Exhibit 99.1

 

						Press Release

For immediate release

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

Bill Barrett Corporation Reports Third Quarter 2012 Results Highlighting Continued

Execution of Oil Programs and Positive Drilling Results

DENVER – October 31, 2012 – Bill Barrett Corporation (NYSE: BBG) today reported third quarter 2012 results and announced operational updates highlighted by:

 

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Total oil and natural gas production growth, up 12% to 31.3 billion cubic feet equivalent (“Bcfe”) compared with the third quarter of 2011.

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Oil production up 80% over the third quarter of 2011 and up 13% sequentially.

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Discretionary cash flow (a non-GAAP measure, see below) of $2.24 per diluted common share, or $105.8 million, up 12% sequentially.

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Successful 4-well pad in Northeast Wattenberg, with per well average 24-hour peak initial production (“IP”) rate of 712 barrels of oil equivalent per day (“Boe/d”) and a per well average 30-day rate of 407 Boe/d.

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Particularly strong wells in the Uinta Oil Program (“UOP”) East Bluebell area where four recent vertical wells averaged more than 1,000 Boe/d 24-hour peak IP rates and 476 Boe/d 30-day rates.

Chairman, Chief Executive Officer and President Fred Barrett commented: “We continue on trend delivering sizable growth in oil production and realizing stronger cash flows. During the third quarter of 2012, we had eight rigs actively drilling our core oil programs in the Denver-Julesburg (“DJ”) and Uinta Basins, increasing oil production 80% from the third quarter of 2011 and 13% from last quarter.

“Drilling in these areas continues to demonstrate the potential of these oil assets with particularly strong results from recent Uinta Oil Program vertical wells and the DJ Northeast Wattenberg horizontal pad drilling. Importantly, we believe our drilling programs in the Uinta and DJ, as well as nearby industry activity, are helping us successfully delineate our increased acreage positions in both basins, growing our location inventories, reserves and the value of each of these core programs.

“In parallel, our confidence continues to grow as we see success to date in our exploratory Powder River Basin oil program with our recent Shannon and Sussex wells, and we are on track to continue additional horizontal exploration drilling in the Powder River, Southern Alberta and San Juan Basins through the fourth quarter.

“As we look ahead, the Company is poised to drive exceptional oil production growth in 2012 and 2013, in turn driving cash flow growth from these higher return programs. We intend to continue building our oil programs and reserves through drilling and opportunistic leasehold acquisitions. We stand committed to financial strength and flexibility as we reduce our funding requirements over the coming year and remain prudent with our capital expenditures.”

OPERATING AND FINANCIAL RESULTS

Oil and natural gas production totaled 31.3 Bcfe in the third quarter of 2012, up 12% from 28.0 Bcfe in the third quarter of 2011. The Company’s 2012 capital program is targeting 75-80% growth in oil production. Third quarter average oil production of 7,766 barrels of oil per day (“Bbls/d”) is up 80% compared with the third quarter of 2011 and oil production is up 79% year-to-date.

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Realized pricing in the third quarter of 2012 remained strong despite low natural gas and ethane prices. The average realized sales price was $6.15 per thousand cubic feet equivalent (“Mcfe”), which benefited from increased oil production and included a $0.75 per Mcfe benefit from NGL-related pricing and a $1.05 per Mcfe benefit from realized hedges. The average realized price is down from $7.06 per Mcfe in the third quarter of 2011 due to lower natural gas and NGL prices partially offset by slightly higher post-hedge oil prices. The average realized natural gas price in the third quarter was $4.90 per Mcf, including the benefit from NGL-related sales volumes, and the average realized oil price was $84.08 per barrel (“Bbl”). (See “Selected Operating Highlights” below for more detail.)

