$	3,298		$	32,636		$	39,191		$	47,851
Adjustments to net income:
Unrealized derivative (gain)/loss		(28,108	)		(5,683	)		(69,052	)		25
Impairment expense		18,337			—			18,337			—
Gain on sale of properties		—			(2,288	)		—			(2,009	)
One time items:
Gain on extinguishment of debt		—			—			(1,601	)		—
Subtotal Adjustments		(9,771	)		(7,971	)		(52,316	)		(1,984	)
Effective tax rate		42	%		37	%		39	%		36	%
Tax effected adjustments		(5,667	)		(5,022	)		(31,913	)		(1,270	)
Adjusted Net Income (loss)	$	(2,369	)	$	27,614		$	7,278		$	46,581
Per share, diluted	$	(0.05	)	$	0.59		$	0.15		$	0.99
Per Mcfe	$	(0.08	)	$	1.04		$	0.13		$	0.94

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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