Bill Barrett Corporation Reports Third Quarter 2011 Results and Announces Further Encouraging Uinta Oil Results

DENVER, Nov. 3, 2011 /PRNewswire/ -- Bill Barrett Corporation (NYSE: BBG) today reported third quarter 2011 operating results highlighted by:

  • Natural gas and oil production growth, up 10% to 28.0 Bcfe compared with the third quarter of 2010
  • Third and fourth Uteland Butte horizontal oil wells showing strong initial flow rates
  • Discretionary cash flow of $125.9 million or $2.65 per diluted common share
  • Net income of $20.6 million or $0.43 per diluted common share and adjusted net income of $16.8 million or $0.35 per diluted common share
  • Issuing $400 million of 7.625% senior notes, providing substantial liquidity
  • Closing key Denver-Julesburg (“DJ”) oil acquisition, adding 7 MMBoe proved reserves with 28,500 net acres

Chairman, Chief Executive Officer and President Fred Barrett commented: “Solid execution on strategies to increase the oil mix in our portfolio continued in the third quarter. Our build in oil is demonstrated on a few fronts with September oil production representing a 42% increase since the start of the year. Our acquisitions team closed on our DJ Basin acquisition, adding a fourth key development area and another liquids-focused program. Our operations team has completed two more horizontal Uteland Butte wells, both with encouraging results from our Uinta Oil Program. Currently, oil and natural gas liquids represent approximately 20% of our production based on energy content and approximately 44% of pre-hedge revenue, driving our continued emphasis on balancing the portfolio with liquids growth.

“We are very pleased to report continued positive results from the Uinta Oil Program where the peak 24-hour initial production (“IP”) rates for the first four horizontal Uteland Butte wells have averaged in excess of 1,000 barrels of oil equivalent per day (“Boe/d”). To date, the first two horizontal wells are producing as, or better than, expected. The third Uteland Butte horizontal well flowed and pumped an average 707 Boe/d over the first 30 days of production and had a peak 24-hour IP rate of 1,330 Boe/d, and the fourth Uteland Butte horizontal well, which has been on production for only 21 days, has averaged 596 Boe/d and had a peak IP rate of 863 Boe/d during that period. It is too early to estimate EURs from results to date, yet success in the Uteland Butte would open the potential for inventory expansion in our sizable Uinta Oil Program acreage position.

“As 2011 is nearing a close, we have added a third rig in the Uinta Oil Program where we will soon commence drilling in the East Bluebell oil expansion area. We have also recently added a rig in the DJ Basin, where we will continue development in the Wattenberg Field and will soon drill our first horizontal Niobrara test at our Chalk Bluffs exploration area. We are diligently working to complete facility upgrades at West Tavaputs in order to keep pace with production there. We have updated 2011 guidance to lower cost estimates for both operating and transportation expenses while keeping production and capital expenditure expectations unchanged (see “Guidance” below.) 2011 remains on track to deliver solid growth while positioning the Company for an even stronger year in 2012.”

Third quarter 2011 natural gas and oil production totaled 28.0 billion cubic feet equivalent (“Bcfe”), up 10% from 25.5 Bcfe in the third quarter of 2010 and up 6% sequentially from the second quarter of 2011. For the first nine months of 2011, production totaled 77.7 Bcfe, up 8% from the 2010 period. The Company is on track for its full year guidance range of 106 to 110 Bcfe. Third quarter production growth was predominantly from the West Tavaputs natural gas program as well as the Uinta Oil Program and acquisition properties. Including the effects of the Company’s hedging activities and natural gas liquids recovery, the average realized sales price in the third quarter of 2011 was $7.06 per thousand cubic feet equivalent (“Mcfe”) compared with $7.03 per Mcfe in the third quarter of 2010. The Company’s commodity hedging program increased third quarter 2011 natural gas and oil revenues by net $16.8 million, or $0.60 per Mcfe of production. The incremental revenue benefit from processing a portion of its natural gas for natural gas liquids increased to $1.41 per Mcfe in the third quarter of 2011, reflecting strong natural gas liquids pricing in the period and inclusion of incremental NGL benefits from West Tavaputs and the DJ Basin.