In the third quarter of 2012, oil and NGLs made up 29% of the total sales volumes (see “Disclosure Statements” below) and 56% 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:

 

		3Q11				4Q11				1Q12				2Q12				3Q12
Reported Production Volumes:
Oil (Bbls/d)			4,304				5,066				5,286				6,972				7,766
Natural gas, including NGLs (MMcf/d)			279				286				278				287				294
Reported Realized Prices:
Oil (per Bbl)		$	79.79			$	81.48			$	88.42			$	84.86			$	84.08
Natural gas, including NGLs (per Mcf)		$	6.48			$	6.26			$	5.46			$	4.77			$	4.90
Sales* Volumes:
Oil (Bbls/d)			4,304				5,066				5,286				6,972				7,766
Natural gas sold as dry gas (MMcf/d)			250				261				257				262				265
NGLs (Bbls/d)			11,571				11,476				11,985				11,439				10,341

 

*	See “Disclosure Statements” below.

Discretionary cash flow (a non-GAAP measure, see “Discretionary Cash Flow Reconciliation” below) in the third quarter of 2012 was $105.8 million, or $2.24 per diluted common share, down from $125.9 million in the third 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 and lower cash operating costs. Discretionary cash flow was $299.4 million for the first nine months of 2012 compared with $353.4 million for the first nine months of 2011.

Net income in the third quarter of 2012 was a loss of $52.6 million, or ($1.11) per diluted common share, down from income of $20.6 million, or $0.43 per diluted common share, in the third quarter of 2011. Net income was affected by the same factors as discretionary cash flow as well as higher depreciation, depletion and amortization expense, a commodity derivative loss versus a gain in the year ago period and a higher impairment, dry hole and abandonment expense. Impairment charges in the third quarter of 2012 were $18.8 million and primarily related to the effect of unfavorable results on certain natural gas exploration properties. Dry hole expenses in the third quarter of 2012 were $15.6 million and related to two unsuccessful natural gas exploration wells in the Paradox Basin. Net income for the first nine months of 2012 was a loss of $13.4 million compared with income of $68.5 million in the first nine months of 2011.

 

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Adjusted net income for the third quarter of 2012 (a non-GAAP measure, see “Adjusted Net Income Reconciliation” below) was a loss of $9.7 million, or ($0.20) per diluted common share, compared with income of $16.8 million, or $0.35 per diluted common share, in the third quarter of 2011. Adjusted net income for the first nine months of 2012 was a loss of $2.7 million compared with income of $63.4 million in the first nine months 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 September 30, 2012, the Company’s revolving credit facility had an outstanding balance of $160.0 million on a borrowing base of $900.0 million. After deducting an outstanding letter of credit for $26.0 million, borrowing capacity was $714.0 million. At September 30, 2012, the Company had outstanding a total of $1,335.2 million principal amount in senior debt, including the lease financing obligation entered into during the third quarter, with no significant maturity before 2016. The borrowing base was reaffirmed at $900.0 million in October 2012.

OPERATIONS

Production, Wells Spud and Capital Expenditures

The following table lists production, wells spud and total capital expenditures by basin for the three and nine months ended September 30, 2012. Capital expenditure totals include leasehold and other acquisition costs:

 

		Three Months ended September 30, 2012												Nine Months ended September 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			33				31			$	91.6				28				86			$	242.6
West Tavaputs			103				0				14.4				101				16				92.3
Piceance			152				6				44.6				144				91				193.2
Denver-Julesburg			9				21				121.3				8				39				176.5
Powder River (CBM)			30				0				0.1				31				0				0.1
Other			13				4				24.2				14				12				73.8
Total			340				62			$	296.2				326				244			$	778.5

(MMcfe/d: million cubic feet equivalent per day)

Operating and Drilling Update

The Company anticipates drilling or participating in approximately 284 gross/192 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 four to five rigs in the Uinta Oil Program and three rigs in the DJ Basin Niobrara oil play.

Uinta Basin, Utah

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

Current net production is approximately 6,300 Boe/d. The Company is currently running a four to five rig program in the area and expects to drill up to 66 gross/50 net operated wells in 2012, plus participate in approximately 32 wells operated by its partner in Lake Canyon.

