Bill Barrett Corporation Reports 2013 Financial and Operating Results Including Discretionary Cash Flow of $281 million or $5.92 per Share - NEWS10 ABC: Albany, New York News, Weather, Sports

Bill Barrett Corporation Reports 2013 Financial and Operating Results Including Discretionary Cash Flow of $281 million or $5.92 per Share

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SOURCE Bill Barrett Corporation

DENVER, Feb. 20, 2014 /PRNewswire/ -- Bill Barrett Corporation (NYSE: BBG) today reported 2013 results and announced operational updates including:

  • Discretionary cash flow of $281.3 million or $5.92 per diluted common share
  • 30% growth in oil production, total production of 14.5 MMBoe
  • 88% growth in proved reserves at three active oil programs, driven primarily by success of the 2013 DJ Basin delineation program
  • Lower total debt by $189 million year-end 2013 from year-end 2012

Chief Executive Officer Scot Woodall commented: "In 2013, we delivered on our key operating and financial objectives. We ended 2013 having achieved a commodity balanced portfolio, successfully delineated 70% of our net Northeast Wattenberg position, substantially increased proved oil reserves and reduced our long-term debt by $189 million. In combination, these achievements position our company for growth in oil production and cash flow in 2014 and forward.

"In the DJ Basin, we tested a number of concepts in combination with delineating the majority of our position and will expand our program there in 2014. Well results in the area to date have been as projected, accounting for the variability expected in a delineation program. We plan to invest approximately 75% of the 2014 capital budget in the DJ with a three-rig program. Drilling will be focused on all three portions of our DJ Basin acreage and includes predominantly pad (multi-well) drilling. We will also drill a number of extended reach laterals. In the East Bluebell area of the Uinta Oil Program, we remain very pleased with the strong returns and will continue with one-two rigs in that area during 2014.

"In 2014, we will continue to build value through the development of our core oil programs. Our commodity balanced portfolio is expected to deliver higher margins as we grow production in 2014 and beyond."

OPERATING AND FINANCIAL RESULTS

Total estimated proved reserves at year-end 2013 were 197 million barrels of oil equivalent ("MMBoe"). Estimated proved reserves were 42% oil, 18% natural gas liquids ("NGLs") and 40% natural gas and were 42% developed and 58% undeveloped. Based on adjusted costs incurred (a non-GAAP measure, see "Costs Incurred and Reserve Information" schedule below) of $472.1 million, estimated reserve additions were made at an average cost of $8.30 per Boe.

Oil and natural gas production totaled 14.5 MMBoe in 2013 compared with 19.6 MMBoe in 2012. Oil production increased 30% to 3.5 million barrels ("MMBbls") from 2.7 MMBbls in 2012. Growth in oil production was more than offset by declines in natural gas production as a result of asset sales and natural production declines as the Company did not drill during 2013 at its natural gas programs. Fourth quarter production was 3.3 MMBoe, down from 4.7 MMBoe in the fourth quarter of 2012. 2013 exit rate production was 40% oil, adjusted for the sale of West Tavaputs and a reduced working interest in Gibson Gulch in the Piceance Basin.

Realized pricing, including the effects of the Company's hedging activities, was $82.38 per barrel of oil, $4.16 per thousand cubic feet ("Mcf") of natural gas and $28.31 per barrel of NGLs. The average benefit of hedge activity was $0.88 per Boe. While average realized prices were lower in 2013 compared with 2012, the Company realized increased revenue per unit in 2013 due to a higher proportion of oil sales versus natural gas sales. The fourth quarter of 2013 average realized prices were $82.05 per barrel of oil, $4.42 per Mcf of natural gas and $29.79 per barrel of NGLs. (See "Selected Operating Highlights" below for more detail.)

Discretionary cash flow (a non-GAAP measure, see "Discretionary Cash Flow Reconciliation" below) for 2013 was $281.3 million, or $5.92 per diluted common share, down from $402.9 million, or $8.51 per diluted common share, in 2012. The decline in discretionary cash flow is primarily due to a 26% decline in production volumes, as the Company sold assets and transitioned from a natural gas to oil focused operating program. Discretionary cash flow was $77.1 million for the fourth quarter of 2013 compared with $103.5 million for the fourth quarter of 2012.