Discretionary cash flow (a non-GAAP measure, see “Discretionary Cash Flow Reconciliation” below) in the third quarter of 2011 was $125.9 million, or $2.65 per diluted common share, compared with $136.5 million, or $2.98 per diluted common share, in the third quarter of 2010. Discretionary cash flow was down from the comparable 2010 period primarily due to a one-time adjustment from current to deferred tax expense in the 2010 period totaling $13.1 million. Discretionary cash flow for the first nine months of 2011 was $353.4 million, down 1% from $357.1 million in the first nine months of 2010.

Net income in the third quarter of 2011 was $20.6 million, or $0.43 per diluted common share, compared with $24.6 million, or $0.54 per diluted common share, in the third quarter of 2010. The decline in net income was primarily due to higher impairment, dry hole and abandonment expense in the 2011 period. Dry hole expense in the third quarter of 2011 was $11.0 million ($6.9 million net of tax) and included the McRae Gap exploration well in the Wind River Basin and interests in two exploratory wells in the north end of the DJ Basin. Net income for the first nine months of 2011 was $68.5 million, down 22% from the first nine months of 2010, primarily due to higher derivative losses and higher impairment, dry hole and abandonment expenses. Adjusted net income for the third quarter of 2011 (a non-GAAP measure, see “Adjusted Net Income Reconciliation” below) was $16.8 million, or $0.35 per diluted common share, compared with $24.0 million, or $0.52 per diluted common share, in the third quarter of 2010. The decline in adjusted net income was primarily due to the higher dry hole cost in the 2011 period, which is not added back in the adjusted net income calculation. 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, 2011, the Company’s revolving credit facility was undrawn. Subsequent to quarter-end, the Company increased its borrowing base to $1.1 billion and bank commitments to $900.0 million, while extending the maturity of the credit facility to October 2016. After deducting an outstanding letter of credit for $26.0 million, borrowing capacity is currently $874.0 million. During the quarter, the Company completed the offering of $400 million of 7.625% senior notes due 2019, issued at par. Proceeds from the offering were used to pay down the Company’s revolving credit facility. The Company also had $172.5 million in 5% convertible senior notes and $250.0 million in 9.875% senior notes outstanding at September 30, 2011.  

OPERATIONS

Production, Wells Spud and Capital Expenditures

The following table lists production, wells spud and total capital expenditures by basin for the three months and nine months ended September 30, 2011:


Three Months ended September 30, 2011


Nine Months ended September 30, 2011


Average Net


Wells


Capital


Average Net


Wells


Capital


Production


Spud


Expenditures


Production


Spud


Expenditures

Basin

(MMcfe/d)


(gross)


(millions)


(MMcfe/d)


(gross)


(millions)













Piceance

134


32


$          55.2


133


83


$        149.5

Uinta

116


45


104.0


99


102


383.0

Powder River (CBM)

36


1


0.3


36


6


3.8

Wind River

15


0


2.4


15


0


3.9

Other

4


4


162.9


2


16


192.6













Total

305


82


$        324.8


285


207


$        732.8



Capital expenditures totaled $324.8 million for the third quarter of 2011, including the acquisition of properties in the DJ Basin for $149.1 million.

Operating and Drilling Update

The Company anticipates participating in the drilling of approximately 300 gross wells in 2011, including approximately 6 coal bed methane (“CBM”) wells. The Company currently has eight active operated drilling rigs with two at West Tavaputs, two at Gibson Gulch, three at the Uinta Oil Program and one at the DJ Basin acquisition area. The Company’s development program is focused on growth in production and reserves as well as driving operating efficiencies at West Tavaputs.