 

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During 2012, the Company seeks to increase recoveries and optimize development of this vast, oil-rich resource base. During the third quarter, the Company had five rigs active and focused predominantly on the core vertical development program where the Company is very pleased with initial results in its East Bluebell and South Altamont acquisition areas as well as continued positive results in development drilling in the Blacktail Ridge area.

While development operations are focused on vertical drilling, the Company is also testing horizontally certain horizons to determine the potential to economically increase recoveries. Due to changes in composition across the Company’s acreage position, it is expected that some horizontal targets will perform differently in various portions of the basin. During the third and fourth quarters of 2012, the Company is continuing to drill its successful horizontal Uteland Butte program in the Blacktail Ridge area where wells drilled to date continue to match an approximate 300,000 Boe type curve.

During the third quarter of 2012, the Company conducted horizontal tests in the Wasatch CR4 zone where, to date, flow rates are somewhat encouraging and the Company plans to drill a second test later this year in the Wasatch CR3 zone. The Company also conducted a horizontal test in the Black Shale, where flow rates continue to be evaluated yet do not support horizontal development costs in a localized area of Blacktail Ridge. In the Shallow Green River zone, the Company conducted a vertical test that continues to be evaluated but does not appear to be economic in the Blacktail Ridge area.

At September 30, 2012, the Company had an approximate 75% working interest in production from 198 gross wells. The working interests for wells in the 2012 program range from 19% to 100%. As of the end of the third quarter of 2012, the Company had approximately 152,000 net acres (including acreage to be earned) in the program.

West Tavaputs – Current net production is approximately 95 MMcfe/d. While drilling is suspended at this time due to low natural gas prices, West Tavaputs remains one of the Company’s largest, long-term development assets.

At September 30, 2012, the Company had an approximate 98% working interest in production from 299 gross wells in its West Tavaputs shallow and deep programs.

The Company’s acreage in the area, including acreage at the nearby Hornfrog prospect where a third party legal dispute was recently settled and other acreage that can be earned, is 70,600 gross and 52,800 net.

Denver-Julesburg Basin, Colorado and Wyoming

Wattenberg and Chalk Bluffs – Current net production is approximately 2,000 Boe/d. In the rapidly growing DJ Program, the Company currently has three active rigs in the area, and the full year 2012 program is expected to include approximately 36 gross/24 net operated wells, all of which will be horizontal and target the “B” and/or “C” benches of the Niobrara formation.

During the third quarter, the Company completed and is testing its first four-well pad, which included two wells drilled into the “B” bench and two wells drilled into the “C” bench. The wells were drilled on average to a vertical depth of approximately 6,400 feet plus a 4,000 foot lateral. Early results include average per well 24-hour peak IP rates of 712 Boe/d and average per well 30-day rates of 407 Boe/d. Rates from the “B” and “C” benches are similar. The Company has drilled two additional four-well pads in the area, which also target the “B” and “C” benches, and is in the process of completing those wells.

 

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At September 30, 2012, the Company had an approximate 89% working interest in production from 236 gross wells and held approximately 75,600 net acres in the program, including the previously announced 31,070 net acre acquisition that closed in the quarter. The Company continues to actively add to its acreage position in this area.

Piceance Basin, Colorado

Gibson Gulch – Current net production is approximately 149 MMcfe/d. Drilling in this area remains suspended as a result of low natural gas and NGL prices.

A portion of Gibson Gulch natural gas production is processed, at the election of the Company, exposing the Company to the benefits of NGL pricing. The incremental benefit to production revenues related to natural gas liquids was $0.75 per Mcfe to the Company-wide realized price in the third quarter of 2012. The Gibson Gulch program serves as a “swing area” as the Company 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 September 30, 2012, the Company had an approximate 98% working interest in production from 935 gross wells in its Gibson Gulch program.

