Bill Barrett Corporation Reports First Quarter 2013 Results, Positive New Wells in the DJ Basin and Powder River Deep Oil Program and Reaffirms 2013 Guidance

DENVER, May 2, 2013 /PRNewswire/ -- Bill Barrett Corporation (NYSE: BBG) today reported first quarter 2013 results and announced operational updates highlighted by:

  • Oil and natural gas production of 21.2 Bcfe, on track for full year guidance of 86-90 Bcfe
  • Oil production averaging 8,827 barrels per day, or 23% of production
  • Average realized price of $6.58 per Mcfe, reflecting the benefit of growing oil volumes.  Oil sales accounted for 47% of pre-hedge sales revenues
  • Discretionary cash flow of $63.6 million, or $1.34 per diluted common share, which includes certain one-time first quarter expenses of $3.8 million, or $0.08 per share.
  • Plans to run three-to-four rigs in the Northeast Wattenberg June through December
  • Uinta Oil Program drilling and completion optimization, driving 10% savings in per well costs over 2012
  • Recent Northeast Wattenberg well flowed 700 barrels of oil equivalent per day ("Boe/d") peak 24-hour initial production ("IP") rate and 413 Boe/d 30-day average rate, located on the eastern portion of the Company's position
  • Two new successful wells in the Powder River Deep Oil Program flowed 2,065 and 1,281 Boe/d peak 24-hour IP rates, and flowed 1,222 and 842 Boe/d 30-day average rates. Both wells were restricted due to availability of facilities capacity in the area  

Chief Executive Officer and President Scot Woodall commented: "First quarter operations are on track with our full year plan. Further, we are pleased with advances we are making in both the Denver-Julesburg Basin ("DJ") and Uinta Oil Program ("UOP") to optimize well costs and performance. Given results to date and improvement in drilling and completion techniques, we are ready to increase the pace of drilling in the Northeast Wattenberg, which carries the best returns in our portfolio. Execution of our development plans in the DJ and UOP remain our top priority. We also remain committed to ending 2013 with no increase in our total debt. We will be actively managing our portfolio to generate proceeds from the sale of assets to meet our funding requirements, which we expect to complete in the second half of the year."

OPERATING AND FINANCIAL RESULTS

Oil and natural gas production totaled 21.2 billion cubic feet equivalent ("Bcfe") in the first quarter of 2013, based on three-stream reporting adopted as of January 1, 2013. (First quarter of 2013 production on a comparable two-stream basis would have been 20.4 Bcfe.) Production is down from 28.2 Bcfe reported in the first quarter of 2012 and down sequentially from 28.2 Bcfe reported in the fourth quarter of 2012 (each reported on a two-stream basis), primarily due to asset sales closed in the fourth quarter of 2012 and cessation of drilling natural gas programs. Oil production of 8,827 barrels per day ("Bbls/d") in the first quarter of 2013 was up 67% compared with the first quarter of 2012, including an 80% increase at the UOP and a three-fold increase in the DJ, partially offset by the oil production sold in the fourth quarter asset sale.

Realized pricing in the first quarter of 2013 was $6.58 per thousand cubic feet equivalent ("Mcfe"), up 3% from the first quarter of 2012, reflecting the significant growth in oil volumes year-over-year and benefiting by $0.41 per Mcfe from realized hedges. The average realized prices by commodity for the first quarter of 2013 were $81.74 per barrel ("Bbl") of oil, $4.10 per Mcfe of natural gas and $48.32 per Bbl of natural gas liquids ("NGLs") (reflecting the Company's election to reject ethane on the majority of its NGLs during the first quarter.)  (See "Selected Operating Highlights" below for more detail.)