Uinta Basin, Utah

West Tavaputs – Current net production is approximately 100 million cubic feet equivalent per day (“MMcfe/d”). The Company continues to successfully execute its development program in the area and is on track for its approximate 100-well program for 2011. Due to increased drilling efficiencies and better than expected well performance at certain wells, production increased faster than anticipated, and the Company is currently installing a loop line and additional compression capacity. New capacity will be in place in the first quarter of 2012 that will support future production. West Tavaputs is one of the Company’s largest development assets based on its current reserve base of 345 Bcfe proved and 1.3 Tcfe proved, probable and possible reserves (see “Reserve Disclosure” below), providing a multi-year, high growth program for the Company.

At September 30, 2011, the Company had an approximate 97% working interest in production from 235 gross wells in its West Tavaputs shallow and deep programs. The West Tavaputs development program primarily targets the shallow Mesaverde and Wasatch zones. Upside potential is also recognized in the shallow Green River oil zones and deeper formations including the Mancos.

Uinta Oil Program (Blacktail Ridge, Lake Canyon and East Bluebell) – Current net production is approximately 4,400 Boe/d. The Company added a third rig to the area in early October 2011. This area offers upside potential through horizontal drilling, increased density and field extension.  

During the third quarter of 2011, the Company continued horizontal drilling into the Uteland Butte formation (working interest 55.8% for first four wells). The third well was completed in the Uteland Butte at approximately 5,850’ with a 3,400’ lateral and 15 fracture stimulation stages and flowed and pumped an average 707 Boe/d over the first 30 days of production with a peak 24-hour IP rate of 1,330 Boe/d. The fourth well was completed to approximately 5,900’ with a 3,200’ lateral and 15 fracture stimulation stages and had a peak IP rate of 863 Boe/d during the 21 days it has been on production. The Company intends to drill a total of seven horizontal wells targeting the Uteland Butte formation by year-end. The Company expects to sizably increase its well inventory at the Uinta Oil Program with continued success in both its vertical and horizontal drilling plans.

The Company also completed a vertical test well into the Mahogany formation to 5,500’ with 245’ of core. Core tests in the Mahogany formation were positive and the well is recovering oil. The Company is currently permitting for two additional vertical test wells it expects to drill in mid-2012.

At September 30, 2011, the Company had an approximate 68% working interest in production from 105 gross wells in the combined area. The working interests in this area range from 19% to 100%.

Piceance Basin, Colorado

Gibson Gulch – Current net production is approximately 138 MMcfe/d. The Company continues to operate two rigs in the area and expects to complete a 100-plus well program in 2011. The Company continues to benefit from its election to process the majority of its Gibson Gulch natural gas production, which exposes the Company to natural gas liquids pricing. Gibson Gulch operations offer strong margins due to low operating costs and the currently higher revenues related to liquids. The program continues to be a key, lower risk development area for the Company.

At September 30, 2011, the Company had an approximate 98% working interest in production from 792 gross wells in its Gibson Gulch program.

Denver-Julesburg Basin, Colorado and Wyoming

Wattenberg/Chalk Bluffs/Sagebrush – The Company has approximately 67,500 net acres in the DJ Basin, a fourth key development area for the Company. The Company closed on its DJ Basin acquisition in August, took over operations as of September and initiated drilling in mid-October. Drilling commenced in the Wattenberg area, where current production is from the Codell, Niobrara and J Sand formations. Following four-to-five vertical wells in the Wattenberg Field, the Company plans to initiate exploration drilling in the area, targeting the Niobrara shale formation through horizontal wells.

During the third quarter of 2011, the Company completed its first DJ Basin exploration well and had a small participation interest in a second well, both located in the northern DJ Basin, north of the Company’s recent acquisition, which did not produce commercial quantities of oil and were expensed as dry holes.

Wind River Basin, Wyoming

McRae Gap - The Company has identified approximately 100,000 net undeveloped acres within its acreage position in the area that it considers prospective for Niobrara shale oil. In the third quarter of 2011, the Company completed its first horizontal exploration well into the lower bench of the Niobrara shale at approximately 8,000’ in depth with an approximate 3,200’ lateral and 13 fracture stimulation stages. While the first exploration well in the area produced only minor amounts of oil, the Company is reviewing data to refine its drilling focus in the prospect. In the third quarter, this $5.7 million McRae Gap well was expensed as a dry hole.