Exploration Update

Powder River Deep, Powder River Basin, Wyoming –The Company completed a horizontal exploration well (working interest 45%) testing the Sussex formation. The well was drilled to a vertical depth of approximately 10,000 feet plus a 4,100 foot lateral and completed with 17 fracture stimulation stages. Preliminary results are encouraging. The Company plans to drill at least two additional horizontal wells in the Frontier formation and one in the Shannon formation in the Powder River Basin by year-end, as well as participate in several non-operated tests. The Company has approximately 148,800 gross/64,300 net acres in the prospect and continues to actively add to its acreage position in this area.

San Juan Basin, New Mexico – The Company completed a 3-dimensional seismic survey in this area and intends to drill up to two horizontal wells in the coming months targeting oil in the Tocito-Gallup-Niobrara at approximately 6,500 feet. The Company has approximately 36,800 net acres (including acreage to be earned) in the prospect.

Southern Alberta Basin, Montana – The Company has drilled its first horizontal well in the area to the Banff Bakken formation at vertical depth of approximately 3,200 feet plus a 3,800 foot lateral and plans to complete the well during the fourth quarter of 2012. The Company has approximately 97,400 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:

 

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Capital expenditures of $900 to $950 million. The increased amount includes approximately $38 million for compression facilities in West Tavaputs and regional infrastructure in the UOP and $128 million for property/leasehold acquisitions completed through the third quarter of 2012. It also includes leasehold acquisitions that may close during the fourth quarter of 2012 totaling an estimated $12 to $36 million.

 

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

 

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Lease operating costs per Mcfe of $0.60 to $0.63, narrowed from $0.60 to $0.65.

 

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Gathering, transportation and processing costs per Mcfe of $0.88 to $0.91, lowered from $0.92 to $0.97.

 

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General and administrative expenses before non-cash stock-based compensation cost per Mcfe of $0.44 to $0.46, lowered from $0.45 to $0.49.

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 the fourth quarter of 2012 and 2013, the Company has hedges in place as outlined in the table below. Swap and collar hedge positions for natural gas and NGLs are tied to regional sales points and oil hedge positions are tied to WTI and include:

 

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For the fourth quarter of 2012, approximately 21.0 Bcfe, or approximately 70% of production, at a weighted average blended floor price of $7.24 per Mcfe.

 

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For 2013, approximately 63.8 Bcfe at a weighted average blended floor price of $7.11 per Mcfe.

As of October 19, 2012:

 

SWAPS & COLLARS
Period		Natural Gas / NGLs								Oil								Equivalent
		Daily Volume (MMBtu/d)				Price ($MMBtu)				Daily Volume (Bbl/d)				Price ($/Bbl)				Total Volume (Mmcfe)				Price ($/Mcfe)
4Q12			204,730			$	4.65				7,000			$	99.92				20,987			$	7.24
1Q13			183,877			$	3.94				6,500			$	98.57				18,555			$	6.63
2Q13			143,835			$	4.06				6,500			$	98.57				15,448			$	7.21
3Q13			143,793			$	4.05				6,500			$	98.57				15,614			$	7.21
4Q13			127,217			$	4.12				6,500			$	98.57				14,228			$	7.53
1Q14			75,000			$	3.83				2,700			$	96.77				7,594			$	6.50
2Q14			75,000			$	3.83				2,700			$	96.77				7,679			$	6.50
3Q14			75,000			$	3.83				2,700			$	96.77				7,763			$	6.50
4Q14			75,000			$	3.83				2,700			$	96.77				7,763			$	6.50

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

THIRD QUARTER 2012 RESULTS WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held tomorrow, November 1, 2012, to discuss third 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 at

 

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www.billbarrettcorp.com, or join by telephone by calling 866-202-4683 (617-213-8846 international callers) with passcode 81488090. The webcast will remain available on the Company’s website for approximately 30 days, and a replay of the call will be available through November 8, 2012 at call-in number 888-286-8010 (617-801-6888 international) with passcode 23605673.