The Company had a net loss in 2013 of $192.7 million, or ($4.06) per diluted common share, down from net income of $0.6 million, or $0.01 per diluted common share, in 2012. Net income in 2013 was affected by the same reduction in production as discretionary cash flow, as well as impairment, dry hole and abandonment expenses of $238.4 million primarily related to the sale of its West Tavaputs natural gas assets. The Company had a net loss in the fourth quarter of 2013 of $7.2 million compared with net income of $14.0 million in the fourth quarter of 2012. The fourth quarter of 2013 net loss included $10.8 million of impairment, dry hole and abandonment expenses and a $3.0 million loss on property sales.

Adjusted net income (a non-GAAP measure, see "Adjusted Net Income Reconciliation" below) for 2013 was a loss of $20.5 million, or ($0.43) per diluted common share, compared with adjusted net income of $6.9 million, or $0.15 per diluted common share, in 2012. Adjusted net income for the fourth quarter of 2013 was $5.2 million compared with $9.6 million in 2012. 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.

On December 10, 2013, the Company closed on the sale of the West Tavaputs natural gas property located in the Uinta Basin, Utah for a transaction value of $369 million. The transaction value was adjusted to the August 1, 2013 effective date and for other customary closing adjustments, providing net cash proceeds to the Company of $309 million plus the buyer's assumption of lease financing obligations associated with the property of approximately $46 million. Net cash proceeds from the transaction were applied to pay down the Company's revolving credit facility.

DEBT AND LIQUIDITY

At December 31, 2013, the Company had borrowing capacity of $484 million and total debt outstanding of $984 million. The Company had $115 million drawn on its revolving credit facility. The facility has a borrowing base of $625 million less an outstanding letter of credit for $26 million. Debt outstanding included $25 million of convertible senior notes, $400 million in 7.625% senior notes, $400 million in 7.000% senior notes and $43 million for a lease financing obligation. The Company has no significant debt maturity before 2016.

OPERATIONS

Production and Capital Expenditures

The following table lists average daily production and capital expenditures by basin for the three and twelve months ended December 31, 2013:






































Average Net Production (Boe/d)




Capital Expenditures ($millions)





Three Months Ended




Twelve Months Ended




Three Months Ended




Twelve Months Ended





December 31, 2013




December 31, 2013




December 31, 2013




December 31, 2013


Basin

































Uinta:

















Uinta Oil Program


7,305




7,239




11




204



West Tavaputs*


6,816




9,998




-




-


Piceance


15,390




17,627




-




4


Denver-Julesburg


5,126




3,530




90




210


Powder Deep Oil & Other


1,525




1,264




10




56



















Total


36,163




39,658




111




474



















*West Tavaputs daily production averaged 8,832 Boe/d for the fourth quarter as adjusted to reflect closing date of sale of December 10, 2013


















Operating and Drilling Update

As previously announced, the Company's 2014 capital budget is estimated at $500 million-$550 million and will be allocated approximately 75% to the DJ Basin, 15%-20% to the Uinta Oil Program and 5%-10% to non-operated drilling in the Powder River Basin. The capital budget anticipates drilling or participating in approximately 200 gross/100 net development wells, including approximately 85 gross non-operated wells, and includes on average three active rigs in the DJ Basin and two in the Uinta Basin.

In the DJ Basin, at December 31, 2013, the Company had an approximate 55% working interest in production from 324 gross wells. DJ Basin production increased 112% and proved reserves increased 355% in 2013 from 2012. In 2014, the Company plans to drill and complete approximately 85 gross operated and participate in approximately 45 non-operated wells. The working interests for the operated wells in the 2014 program are expected to average 70%. As of year-end 2013, the Company had approximately 76,000 net acres in the program, including approximately 40,500 net acres in the Northeast Wattenberg where the Company plans to concentrate its 2014 drilling program.

In the Uinta Basin, at December 31, 2013, the Company had an approximate 61% working interest in production from 299 gross wells. Uinta Oil Program production increased 38% and proved reserves increased 11% in 2013 from 2012. In 2014, the Company plans to drill and complete approximately 35 gross operated wells with an expected 59% (or higher depending upon partner elections) working interest. As of year-end 2013, the Company had approximately 154,000 net acres (including acreage to be earned) in the program.

In the Powder River Basin, the Company drilled and completed five wells in 2013. Powder Deep Oil Program production increased 258% and reserves increased 52% in 2013 from 2012. In 2014, the Company plans to allocate approximately 5% - 10% of its planned capital expenditures to the Powder River Deep Oil Program by participating in drilling approximately 15 non-operated wells in the area.