ADDITIONAL FINANCIAL INFORMATION

Guidance

The Company’s 2011 guidance (please reference “Forward-Looking Statements” below) is updated as follows:

  • Capital expenditures for exploration and development of $685 to $705 million, unchanged. This amount is before acquisition purchase costs totaling approximately $268 million through the first nine months.
  • Oil and natural gas production of 106 to 110 Bcfe, unchanged.
  • Lease operating costs per Mcfe of $0.53 to $0.55, reduced and narrowed from $0.54 to $0.58 as a result of effective cost discipline across operations.
  • Gathering, transportation and processing costs per Mcfe of $0.87 to $0.89, lowered from $0.89 to $0.93.
  • General and administrative expenses before non-cash stock-based compensation between $47.5 and $48.5 million, increased from $46.0 and $47.5 million, mostly due to higher employee costs and headcount.

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

  • For the fourth quarter of 2011, approximately 18.7 Bcfe at a weighted average blended floor price of $7.30 per Mcfe.
  • For 2012, approximately 51.7 Bcfe at a weighted average blended floor price of $7.27 per Mcfe.

As of October 31, 2011:

SWAPS & COLLARS











Period


Natural Gas / NGLs


Oil


Equivalent



Volume

Price


Volume

Price


Volume

Price



MMBtu/d

$/MMBtu


Bbl/d

$/Bbl


MMcfe

$/Mcfe











4Q11


202,221

$   5.82


3,300

$   93.66


18,735

$ 7.30

1Q12


169,223

$   5.10


3,400

$ 100.88


15,856

$ 6.92

2Q12


133,131

$   5.11


3,400

$ 100.88


12,870

$ 7.24

3Q12


133,069

$   5.11


3,400

$ 100.88


13,006

$ 7.23

4Q12


96,602

$   5.31


3,400

$ 100.88


9,956

$ 7.91























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

THIRD QUARTER 2011 WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held later this morning to discuss third quarter 2011 results. Please join Bill Barrett Corporation executive management at 12:00 p.m. Eastern time (“ET”)/10:00 a.m. Mountain time (“MT”) for the live webcast, accessed at www.billbarrettcorp.com, or join by telephone by calling 866-761-0748 (617-614-2706 international callers) with passcode 68573156. 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 10, 2011 at call-in number 888-286-8010 (617-801-6888 international) with passcode 69611288. The Company also has tentatively scheduled its fourth quarter 2011 earnings conference call for February 23, 2012 at noon ET/10:00 a.m. MT.

UPCOMING EVENTS

Updated investor presentations will be posted to the homepage of the Company’s website at www.billbarrettcorp.com for each event below. Please check the website at 5:00 p.m. MT on the business day prior to the investor event for the most recent presentation, unless otherwise noted:

Investor Conferences

Chief Financial Officer Bob Howard will participate at the Barclays Capital Second Annual Energy, Engineering and Construction Forum in Dallas on November 10, 2011. An updated investor presentation will be posted at 5:00 p.m. MT on Tuesday, November 8, 2011.

Chief Operating Officer Scot Woodall will present at the Bank of America Merrill Lynch Global Energy Conference in Miami on November 15, 2011 at 1:20 p.m. ET. The event will be webcast.

Chief Financial Officer Bob Howard will present at the Bank of America Merrill Lynch Leveraged Finance Conference in Orlando on December 2, 2011 at 10:50 a.m. ET. The event will be webcast. The presentation for this event will be posted at 5:00 p.m. MT on Wednesday, November 30, 2011.