QUARTERLY REPORT ON FORM 10-Q

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

UPCOMING EVENTS

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

Investor Conferences

Chief Operating Officer Scot Woodall will present at the Bank of America Merrill Lynch Energy Conference on November 13, 2012 at 10:30 a.m. Eastern time. The event will be webcast. The presentation for this event will be posted at 5:00 Mountain time on Monday, November 12, 2012.

Chief Financial Officer Bob Howard will present at the Bank of America Leveraged Finance Conference on December 5, 2012 at 7:30 a.m. Eastern time. The event will be webcast. The presentation for this event will be posted at 5:00 Mountain time on Monday, December 3, 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 related 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.

 

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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; costs and availability of third party facilities for gathering, processing, refining and transportation; the ability to receive drilling and other permits and rights-of-way; regulatory approvals, including regulatory restrictions on federal lands; legislative or regulatory changes, including initiatives related to hydraulic fracturing; exploration risks such as drilling unsuccessful wells; higher than expected costs and expenses, including the availability and cost of services and materials; unexpected future capital expenditures; economic and competitive conditions; debt and equity market conditions, including the availability and costs of financing to fund the Company’s operations; 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; declines in the values of our oil and gas properties resulting in impairments; changes in estimates of proved reserves; development drilling and testing results; the potential for production decline rates to be greater than we expect; performance of acquired properties; compliance with environmental and other regulations; derivative and hedging activities; 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.

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 website www.billbarrettcorp.com.

 

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BILL BARRETT CORPORATION

Selected Operating Highlights

(Unaudited)

 

						Three Months Ended September 30,								Nine Months Ended September 30,
						2012				2011				2012				2011
Production Data:
Natural gas (MMcf)							27,010				25,655				78,417				71,596
Oil (MBbls)							714				396				1,830				1,024
Combined volumes (MMcfe)							31,294				28,031				89,397				77,740
Daily combined volumes (Mmcfe/d)							340				305				326				285
Average Prices (before the effects of realized hedges):
Natural gas (per Mcf)			(1	)		$	3.85			$	5.87			$	3.84			$	5.81
Oil (per Bbl)							77.99				76.81				81.42				82.15
Combined (per Mcfe)							5.10				6.46				5.03				6.43
Average Realized Prices (after the effects of realized hedges):
Natural gas (per Mcf)			(1	)		$	4.90			$	6.48			$	5.04			$	6.54
Oil (per Bbl)							84.08				79.79				85.49				80.24
Combined (per Mcfe)							6.15				7.06				6.17				7.08
Average Costs (per Mcfe):
Lease operating expense						$	0.54			$	0.49			$	0.61			$	0.53
Gathering, transportation and processing expense							0.85				0.91				0.89				0.85
Production tax expense							0.26				0.39				0.24				0.38
Depreciation, depletion and amortization							2.92				2.72				2.81				2.71
General and administrative expense, excluding non-cash stock-based compensation			(2	)			0.44				0.45				0.44				0.47

 