The table below presents production volumes, sales volumes (see "Disclosure Statements" below) and realized prices historically by quarter. First quarter of 2013 production reflects the effects of the asset sale, the change to three-stream reporting and the Company's election to reject ethane:




1Q12

2Q12

3Q12

4Q12

1Q13

Reported Production Volumes 3-Stream:







Oil (Bbls/d)

N/A

N/A

N/A

N/A

8,827


Natural gas, including NGLs (MMcf/d)

N/A

N/A

N/A

N/A

163


NGLs ethane rejected (Bbls/d)

N/A

N/A

N/A

N/A

3,349








Reported Production Volumes 2-Stream:







Oil (Bbls/d)

5,286

6,972

7,766

9,315

N/A


Natural gas, including NGLs (MMcf/d)

278

287

294

251

N/A








Sales* Volumes (1Q12-4Q12) & 2-stream   estimate 1Q13:







Oil (Bbls/d)

5,286

6,972

7,766

9,315

8,827


Natural gas sold as dry gas (MMcf/d)

257

262

265

223

N/A


Natural gas including NGLs (MMcf/d)





174


NGLs (Bbls/d)

11,985

11,439

10,341

8,687

N/A















Reported Realized Prices







Oil (per Bbl)

$ 88.42

$ 84.86

$ 84.08

$ 83.84

$  81.74


Natural gas sold as dry gas (per Mcf)

N/A

N/A

N/A

N/A

$   4.10


Natural gas including benefit of NGL realizations (per Mcf)

$   5.46

$   4.77

$   4.90

$   5.18

N/A


NGLs (per Bbl)

N/A

N/A

N/A

N/A

$  48.32








* (see "Disclosure Statements" below)


Discretionary cash flow (a non-GAAP measure, see "Discretionary Cash Flow Reconciliation" below) in the first quarter of 2013 was $63.6 million, or $1.34 per diluted common share, down from $99.0 million in the first quarter of 2012. Adjusting first quarter of 2013 discretionary cash flow for certain one-time items totaling $3.8 million, normalized discretionary cash flow was $67.4 million, or $1.42 per diluted common share. One-time items included $1.2 million in charges not covered by insurance associated with the compressor station fire at West Tavaputs included in lease operating expense ("LOE"), and $2.6 million related to the CEO transition included in general and administrative expense ("G&A") (which was considered in 2013 G&A guidance). The decline in discretionary cash flow in the first quarter of 2013 compared with the first quarter of 2012 was primarily due to lower production (described above). LOE per unit was $0.88 in the first quarter of 2013 compared with $0.66 in the first quarter of 2012. The increase in per unit LOE was due in general to fixed costs spread over lower production volumes and due to the higher cost of producing oil, with first quarter costs also including major compressor overhauls in Gibson Gulch (which were considered in full year LOE guidance) and the one-time charge associated with the compressor station fire.

Net income in the first quarter of 2013 was a loss of $33.2 million, or ($0.70) per diluted common share, compared with income of $35.9 million in the first quarter of 2012. Net income was affected by the same items that affected discretionary cash flow described above. In addition, net income was lower due to non-cash items including: a derivative loss in the current period of $36.3 million versus a derivative gain of $40.9 million in the prior year period; an abandonment charge in the current period of $4.6 million related to exploration properties in the San Juan Basin where the Company elected to terminate a drill-to-earn agreement; all of which was tax effected. Adjusted net income for the first quarter of 2013 (a non-GAAP measure, see "Adjusted Net Income Reconciliation" below) was a loss of $11.8 million, or ($0.25) per diluted common share, compared with earnings of $9.5 million, or $0.20 per diluted common share, in the first quarter of 2012. Adjusted net income removes the effect of non-recurring charges such as unrealized derivative gains and losses, impairment expenses, property sales and certain one-time items.

DEBT AND LIQUIDITY

At March 31, 2013, the Company had total debt outstanding (principal balance) of $1,195.7 million including $25.0 million drawn on its revolving credit facility.  Subsequent to quarter-end, the Company's lenders affirmed the borrowing base and commitments at $825.0 million. After deducting an outstanding letter of credit for $26.0 million, borrowing capacity at quarter-end was $774.0 million. The Company has no maturities before 2016.

OPERATIONS

Production, Wells Spud and Capital Expenditures

The following table lists production, wells spud and total capital expenditures by basin for the three months ended March 31, 2013:

 




Three Months Ended March 31, 2013

Basin

Average Net Daily Production MMcfe/d


Wells Spud Gross*


Capital Expenditures $mm







Uinta:






       Uinta Oil Program

42


20


$  65

       West Tavaputs

73


0


1

Piceance

101


0


2

Denver-Julesburg

16


2


20

Powder River Deep Oil & Other

4


4


30













Total

236


26


$ 118

*Operated wells

 

Operating and Drilling Update

The Company anticipates drilling or participating in approximately 180 gross/100 net development wells in 2013, including participation in approximately 40 non-operated wells. The Company's development program will focus on growth in oil production and reserves at its established development programs.