DISCLOSURE STATEMENTS

Forward-Looking Statements

This press release contains forward-looking statements, including statements regarding projected results and future events, including guidance and the upside potential and other prospects of acquisitions and other planned activities. These forward-looking statements are based on management’s judgment as of this date and include certain risks and uncertainties. Please refer to the Company’s Annual Report on Form 10-K for the year-ended December 31, 2010 filed with the SEC, and other filings including our Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 and 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, market conditions, oil and gas price volatility, exploration and development drilling and testing results, performance of acquired properties, the ability to receive drilling and other permits and rights-of-way, regulatory approvals, governmental laws and regulations and changes in enforcement of those laws and regulations, new laws and regulations, risks related to and costs of hedging activities including counterparty viability, surface access and costs, availability of third party gathering, transportation and processing, the availability and cost of services and materials, the ability to obtain industry partners to jointly explore certain prospects and the willingness and ability of those partners to meet capital obligations when requested, availability and costs of financing to fund the Company’s operations, uncertainties inherent in oil and gas production operations and estimating reserves, the speculative actual recovery of estimated potential volumes, unexpected future capital expenditures, competition, risks associated with operating in one major geographic area, the success of the Company’s risk management activities, title to properties, litigation, environmental liabilities, and other factors discussed in the Company’s reports filed with the SEC. Bill Barrett Corporation encourages readers to consider the risks and uncertainties associated with projections and other forward-looking statements. In addition, the Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances.

Reserve Disclosure

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

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

ABOUT BILL BARRETT CORPORATION

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

BILL BARRETT CORPORATION

Selected Operating Highlights

(Unaudited)














Three Months Ended


Nine Months Ended





September 30,


September 30,





2011

2010


2011

2010

Production Data:









Natural gas (MMcf)



25,655

23,540


71,596

67,505


Oil (MBbls)



396

322


1,024

795


Combined volumes (MMcfe)



28,031

25,472


77,740

72,275


Daily combined volumes (Mmcfe/d)



305

277


285

265

Average Prices (before the effects of realized hedges):









Natural gas (per Mcf)



$   5.87

$   4.77


$   5.81

$   5.32


Oil (per Bbl)



76.81

64.65


82.15

66.43


Combined (per Mcfe)



6.46

5.23


6.43

5.70

Average Realized Prices (after the effects of realized hedges):









Natural gas (per Mcf)



$   6.48

$   6.67


$   6.54

$   6.83


Oil (per Bbl)



79.79

68.57


80.24

69.49


Combined (per Mcfe)



7.06

7.03


7.08

7.14

Average Costs (per Mcfe):









Lease operating expense



$   0.49

$   0.51


$   0.53

$   0.54


Gathering, transportation and processing expense



0.91

0.68


0.85

0.72


Production tax expense

(1)


0.39

0.32


0.38

0.35


Depreciation, depletion and amortization



2.72

2.72


2.71

2.65


General and administrative expense,  









   excluding non-cash stock-based compensation

(2)


0.45

0.41


0.47

0.42





















(1)

Production tax expense for the first nine months of 2010 includes a one-time benefit to reduce and re-estimate prior periods as a result of amended returns filed with the State of Utah regarding the calculation of severance taxes.  Exclusive of the one-time benefits, the production tax expense per Mcfe for the first nine months of 2010 would have been $0.38.










(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.



BILL BARRETT CORPORATION

Consolidated Statements of Operations

(Unaudited)




















Three Months Ended


Nine Months Ended




September 30,


September 30,




2011


2010


2011


2010

(in thousands, except per share amounts)



















Operating and Other Revenues:










Oil and gas production

(1)

$ 206,611


$ 185,007


$ 573,136


$ 534,956


Commodity derivative gain (loss)

(1)

1,285


(4,934)


(12,734)


(2,922)


Other


769


558


4,028


3,032


Total operating and other revenues


208,665


180,631


564,430


535,066











Operating Expenses:










Lease operating


13,683


13,001


41,057


39,023


Gathering, transportation and processing


25,431


17,301


66,105


51,758


Production tax

(2)

10,946


8,193


29,293


25,524


Exploration


554


3,841


2,602


4,796


Impairment, dry hole costs and abandonment


17,187


4,653


18,563


8,520


Depreciation, depletion and amortization


76,165


69,192


210,406


191,626


General and administrative

(3)