ADDITIONAL FINANCIAL INFORMATION

Guidance

As previously reported, the Company's 2014 guidance (please reference "Forward-Looking Statements" below) is as follows:

The Company may update the following guidance as business conditions warrant:

  • Capital expenditures of $500 million - $550 million.
  • Production of 11.0 million -12.2 million Boe.
  • Lease operating costs of $62 million - $67 million.
  • Gathering, transportation and processing costs of $43 million - $48 million.
  • General and administrative expenses, before non-cash stock-based compensation costs, of $48 million - $52 million.

2013 RESULTS WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held tomorrow, February 21, 2014, to discuss 2013 results. Please join Bill Barrett Corporation executive management at 11:00 a.m. Eastern time/9:00 a.m. Mountain time for the live webcast, accessed at www.billbarrettcorp.com, or join by telephone by calling 866-713-8563 (617-597-5311 inter-national callers) with passcode 54178378. The webcast will remain available on the Company's website for approximately 30 days, and a replay of the call will be available through February 28, 2014 at call-in number 888-286-8010 (617-801-6888 international) with passcode 62359572.

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 Financial Officer Bob Howard will participate in investor meetings at the Simmons Fourteenth Annual Energy Conference on February 28, 2014. The presentation for this event will be posted at 5:00 p.m. Mountain time on Thursday, February 27, 2014.

Chief Executive Officer Scot Woodall will present at the 42nd Annual Howard Weil Energy Conference on March 24, 2014 at 4:35 p.m. Central time. The event will not be webcast. The presentation for this event will be posted at 5:00 p.m. Mountain time on Friday, March 21, 2014.

DISCLOSURE STATEMENTS

Presentation of Natural Gas Liquids Volumes

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 distinct product.

2013 year-end reserves are presented on a three-stream basis, and year-end 2012 reserves are recalculated to reflect three-stream volumes for comparability. NGL volumes 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.

Reserve and Resource Disclosure

The SEC permits oil and gas companies to disclose proved, 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.

We may use certain terms, such as "risked resources," that the SEC's guidelines strictly prohibit us from including in filings with the SEC. While not referenced in this release, it may be referenced in the earnings conference call following this release. The calculation of risked resources, and any other estimates of reserves and resources that are not proved, probable or possible reserves are not necessarily calculated in accordance with SEC guidelines. Our estimate of risked resources is not prepared or reviewed by third party engineers, is determined using strip pricing, which we use internally for planning and budgeting purposes, and may differ from an un-risked estimate of proved, probable and possible reserves. The Company's estimate of risked resources 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; however, the Company's estimate of risked resources may not be comparable to similar metrics provided by other companies. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2013, 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.

Finding and Development Costs

Finding and development cost is a non-GAAP metric commonly used in the exploration and production industry. Calculations presented by the Company are based on costs incurred, as adjusted by the Company, divided by reserve additions and are unaudited.

Forward-Looking Statements

This press release contains forward-looking statements. Forward-looking statements include statements as to the Company's future plans, estimates, beliefs and expected performance. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could," "guidance" and similar terms and phrases. Forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company's control. Our actual results could differ materially from those discussed in these forward-looking statements. In particular, the Company is providing "2014 Operating Guidance," which contains projections for certain 2014 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. Among a number of factors, operations plans are subject to change during the year and such changes can materially affect projected results provided in the Company's guidance. Please refer to the Company's Annual Report on Form 10-K for the year ended December 31, 2013 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, including regional price differentials; costs, availability and timing of build-out of third party facilities for gathering, processing, refining and transportation; the ability to receive drilling and other permits and rights-of-way in a timely manner; development drilling and testing results; the potential for production decline rates to be greater than expected; legislative or regulatory changes, including initiatives related to hydraulic fracturing; regulatory approvals, including regulatory restrictions on federal lands; 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; 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 and to not place undue reliance on any such 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, 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


Twelve Months Ended




December 31,


December 31,




2013

2012


2013

2012

Production Data:








Oil (MBbls)


967

857


3,495

2,687


Natural gas (MMcf)


10,723

23,070


52,685

101,486


NGLs (MBbls)


573

N/A


2,199

N/A


Combined volumes (MBoe)


3,327

4,702


14,475

19,601


Daily combined volumes (Boe/d)


36,163

51,109


39,658

53,701

Average Prices (before the effects of realized hedges):