Uinta Basin, Utah

Uinta Oil Program (Blacktail Ridge, Lake Canyon, East Bluebell and South Altamont)
First quarter net production averaged 6,940 Boe/d. The Company currently has five drilling rigs operating in the area and plans to operate between two and five rigs in the area through the remainder of the year with a full year program that includes 70 gross/43 net operated wells. Sixteen wells were completed in the first quarter. The Company continues to drive cost efficiencies in the area with optimizations to fracture stimulation design and well depths, driving an approximate $400,000 savings per well in drilling and completion costs for 2013. The Company currently is testing an 80-acre spacing pilot program in the Blacktail Ridge area on two pads, the first of which is drilled and the second currently is being drilled. Down-spacing offers upside potential to increase the current reserves and drilling inventory, which are currently estimated on 160-acre spacing.

At March 31, 2013, the Company had an approximate 74% working interest in production from 226 gross wells. Depending upon elections to participate by partners, the Company may have a lower working interest in its 2013 drilling program.  As of the end of the first quarter of 2013, the Company had 152,750 net acres (including acreage to be earned) in the program.

West Tavaputs – First quarter net production averaged 73 million cubic feet equivalent per day (MMcfe/d). Production operations are fully back on-line following the compressor station fire in November of 2012. Drilling in the area remains suspended as the Company focuses its operations plan on oil development.

At March 31, 2013, the Company had an approximate 96% working interest in production from 300 gross wells.

Denver-Julesburg Basin, Colorado and Wyoming

Northeast Wattenberg/DJ – First quarter net production averaged approximately 2,700 Boe/d. Results from a fourth well located in the eastern portion of the Northeast Wattenberg position are very strong having a 700 Boe/d peak 24-hour IP rate and 413 Boe/d 30-day average rate. The 2013 drilling program will focus on realizing value through development and delineation drilling on the Company's approximate 40,000 net acre Northeast Wattenberg position, which lies in the core of industry activity in the area. The Company recently added a second rig in the area and plans to operate between two and four rigs in the area through the remainder of the year with a full year program that includes approximately 65 gross/42 net operated wells. The Company also expects to participate in approximately 20 non-operated wells.

At March 31, 2013, the Company had an approximate 70% working interest in production from 262 gross wells.

Piceance Basin, Colorado

Gibson Gulch – Current net production is approximately 100 MMcfe/d. Drilling in the area remains suspended as the Company focuses its operations plan on oil development. 

At March 31, 2013, the Company had an approximate 80% working interest in production from 940 gross wells in its Gibson Gulch program.

Powder River Basin, Wyoming

Powder Deep Oil Program – The Company holds a 68,740 net acre position in the Powder River Basin, a stacked oil play. The Company's position is prospective for targets in the Sussex, Shannon and Frontier formations. Following two very strong wells completed in 2012 to the Shannon and Sussex formations, the Company flowed two Frontier wells in the first quarter of 2013 that averaged just over 1,000 Boe/d for the first 30 days. In 2013, the Company plans to drill five operated wells in the area and participate in a number of non-operated wells.

At March 31, 2013, the Company had an approximate 23% working interest in production from 81 gross wells.

ADDITIONAL FINANCIAL INFORMATION

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 2013 and 2014, the Company has hedges in place as outlined in the table below. Swap positions for natural gas and NGLs are tied to regional sales points and oil hedge positions are tied to WTI and include:

  • For the second through fourth quarters of 2013, 46.8 Bcfe, or approximately 70% of production, at a weighted average price of $7.85 per Mcfe. Approximately 75% of natural gas, two-thirds of oil and one-third of NGL production/sales is hedged.
  • For 2014, approximately 35.8 Bcfe at a weighted average blended price of $7.75 per Mcfe.