12,743


10,557


36,549


30,560


Non-cash stock-based compensation

(3)

5,052


3,428


13,699


11,169


Total operating expenses


161,761


130,166


418,274


362,976

Operating Income


46,904


50,465


146,156


172,090

Other Income and Expense:










Interest income and other income (expense)


(2)


231


163


356


Interest expense


(14,015)


(11,170)


(38,378)


(32,492)


Total other income and expense


(14,017)


(10,939)


(38,215)


(32,136)

Income before Income Taxes


32,887


39,526


107,941


139,954

Provision for Income Taxes


12,251


14,964


39,454


52,217

Net Income



$   20,636


$   24,562


$   68,487


$   87,737





















Net Income Per Common Share










Basic


$       0.44


$       0.54


$       1.48


$       1.95


Diluted


$       0.43


$       0.54


$       1.45


$       1.92





















Weighted Average Common Shares Outstanding










Basic


46,735


45,206


46,417


45,067


Diluted


47,527


45,791


47,125


45,595













(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,




2011


2010


2011


2010


Included in oil and gas production revenue:










Realized gain on cash flow hedges


$   25,525


$   51,841


$   73,223


$ 122,739












Included in commodity derivative gain (loss):










Realized loss on derivatives not designated as










  cash flow hedges


$   (8,711)


$   (5,941)


$ (22,705)


$ (18,927)


Unrealized ineffectiveness gain (loss) recognized










  on derivatives designated as cash flow hedges


(18)


(781)


1,032


(1,047)


Unrealized gain on derivatives










  not designated as cash flow hedges


10,014


1,788


8,939


17,052


  Total commodity derivative gain (loss)


$     1,285


$   (4,934)


$ (12,734)


$   (2,922)













(2)  

Production tax expense for the first nine months of  2010 period includes a one-time benefit to reduce and re-estimate prior periods as a result of amended returns filed with the State of Utah regarding the calculation of severance taxes.











(3)  

Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of cash required for general and administrative expenses. Management also believes that this disclosure may allow for a more accurate comparison to the Company's peers that may have higher or lower costs associated with equity grants.



BILL BARRETT CORPORATION

Consolidated Condensed Balance Sheets

(Unaudited)












As of


As of





September 30, 2011


December 31, 2010








(in thousands)













Assets:






Cash and cash equivalents


$                   105,219


$                    58,690


Other current assets

(1)

162,042


148,958


Property and equipment, net


2,327,555


1,811,819


Other noncurrent assets


42,816


19,033



Total assets


$                2,637,632


$               2,038,500















Liabilities and Stockholders' Equity:






Current liabilities      

(1)

$                   194,740


$                  165,957


Notes payable to bank


-


-


Senior notes


640,829


239,766


Convertible senior notes


169,354


164,633


Other long-term liabilities      

(1)

382,801


327,182


Stockholders' equity


1,249,908


1,140,962



Total liabilities and stockholders' equity


$                2,637,632


$               2,038,500










(1)

At September 30, 2011, the estimated fair value of all of our commodity derivative instruments was a net asset of $82.7 million, comprised of: $64.0 million current assets; $0.8 million current liabilities; $20.1 million non-current assets; and $0.6 million non-current liabilities.  This amount will fluctuate quarterly based on estimated future commodity prices and the current hedge position.



BILL BARRETT CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)


















Three Months Ended


Nine Months Ended






September 30,


September 30,






2011


2010


2011


2010

(in thousands)





















Operating Activities:










Net income


$    20,636


$    24,562


$    68,487


$    87,737


Adjustments to reconcile to net cash










 provided by operations:











Depreciation, depletion and amortization


76,165


69,192


210,406


191,626



Impairment, dry hole costs and abandonment expense


17,187


4,653


18,563


8,520



Unrealized derivative gain


(9,996)


(1,007)


(9,971)


(16,005)



Deferred income taxes


12,267


28,068


39,470


60,350



Stock compensation and other non-cash charges


5,613


3,926


15,958


12,253



Amortization of debt discounts and deferred financing costs


3,429


3,170


9,849


8,831



Loss (gain) on sale of properties


-


50


(2,009)


