Bill Barrett Corporation Announces 66% Increase in Oil Reserves and 80% Increase in 2012 Oil Production and Provides 2013 Guidance

DENVER, Jan. 31, 2013 /PRNewswire/ -- Bill Barrett Corporation (the "Company") (NYSE: BBG) announced today certain unaudited operating results and estimated reserves for year-end 2012 and certain operating guidance for 2013.  Highlights from 2012 include (unaudited):

  • Production growth of 10% to 118 Bcfe, including 80% growth in oil production
  • Proved reserves of 1.04 Tcfe, including 66% growth in oil reserves
  • Proved reserves plus risked resources of 2.9 Tcfe
  • Continued DJ Basin success with 82% growth in proved reserves and nearly four-fold increase in resource drilling locations
  • Strong balance sheet with $825 million line of credit undrawn

Interim Chief Executive Officer and Chief Operating Officer Scot Woodall commented: "During the past two years we have focused on building a better oil-to-natural gas balance in our asset portfolio, and we exit 2012 recognizing substantial success with this challenging transition. Over the past two years, our production mix increased to 24% oil exiting 2012 (pro forma for the fourth quarter asset sale) compared with 7% oil exiting 2010. Our proved reserves were 29% oil at year-end 2012 compared with 7% at year-end 2010 and drilling locations targeting oil increased to nearly 2,900 from approximately 400, year-end 2012 compared with year-end 2010. Total production was up 10% in 2012 compared with 2011 with oil production up 80%, meeting our targeted growth.

"Our investment in oil programs has delivered two solid, scalable development programs in the Uinta and Denver-Julesburg ("DJ") basins. In 2013, we are focused on developing the inventories we have built while optimizing the margins and returns at these programs. These basins each offer strong returns and notable upside through downspacing and operating efficiencies that correspond with increasing scale. Our $475 to $525 million capital program in 2013 assumes six active rigs in these two basins and includes a total of approximately 180 gross/100 net wells (including non-operated wells.) Approximately 97% of our capital budget is directed towards our oil programs, and we are targeting 50% to 55% growth in oil production in 2013. Execution is our theme for 2013, and we have realigned our senior technical personnel to focus on our development programs and to deliver top tier operational performance."

Chief Financial Officer Bob Howard adds: "We enter 2013 in a strong financial position with zero drawn on the $825 million borrowing base available from the Company's credit facility. The borrowing base was redetermined at year-end, and it is expected to remain virtually unchanged with the spring scheduled redetermination. We are committed to ending 2013 with no increase in our total debt and will be actively managing our portfolio to generate proceeds from the sale of assets to meet our funding requirements. In addition, we have hedges in place to support our expected cash flows for 2013 including 7,000 barrels per day of oil ("Bopd") at $98.00, about 60-65% of expected oil production, and 133 million cubic feet per day ("MMcf/d") of natural gas at $3.70, or about 75% of expected natural gas production."

2012 YEAR-END ESTIMATED RESERVES, PRODUCTION AND CAPITAL EXPENDITURES

(The following information is unaudited and preliminary. Audited and final results will be provided in our Annual Report on Form 10-K for the year ended December 31, 2012 currently planned to be filed with the Securities and Exchange Commission ("SEC") by the end of February 2013.)

2012 Year-End Reserves

2012 year-end estimated proved reserves of 1.04 trillion cubic feet equivalent ("Tcfe") reflect 74% growth in proved reserves at the Company's three active oil programs in the Uinta Basin, DJ Basin and Powder River Basin plus natural gas drilling additions at West Tavaputs and Gibson Gulch. This growth was more than offset by: the fourth quarter asset sale that included 219 billion cubic feet equivalent ("Bcfe") of proved reserves as of year-end 2012; and, negative revisions of 221 Bcfe in West Tavaputs and Gibson Gulch related to the significantly lower natural gas price used to determine reserves, the Company's expectation to not drill in these areas during 2013, and negative engineering revisions at West Tavaputs associated with performance of 20-acre spacing on a portion of the Company's acreage position.