The following table summarizes hedge positions as of April 19, 2013:










Natural Gas


NGLs*


Oil



 

Volume


 

Price


 

Volume


 

Price


 

Volume


 

Price

Period


MMBtu/d


$/MMBtu


Bbls/d

 


$/Bbl


Bbls/d


$/Bbl














2Q13


132.5


3.72


883


74.74


7,500


98.01

3Q13


135.0


3.71


873


74.74


8,300


97.62

4Q13


123.4


3.72


873


74.74


8,300


97.62

1Q14


75.0


3.83


-


-


5,500


94.35

2Q14


75.0


3.83


-


-


5,500


94.35

3Q14


75.0


3.83


-


-


4,500


95.09

4Q14


75.0


3.83


-


-


4,500


95.09














*NGL volumes include propane, butanes and natural gasoline. No ethane volumes are hedged.

Guidance

The Company's 2013 guidance (please reference "Forward-Looking Statements" below) is as follows. The Company may update guidance as business conditions warrant:

  • Capital expenditures of $475 to $525 million, unchanged.
  • Oil and natural gas production of 86 to 90 Bcfe, on a three-stream basis, unchanged. The Company is targeting 50%-plus growth in oil production in 2013 over 2012 and expects approximately 6% to 8% of production will be NGLs (assuming ethane rejection for the year), unchanged.
  • Lease operating costs of $62 to $67 million, unchanged.
  • Gathering, transportation and processing costs of $65 to $68 million, reduced from $72 to $75 million. The reduction is a result of a change in accounting methodology effective January 1, 2013 in which certain crude oil trucking charges are classified as a reduction in revenue rather than as a transportation expense.
  • General and administrative expenses before non-cash stock-based compensation cost of $50-54 million, unchanged.

FIRST QUARTER 2013 RESULTS WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held tomorrow morning to discuss first quarter 2013 results. Please join Bill Barrett Corporation executive management at 11:00 Eastern time/9:00 a.m. Mountain time on May 3, 2013 for the live webcast, accessed at www.billbarrettcorp.com, or join by telephone by calling 877-415-3183 (857-244-7326 international callers) with passcode 61657684. The webcast will remain available on the Company's website for approximately 30 days, and a replay of the call will be available through May 10, 2013 at call-in number 888-286-8010 (617-801-6888 international) with passcode 76337713. The Company also has tentatively scheduled its remaining 2013 earnings conference calls for August 2 and November 1, 2013, typically at 11:00 Eastern time/9:00 a.m. Mountain time.

QUARTERLY REPORT ON FORM 10-Q

The Company plans to file tomorrow its Quarterly Report on Form 10-Q for the quarter ended March 31, 2013. The 10-Q will be posted to the Company's website at www.billbarrettcorp.com and found under "SEC Filings".

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:

Annual Meeting of Stockholders

The 2013 Annual Meeting of Stockholders of Bill Barrett Corporation will be held on May 10, 2013 at 8:30 a.m. Mountain time. The meeting will be followed by a Company presentation and a question and answer period. The meeting, presentation and question and answer period will be webcast and may be accessed live and for replay on the Company's website at www.billbarrettcorp.com

Investor Conferences

Vice President of Investor Relations Jennifer Martin will participate in investor meetings at the 2nd Annual ISI Bermuda Energy One-on-One Conference to be held May 7-10, 2013. The presentation handout for this event will be posted at 5:00 p.m. Mountain time on May 6, 2013.

Chief Financial Officer Bob Howard will present at the BAML Global Energy and Power Leveraged Finance Conference May 14, 2013 at 8:30 a.m. Eastern time. The presentation will be webcast. The presentation handout for this event will be posted at 5:00 p.m. Mountain time on May 13, 2013.

DISCLOSURE STATEMENTS

Natural Gas Liquids

Effective January 1, 2013, the Company began reporting its production volumes on a three-stream basis, which separately reports NGLs extracted from the natural gas stream and sold as a separate product.  The NGL volumes identified by our gas purchasers 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.

Calculation of Natural Gas Liquids as a Percent of Sales Volumes

Prior to January 1, 2013, the Company reported natural gas production based on wellhead volumes and its natural gas revenue included the incremental revenue benefit from third party purchasers and processors when the company elected to receive NGL values from certain volumes of natural gas.  In order to provide a metric that is comparable to three-stream reporting, 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 for certain historical time periods.  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 "2013 guidance," which contains projections for certain 2013 operational and financial metrics. These forward-looking statements are based on management's judgment as of the date of this press release and include certain risks and uncertainties. Please refer to the Company's Annual Report on Form 10-K for the year ended December 31, 2012 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; ability to monetize properties in order to fund the 2013 capital expenditure program in excess of discretionary cash flow generated; development drilling and testing results; the potential for production decline rates to be greater than expected; performance of acquired properties; 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; higher than expected costs and expenses, including the  availability and cost of services and materials; unexpected future capital expenditures; economic and competitive conditions; 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; 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.