(999)



Change in assets and liabilities:












Accounts receivable


7,335


(15)


(14,779)


(80)




Prepayments and other assets


548


(7,332)


2,617


(10,303)




Accounts payable, accrued and other liabilities


(8,838)


(6,392)


(12,152)


(9,943)




Amounts payable to oil & gas property owners


300


3,777


7,761


5,446




Production taxes payable


8,088


5,936


9,773


3,122















Net cash provided by operating activities


$  132,734


$  128,588


$  343,973


$  340,555

Investing Activities:










Additions to oil and gas properties, including acquisitions


(317,595)


(114,299)


(701,397)


(313,481)


Additions of furniture, equipment and other


(2,986)


(453)


(5,758)


(2,091)


Proceeds from sale of properties and other investing activities


(56)


(135)


1,804


2,133















Net cash used in investing activities


$ (320,637)


$ (114,887)


$ (705,351)


$ (313,439)

Financing Activities:










Proceeds from debt


585,000


-


730,000


20,000


Principal payments on debt


(330,000)


-


(330,000)


(25,000)


Deferred financing costs and other


(7,647)


(291)


(11,084)


(15,257)


Proceeds from stock option exercises


5,913


8,121


18,991


10,508















Net cash provided by (used in) financing activities


$  253,266


$      7,830


$  407,907


$     (9,749)













Increase in Cash and Cash Equivalents


65,363


21,531


46,529


17,367













Beginning Cash and Cash Equivalents


39,856


50,241


58,690


54,405













Ending Cash and Cash Equivalents


$  105,219


$    71,772


$  105,219


$    71,772



BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow & Adjusted Net Income

(Unaudited)





















Discretionary Cash Flow Reconciliation











Three Months Ended


Nine Months Ended




September 30,


September 30,




2011


2010


2011


2010

(in thousands, except per share amounts)




















Net Income

$   20,636


$   24,562


$   68,487


$   87,737











Adjustments to reconcile to discretionary cash flow:









Depreciation, depletion and amortization

76,165


69,192


210,406


191,626


Impairment, dry hole and abandonment expense

17,187


4,653


18,563


8,520


Exploration expense

554


3,841


2,602


4,796


Unrealized derivative gain

(9,996)


(1,007)


(9,971)


(16,005)


Deferred income taxes

12,267


28,068


39,470


60,350


Stock compensation and other non-cash charges

5,613


3,926


15,958


12,253


Amortization of debt discounts and deferred financing costs

3,429


3,170


9,849


8,831


Loss (gain) on sale of properties

-


50


(2,009)


(999)

Discretionary Cash Flow

$ 125,855


$ 136,455


$ 353,355


$ 357,109












Per share, diluted

$       2.65


$       2.98


$       7.50


$       7.83


Per Mcfe

$       4.49


$       5.36


$       4.55


$       4.94












Adjusted Net Income Reconciliation











Three Months Ended


Nine Months Ended




September 30,


September 30,




2011


2010


2011


2010

(in thousands except per share amounts)




















Net Income

$   20,636


$   24,562


$   68,487


$   87,737











Adjustments to net income:









Unrealized derivative gain

(9,996)


(1,007)


(9,971)


(16,005)


Impairment expense

3,879




3,879




Loss (gain) on sale of properties

-


50


(2,009)


(999)


One time items:










Production tax expense

-


-


-


(2,184)


Subtotal Adjustments

(6,117)


(957)


(8,101)


(19,188)


Effective tax rate

37%


38%


37%


37%


Tax effected adjustments

(3,854)


(593)


(5,104)


(12,088)

Adjusted Net Income

$   16,782


$   23,969


$   63,383


$   75,649












Per share, diluted

$       0.35


$       0.52


$       1.35


$       1.66


Per Mcfe

$       0.60


$       0.94


$       0.82


$       1.05























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.



SOURCE Bill Barrett Corporation



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http://www.billbarrettcorp.com

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