Oil (per Bbl)

(1)

$ 81.56

$ 75.03


$ 82.61

$ 79.39


Natural gas (per Mcf)

(2)

4.14

4.56


3.96

4.00


NGLs (per Bbl)


28.96

N/A


27.02

N/A


Combined (per Boe)


42.04

36.06


38.47

31.60

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








Oil (per Bbl)

(1)

$ 82.05

$ 83.84


$ 82.38

$ 84.96


Natural gas (per Mcf)

(2)

4.42

5.18


4.16

5.07


NGLs (per Bbl)


29.79

N/A


28.31

N/A


Combined (per Boe)


43.21

40.70


39.35

37.90

Average Costs (per Boe):








Lease operating expense


$ 5.13

$ 3.84


$ 4.85

$ 3.71


Gathering, transportation and processing expense

(1)

4.97

5.66


4.65

5.44


Production tax expense


1.58

0.92


1.88

1.30


Depreciation, depletion and amortization

(3)

19.53

19.89


19.33

17.49


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

(4)

3.84

2.81


3.39

2.66









(1)

Oil average prices for the year ended December 31, 2013 include an approximate $5.30 per Bbl transportation deduct related to certain production within the Uinta Oil Program. These costs were previously included within gathering, transportation and processing expense. The effect on the average per unit oil price is approximately $1.86 per Bbl.










(2)

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










(3)

The calculation of the per unit DD&A rate for the 2012 periods is adjusted to reflect the fourth quarter 2012 asset sale. The assets were excluded from the overall corporate depletion pool, and the per unit calculation adjusts the production accordingly.










(4)

This separate presentation is a non-GAAP (Generally Accepted Accounting Principles) measure. 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, which may have higher or lower costs associated with stock-based grants.

BILL BARRETT CORPORATION

Consolidated Statements of Operations

(Unaudited)
























Three Months Ended


Twelve Months Ended




December 31,


December 31,




2013


2012


2013


2012

(in thousands, except per share amounts)



















Operating and Other Revenues:










Oil, gas and NGLs

(1)

$ 141,425


$ 184,083


$ 565,555


$ 700,639


Other


(2,463)


(4,282)


2,538


(444)


Total operating and other revenues


138,962


179,801


568,093


700,195











Operating Expenses:










Lease operating


17,079


18,063


70,217


72,734


Gathering, transportation and processing


16,535


26,609


67,269


106,548


Production tax


5,257


4,320


27,172


25,513


Exploration


125


751


337


8,814


Impairment, dry hole costs and abandonment


10,752


7,690


238,398


67,869


Depreciation, depletion and amortization


64,983


75,425


279,775


326,842


General and administrative

(2)

12,791


13,196


49,069


52,222


Non-cash stock-based compensation

(2)

3,854


4,029


15,833


16,444


Total operating expenses


131,376


150,083


748,070


676,986

Operating Income


7,586


29,718


(179,977)


23,209

Other Income and Expense:










Interest income and other income


1,523


27


1,646


155


Interest expense


(19,161)


(25,477)


(88,507)


(95,506)


Commodity derivative gain (loss)

(1)

(4,461)


19,328


(23,068)


72,759


Gain (loss) on extinguishment of debt


-


-


(21,460)


1,601


Total other income and expense


(22,099)


(6,122)


(131,389)


(20,991)

Income (Loss) before Income Taxes


(14,513)


23,596


(311,366)


2,218

Provision for (Benefit from) Income Taxes


(7,314)


9,579


(118,633)


1,636

Net Income (Loss)


$ (7,199)


$ 14,017


$ (192,733)


$ 582





















Net Income (Loss) Per Common Share










Basic


$ (0.15)


$ 0.30


$ (4.06)


$ 0.01


Diluted


$ (0.15)


$ 0.30


$ (4.06)


$ 0.01





















Weighted Average Common Shares Outstanding










Basic


47,626


47,260


47,497


47,195


Diluted


47,626


47,358


47,497


47,354











(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

December 31,


Twelve Months Ended

December 31,




2013


2012


2013


2012


Included in oil and gas production revenue:










Certain realized gains on hedges


$ 1,561


$ 14,514


$ 7,463


$ 81,166












Included in commodity derivative gain (loss):










Realized gain on derivatives not designated as cash flow hedges


$ 2,344


$ 7,291


$ 5,315


$ 42,305


Unrealized gain on derivatives not designated as cash flow hedges


(6,805)


12,037


(28,383)


30,454


Total commodity derivative gain (loss)


$ (4,461)


$ 19,328


$ (23,068)


$ 72,759











(2)

This separate presentation is a non-GAAP measure. 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, which may have higher or lower costs associated with stock-based grants.