(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 September 30,								Nine Months Ended September 30,
						2012				2011				2012				2011
(in thousands, except per share amounts)
Operating and Other Revenues:
Oil and gas production			(1	)		$	180,024			$	206,611			$	516,556			$	573,136
Other							842				769				3,838				4,028
Total operating and other revenues							180,866				207,380				520,394				577,164
Operating Expenses:
Lease operating							17,003				13,683				54,671				41,057
Gathering, transportation and processing							26,725				25,431				79,939				66,105
Production tax							8,094				10,946				21,193				29,293
Exploration							3,562				554				8,063				2,602
Impairment, dry hole costs and abandonment							38,540				17,187				60,179				18,563
Depreciation, depletion and amortization							91,392				76,165				251,417				210,406
General and administrative			(2	)			13,912				12,743				39,026				36,549
Non-cash stock-based compensation			(2	)			4,053				5,052				12,415				13,699
Total operating expenses							203,281				161,761				526,903				418,274
Operating Income/ (Loss)							(22,415	)			45,619				(6,509	)			158,890
Other Income and Expense:
Interest income and other income (expense)							53				(2	)			1,729				163
Interest expense							(24,527	)			(14,015	)			(70,029	)			(38,378	)
Commodity derivative gain (loss)			(1	)			(38,340	)			1,285				53,431				(12,734	)
Total other income and expense							(62,814	)			(12,732	)			(14,869	)			(50,949	)
Income (Loss) before Income Taxes							(85,229	)			32,887				(21,378	)			107,941
Provision for (Benefit from) Income Taxes							(32,603	)			12,251				(7,943	)			39,454
Net Income (Loss)						$	(52,626	)		$	20,636			$	(13,435	)		$	68,487
Net Income (Loss) Per Common Share
Basic						$	(1.11	)		$	0.44			$	(0.28	)		$	1.48
Diluted						$	(1.11	)		$	0.43			$	(0.28	)		$	1.45
Weighted Average Common Shares Outstanding
Basic							47,230				46,735				47,173				46,417
Diluted							47,230				47,527				47,173				47,125

 

(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 September 30,								Nine Months Ended September 30,
		2012				2011				2012				2011
Included in oil and gas production revenue:
Certain realized gains on hedges		$	20,391			$	25,525			$	66,654			$	73,223
Included in commodity derivative gain (loss):
Realized gain (loss) on derivatives not designated as cash flow hedges		$	12,295			$	(8,711	)		$	35,014			$	(22,705	)
Unrealized ineffectiveness gain (loss) recognized on derivatives designated as cash flow hedges			—				(18	)			—				1,032
Unrealized gain (loss) on derivatives not designated as cash flow hedges			(50,635	)			10,014				18,417				8,939
Total commodity derivative gain (loss)		$	(38,340	)		$	1,285			$	53,431			$	(12,734	)

 

(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 September 30, 2012				As of December 31, 2011
(in thousands)
Assets:
Cash and cash equivalents						$	23,933			$	57,331
Other current assets			(1	)			136,655				189,012
Property and equipment, net							2,864,841				2,406,764
Other noncurrent assets			(1	)			35,200				34,823
Total assets						$	3,060,629			$	2,687,930
Liabilities and Stockholders’ Equity:
Current liabilities			(1	)		$	219,762			$	233,198
Notes payable to bank							160,000				70,000
Capital lease							90,816				—
Senior notes							1,042,380				641,198
Convertible senior notes							25,344				171,042
Other long-term liabilities			(1	)			348,120				353,654
Stockholders’ equity							1,174,207				1,218,838
Total liabilities and stockholders’ equity						$	3,060,629			$	2,687,930

 

(1)