 

 

BILL BARRETT CORPORATION 

Selected Operating Highlights

(Unaudited)












Three Months Ended






March 31,






2013

2012


Production Data:







Natural gas (MMcf)



14,662

25,319



Oil (MBbls)



794

481



NGLs (MBbls)



301

 N/A 



Combined volumes (MMcfe)



21,232

28,205



Daily combined volumes (MMcfe/d)



236

310


Average Prices (before the effects of realized hedges):







Natural gas (per Mcf)



$   3.71

$   4.28

(1)


Oil (per Bbl)


(2)

78.73

89.86



NGLs (per Bbl)



46.91

 N/A 



Combined (per Mcfe)



6.17

5.37


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







Natural gas (per Mcf)



$   4.10

$   5.46

(1)


Oil (per Bbl)


(2)

81.74

88.42



NGLs (per Bbl)



48.32

 N/A 



Combined (per Mcfe)



6.58

6.41


Average Costs (per Mcfe):







Lease operating expense



$   0.88

$   0.66



Gathering, transportation and processing expense


(2)

0.73

0.97



Production tax expense



0.28

0.22



Depreciation, depletion and amortization



3.22

2.63



General and administrative expense, excluding non-cash stock-based compensation


(3)

0.71

0.49



(1)

Natural gas average prices include the effect of NGL revenues for the 2012 period.










(2)

Oil average prices for the 2013 period include an approximate $5.50 per barrel transportation deduct related to certain production within the Uinta Oil Program. These costs were previously included within Gathering, Transportation and Processing. The effect on the average per unit oil price is approximately $2.00 per barrel.








(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 Statements of Operations

(Unaudited)











Three Months Ended





March 31,





2013


2012


(in thousands, except per share amounts)













Operating and Other Revenues:







Oil, gas and NGLs

(1)

$ 134,405


$ 177,042



Other


3,872


2,134



  Total operating and other revenues


138,277


179,176









Operating Expenses:







Lease operating


18,746


18,638



Gathering, transportation and processing


15,588


27,352



Production tax 


5,951


6,207



Exploration


95


439



Impairment, dry hole costs and abandonment


7,101


564



Depreciation, depletion and amortization


68,438


74,083



General and administrative

(2)

15,148


13,800



Non-cash stock-based compensation

(2)

5,434


4,640



  Total operating expenses


136,501


145,723


Operating Income


1,776


33,453


Other Income and Expense:







Interest income and other income


39


1,563



Interest expense


(24,542)


(21,590)



Commodity derivative gain (loss)

(1)

(29,851)


44,747



  Total other income and expense


(54,354)


24,720


Income (Loss) before Income Taxes


(52,578)


58,173


Provision for (Benefit from) Income Taxes


(19,427)


22,280


Net Income (Loss)


$  (33,151)


$   35,893
















Net Income (Loss) Per Common Share







Basic


$      (0.70)


$        0.76



Diluted


$      (0.70)


$        0.76
















Weighted Average Common Shares Outstanding







Basic


47,353


47,085



Diluted


47,353


47,368









(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 March 31, 





2013


2012



Included in oil and gas production revenue:







Certain realized gains on hedges


$       2,067


$     25,465










Included in commodity derivative gain (loss):







Realized gain (loss) on derivatives not designated as cash flow hedges


$       6,453


$       3,803



Unrealized gain on derivatives not designated as cash flow hedges


(36,304)


40,944



   Total commodity derivative gain (loss)


$    (29,851)


$     44,747









(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 Condensed Balance Sheets

(Unaudited)












As of


As of





March 31, 2013


December 31, 2012








(in thousands)












Assets:




Cash and cash equivalents


$               58,522


$                        79,445


Other current assets

(1)

102,430


148,894


Property and equipment, net


2,653,125


2,611,337


Other noncurrent assets

(1)