BILL BARRETT CORPORATION

Consolidated Condensed Balance Sheets

(Unaudited)












As of


As of





December 31, 2013


December 31, 2012








(in thousands)








Assets:




Cash and cash equivalents


$ 54,595


$ 79,445


Other current assets

(1)

102,652


148,894


Property and equipment, net


2,202,496


2,611,337


Other noncurrent assets

(1)

21,770


29,773



Total assets


$ 2,381,513


$ 2,869,449















Liabilities and Stockholders' Equity:






Current liabilities

(1)

$ 192,719


$ 213,133


Notes payable to bank


115,000


-


Capitalized lease obligation


38,738


88,519


Senior notes


800,000


1,042,791


Convertible senior notes


25,344


25,344


Other long-term liabilities

(1)

203,994


316,887


Stockholders' equity


1,005,718


1,182,775



Total liabilities and stockholders' equity


$ 2,381,513


$ 2,869,449








(1)

At December 31, 2013, the estimated fair value of all of the Company's commodity derivative instruments was a net liability of $3.3 million, comprised of: $0.2 million current assets, $2.5 million non-current assets and $6.0 million 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


Twelve Months Ended






December 31,


December 31,






2013


2012


2013


2012

(in thousands)





















Operating Activities:










Net income (loss)


$ (7,199)


$ 14,017


$ (192,733)


$ 582


Adjustments to reconcile to net cash provided by operations:











Depreciation, depletion and amortization


64,983


75,425


279,775


326,842



Impairment, dry hole costs and abandonment expense


10,752


7,690


238,398


67,869



Total derivative (gain)/loss


6,805


(12,037)


28,383


(30,454)



Deferred income taxes


(7,014)


7,484


(117,050)


(185)



Stock compensation and other non-cash charges


4,605


4,047


17,286


18,296



Amortization of debt discounts and deferred financing costs


1,069


1,715


5,604


8,425



(Gain) loss on extinguishment of debt


-


-


21,460


(1,601)



(Gain) loss on sale of properties


2,972


4,387


(130)


4,279



Change in assets and liabilities:












Accounts receivable


1,951


(14,986)


14,294


(10,511)




Prepayments and other current assets


(81)


(222)


1,394


1,293




Accounts payable, accrued and other liabilities


(10,799)


7,402


(35,600)


2,589




Amounts payable to oil & gas property owners


3,487


3,421


9,997


3,988




Production taxes payable


(2,568)


(510)


(5,813)


(2,976)















Net cash provided by operating activities


$ 68,963


$ 97,833


$ 265,265


$ 388,436

Investing Activities:










Additions to oil and gas properties, including acquisitions


(109,882)


(207,109)


(445,479)


(958,654)


Additions of furniture, equipment and other


(748)


(1,712)


(2,254)


(7,231)


Proceeds from sale of properties and other investing activities


309,920


328,797


310,704


328,888















Net cash provided by (used in) investing activities


$ 199,290


$ 119,976


$ (137,029)


$ (636,997)

Financing Activities:










Proceeds from debt


30,000


90,000


420,000


875,826


Principal payments on debt


(307,297)


(252,223)


(576,422)


(595,386)


Deferred financing costs and other


(1,623)


(74)


(3,049)


(10,438)


Proceeds from sale of common and preferred stock


4,732


-


6,385


673















Net cash provided by (used in) financing activities


$ (274,188)


$ (162,297)


$ (153,086)


$ 270,675













Increase (Decrease) in Cash and Cash Equivalents


(5,935)


55,512


(24,850)


22,114













Beginning Cash and Cash Equivalents


60,530


23,933


79,445


57,331













Ending Cash and Cash Equivalents


$ 54,595


$ 79,445


$ 54,595


$ 79,445














BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow & Adjusted Net Income

(Unaudited)























Discretionary Cash Flow Reconciliation













Three Months Ended


Twelve Months Ended





December 31,


December 31,





2013


2012


2013


2012

(in thousands, except per share amounts)




















Net Income (Loss)


$ (7,199)


$ 14,017


$ (192,733)