At September 30, 2012, the estimated fair value of all of our commodity derivative instruments was a net asset of $35.0 million, comprised of: $32.9 million current assets; $4.3 million non-current assets; and $0.6 million current liabilities and $1.6 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 September 30,								Nine Months Ended September 30,
		2012				2011				2012				2011
(in thousands)
Operating Activities:
Net income (loss)		$	(52,626	)		$	20,636			$	(13,435	)		$	68,487
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization			91,392				76,165				251,417				210,406
Impairment, dry hole costs and abandonment expense			38,540				17,187				60,179				18,563
Unrealized derivative (gain)\loss			50,635				(9,996	)			(18,417	)			(9,971	)
Deferred income taxes			(32,329	)			12,267				(7,669	)			39,470
Stock compensation and other non-cash charges			5,008				5,613				12,648				15,958
Amortization of debt discounts and deferred financing costs			1,708				3,429				6,710				9,849
Gain on sale of properties			(108	)			—				(108	)			(2,009	)
Change in assets and liabilities:
Accounts receivable			(13,661	)			7,335				4,475				(14,779	)
Prepayments and other assets			7,581				548				1,515				2,617
Accounts payable, accrued and other liabilities			4,040				(8,838	)			(4,813	)			(12,152	)
Amounts payable to oil & gas property owners			5,950				300				567				7,761
Production taxes payable			5,229				8,088				(2,466	)			9,773
Net cash provided by operating activities		$	111,359			$	132,734			$	290,603			$	343,973
Investing Activities:
Additions to oil and gas properties, including acquisitions			(291,486	)			(317,595	)			(751,545	)			(701,397	)
Additions of furniture, equipment and other			(1,278	)			(2,986	)			(5,519	)			(5,758	)
Proceeds from sale of properties and other investing activities			(43	)			(56	)			91				1,804
Net cash used in investing activities		$	(292,807	)		$	(320,637	)		$	(756,973	)		$	(705,351	)
Financing Activities:
Proceeds from debt			260,826				585,000				785,826				730,000
Principal payments on debt			(76,007	)			(330,000	)			(343,163	)			(330,000	)
Deferred financing costs and other			(277	)			(7,647	)			(10,364	)			(11,084	)
Proceeds from stock option exercises			5				5,913				673				18,991
Net cash provided by financing activities		$	184,547			$	253,266			$	432,972			$	407,907
Increase (Decrease) in Cash and Cash Equivalents			3,099				65,363				(33,398	)			46,529
Beginning Cash and Cash Equivalents			20,834				39,856				57,331				58,690
Ending Cash and Cash Equivalents		$	23,933			$	105,219			$	23,933			$	105,219

 

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                    BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow & Adjusted Net Income

(Unaudited)

Discretionary Cash Flow Reconciliation

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2012				2011				2012				2011
(in thousands, except per share amounts)
Net Income (Loss)		$	(52,626	)		$	20,636			$	(13,435	)		$	68,487
Adjustments to reconcile to discretionary cash flow:
Depreciation, depletion and amortization			91,392				76,165				251,417				210,406
Impairment, dry hole and abandonment expense			38,540				17,187				60,179				18,563
Exploration expense			3,562				554				8,063				2,602
Unrealized derivative (gain)/loss			50,635				(9,996	)			(18,417	)			(9,971	)
Deferred income taxes			(32,329	)			12,267				(7,669	)			39,470
Stock compensation and other non-cash charges			5,008				5,613				12,648				15,958
Amortization of debt discounts and deferred financing costs			1,708				3,429				8,311				9,849
Gain on extinguishment of debt			—				—				(1,601	)			—
Gain on sale of properties			(108	)			—				(108	)			(2,009	)
Discretionary Cash Flow		$	105,782			$	125,855			$	299,388			$	353,355
Per share, diluted		$	2.24			$	2.65			$	6.35			$	7.50
Per Mcfe		$	3.38			$	4.49			$	3.35			$	4.55

Adjusted Net Income (Loss) Reconciliation

		Three Months Ended September 30,								Nine Months Ended September 30,
		2012				2011				2012				2011
(in thousands except per share amounts)
Net Income (Loss)		$	(52,626	)		$	20,636			$	(13,435	)		$	68,487
Adjustments to net income (loss):
Unrealized derivative (gain)/loss			50,635				(9,996	)			(18,417	)			(9,971	)
Impairment expense			18,772				3,879				37,109				3,879
Gain on sale of properties			(108	)			—				(108	)			(2,009	)
One time items:
Gain on extinguishment of debt			—				—				(1,601	)			—
Subtotal Adjustments			69,299				(6,117	)			16,983				(8,101	)
Effective tax rate			38	%			37	%			37	%			37	%
Tax effected adjustments			42,965				(3,854	)			10,699				(5,104	)
Adjusted Net Income (Loss)		$	(9,661	)		$	16,782			$	(2,736	)		$	63,383
Per share, diluted		$	(0.20	)		$	0.35			$	(0.06	)		$	1.35
Per Mcfe		$	(0.31	)		$	0.60			$	(0.03	)		$	0.82

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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