26,967


29,773



Total assets


$         2,841,044


$                  2,869,449















Liabilities and Stockholders' Equity:






Current liabilities       

(1)

$            205,708


$                     213,133


Notes payable to bank


25,000


-


Capital lease


86,203


88,519


Senior notes


1,043,220


1,042,791


Convertible senior notes


25,344


25,344


Other long-term liabilities      

(1)

302,069


316,887


Stockholders' equity


1,153,500


1,182,775



Total liabilities and stockholders' equity

$         2,841,044


$                  2,869,449








(1)

At March 31, 2013, the estimated fair value of all of our commodity derivative instruments was a net liability of $5.8 million, comprised of: $3.6 million current assets; $1.6 million non-current assets; $9.7 million current liabilities; and $1.3 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






March 31,






2013


2012

(in thousands)













Operating Activities:






Net income (loss)


$   (33,151)


$     35,893


 Adjustments to reconcile to net cash provided by operations:







Depreciation, depletion and amortization


68,438


74,083



Impairment, dry hole costs and abandonment expense


7,101


564



Unrealized derivative (gain)\loss


36,304


(40,944)



Deferred income taxes


(19,427)


22,280



Stock compensation and other non-cash charges


6,070


3,322



Amortization of debt discounts and deferred financing costs


1,732


3,317



Loss (gain) on sale of properties


(3,519)


-



Change in assets and liabilities:








Accounts receivable


19,235


15,207




Prepayments and other current assets


818


1,191




Accounts payable, accrued and other liabilities


(14,089)


(12,434)




Amounts payable to oil & gas property owners


2,406


(3,277)




Production taxes payable


(4,992)


(2,402)











Net cash provided by operating activities


$     66,926


$     96,800

Investing Activities:






Additions to oil and gas properties, including acquisitions


(115,324)


(230,158)


Additions of furniture, equipment and other


(445)


(2,329)


Proceeds from sale of properties and other investing activities


6,424


(112)











Net cash provided by (used in) investing activities


$ (109,345)


$ (232,599)

Financing Activities:






Proceeds from debt


25,000


450,000


Principal payments on debt


(2,241)


(267,156)


Deferred financing costs and other


(1,263)


(9,350)


Proceeds from stock option exercises


-


668











Net cash provided by (used in) financing activities


$     21,496


$  174,162









Increase (Decrease) in Cash and Cash Equivalents


(20,923)


38,363









Beginning Cash and Cash Equivalents


79,445


57,331









Ending Cash and Cash Equivalents


$     58,522


$     95,694

 


BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow & Adjusted Net Income

(Unaudited)









Discretionary Cash Flow Reconciliation










Three Months Ended






March 31,






2013


2012


(in thousands, except per share amounts)














Net Income (Loss)


$ (33,151)


$ 35,893










Adjustments to reconcile to discretionary cash flow:







Depreciation, depletion and amortization


68,438


74,083



Impairment, dry hole and abandonment expense


7,101


564



Exploration expense


95


439



Unrealized derivative (gain)/loss


36,304


(40,944)



Deferred income taxes


(19,427)


22,280



Stock compensation and other non-cash charges


6,070


3,322



Amortization of debt discounts and deferred financing costs 


1,732


3,317



Loss (gain) on sale of properties


(3,519)


-


Discretionary Cash Flow


$  63,643


$ 98,954











Per share, diluted


$       1.34


$      2.09



Per Mcfe


$       3.00


$      3.51











Adjusted Net Income (Loss) Reconciliation










Three Months Ended






March 31,






2013


2012


(in thousands except per share amounts)














Net Income (Loss)


$ (33,151)


$ 35,893










Adjustments to net income (loss):







Unrealized derivative (gain)/loss


36,304


(40,944)



Impairment expense


-


-



Loss (gain) on sale of properties


(3,519)


-



One time items:








Expenses relating to compressor station fire


1,175


-




Gain on extinguishment of debt 


-


(1,601)



Subtotal Adjustments


33,960


(42,545)



Effective tax rate


37%


38%



Tax effected adjustments


21,395


(26,378)


Adjusted Net Income


$ (11,756)


$   9,515











Per share, diluted


$     (0.25)


$      0.20



Per Mcfe


$     (0.55)


$      0.34



















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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