$ 582












Adjustments to reconcile to discretionary cash flow:










Depreciation, depletion and amortization


64,983


75,425


279,775


326,842


Impairment, dry hole and abandonment expense


10,752


7,690


238,398


67,869


Exploration expense


125


751


337


8,814


Unrealized derivative (gain) loss


6,805


(12,037)


28,383


(30,454)


Deferred income taxes


(7,014)


7,484


(117,050)


(185)


Stock compensation and other non-cash charges


4,605


4,047


17,286


18,296


Amortization of debt discounts and deferred financing costs


1,069


1,715


5,604


8,425


(Gain) loss on extinguishment of debt


-


-


21,460


(1,601)


(Gain) loss on sale of properties


2,972


4,387


(130)


4,279

Discretionary Cash Flow


$ 77,098


$ 103,479


$ 281,330


$ 402,867













Per share, diluted


$ 1.62


$ 2.19


$ 5.92


$ 8.51


Per Boe


$ 23.17


$ 22.01


$ 19.44


$ 20.55
















Adjusted Net Income (Loss) Reconciliation













Three Months Ended


Twelve Months Ended





December 31,


December 31,





2013


2012


2013


2012

(in thousands except per share amounts)




















Net Income (Loss)


$ (7,199)


$ 14,017


$ (192,733)


$ 582












Adjustments to net income (loss):










Unrealized derivative (gain) loss


6,805


(12,037)


28,383


(30,454)


Impairment expense


9,987


239


226,551


37,348


(Gain) loss on sale of properties


2,972


4,387


(130)


4,279


One time items:











Expenses relating to compressor station fire


215


-


1,582


-



(Gain) loss on extinguishment of debt


-


-


21,460


(1,601)


Subtotal Adjustments


19,979


(7,411)


277,846


9,572


Effective tax rate


38%


41%


38%


34%


Tax effected adjustments


12,387


(4,372)


172,265


6,327

Adjusted Net Income (Loss)


$ 5,188


$ 9,645


$ (20,468)


$ 6,909













Per share, diluted


$ 0.11


$ 0.20


$ (0.43)


$ 0.15


Per Boe


$ 1.56


$ 2.05


$ (1.41)


$ 0.35


































Discretionary cash flow and adjusted net income are non-GAAP measures. These measures 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 (loss) for unusual items to allow for a more consistent comparison from period to period. In addition, the Company believes that 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 that 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 necessarily all, items that affect net income (loss) and may vary among companies, the amounts presented may not be comparable to similarly titled measures of other companies.












BILL BARRETT CORPORATION

Costs Incurred and Reserve Information

(Unaudited)



















2013


2012


2011


($ in millions)













TOTAL CAPITAL EXPENDITURES

$474.0


$962.6


$987.3



Furniture, fixtures and equipment and real estate

(1.9)


(6.9)


(10.6)



Change in asset retirement obligation

3.5


8.3


12.1


TOTAL COSTS INCURRED (1)

475.6


964.0


988.8


















TOTAL COSTS INCURRED








Exploration costs

2.5


32.5


20.8



Development costs

455.5


754.2


607.7



Acquisition costs:








Unproved properties

13.7


163.0


183.4



Proved properties

0.4


6.0


164.8



Change in asset retirement obligation

3.5


8.3


12.1


TOTAL COSTS INCURRED (1)

475.6


964.0


988.8



less: asset retirement obligation

(3.5)


(8.3)


(12.1)



less: Capitalized interest

-


(0.5)


(1.4)



Adjusted costs incurred

$472.1


$955.2


$975.3










RESERVE ADDITIONS (MMBoe)








Extensions, discoveries and other additions

75.6


31.2


35.3



Revisions of previous estimates based on performance

(13.1)


(7.3)


6.3



Revisions of previous estimates based on price or aging

(5.6)


(21.5)


0.9



Purchases of reserves in place

-


0.3


16.4



RESERVE ADDITIONS MMBoe

56.9


2.7


58.9


















SALES INFORMATION (2)








Property sales

$354.5


$329.0


$ 2.0



Sales of reserves (MMBoe)

40.5


36.5


-


















(1)

Costs Incurred is a defined capital expenditure used in the discussion of proved reserves in the Company's Form 10-K for the years indicated.



(2)

2013 property sales includes cash proceeds plus purchaser's assumption of capital lease obligation for compressor units.

©2012 PR Newswire. All Rights Reserved.

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