                       

Table: Reserve Reconciliation 2011 to 2012


Reserves

Bcfe



2011 year-end estimated proved reserves

1,365

2012 estimated production

(118)

2012 reserve dispositions

(219)

2012 revisions at natural gas programs (described above)

(221)

2012 reserve additions, acquisitions and all other revisions

237



2012 year-end estimated proved reserves

1,044

Year-end estimated proved reserves were 29% oil and 71% natural gas and were 59% developed and 41% undeveloped. The present value of proved reserves, or PV10, was estimated at $1.4 billion, which is down $700 million from year-end 2011, primarily due to the fourth quarter 2012 asset sale and impact from a 35% decline in the natural gas commodity price used for the calculation. The present value calculation is before income taxes and is based on a Colorado Interstate Gas ("CIG") natural gas price of $2.56 per MMBtu, a West Texas Intermediate ("WTI") oil price of $91.21 per barrel and a 10% per annum discount rate. PV10 information is provided because it is a commonly used metric in the exploration and production industry. PV10 sensitivity to the natural gas price at +$1.00 and + $2.00 is provided below:

           

Table: PV10 Sensitivity






Commodity Price

Natural Gas

Oil

Equivalent

PV10


(Bcf)

(MMBbls)

(Bcfe)

(Millions)






2012: $2.56 gas, $91.21 oil

739

51

1,044

$1,401

+$1.00/$0: $3.56 gas, $91.21 oil

817

51

1,123

$1,720

+$2.00/$0: $4.56 gas, $91.21 oil

839

51

1,146

$2,091

   

2012 Year-End Risked Resources

In addition to estimated proved reserves, the Company estimates it has risked resources of 1.9 Tcfe at December 31, 2012, for total proved reserves plus risked resources of approximately 2.9 Tcfe. See "Reserve and Resource Disclosure" note below.

          

Table: Proved Reserves, Risked Resources and Drilling Locations







Proved Plus






Proved Reserves

Percent


Risked Resources

Percent


Gross Drilling



Bcfe

Oil


Bcfe

Oil


Locations










Gibson Gulch, Piceance


401

6%


511

6%


528










Uinta Oil Program, Uinta


282

80%


967

79%


1,696










West Tavaputs, Uinta


265

1%


885

1%


588










Denver-Julesburg Basin


75

50%


532

61%


1,082










Powder River Basin Oil


21

84%


40

85%


107










Other


-

-


1

-


-










Total


1,044

29%


2,936

40%


4,001

 

2012 Production

Estimated production for 2012 was 117.6 Bcfe. Total production was up 10% from 2011 and oil production was up 80% to 2.69 million barrels from 1.49 million barrels in 2011. Fourth quarter 2012 production of 28.2 Bcfe was negatively affected by approximately 1.2 Bcf due to the previously announced fire at a West Tavaputs compressor station (with 90% of pre-fire production back on-line.)

 

Table: 2012 Production and Sales Volumes by Quarter



1Q12

2Q12

3Q12

4Q12

2012

Reported Production Volumes






Oil (Bbls/d)

5,286

6,972

7,766

9,315

7,341

Natural gas, including NGLs (MMcf/d)

278

287

294

251

277







Reported Realized Prices:






Oil (per Bbl)

$  88.42

$  84.86

$  84.08

$  83.84

$  84.96

Natural gas, including NGLs (per Mcf)

$    5.46

$    4.77

$    4.90

$    5.18

$    5.07







Sales* Volumes:






Oil (Bbls/d)

5,286

6,972

7,766

9,315

7,341

Natural gas sold as dry gas (MMcf/d)

257

262

265

223

252

NGLs (Bbls/d)

11,985

11,439

10,341

8,687

10,615


*See Disclosure Statements below.

 

Entering 2013, production will be affected by the sale of natural gas assets that closed December 31, 2012 and ethane rejection reducing the natural gas liquids ("NGL") volumes. Calculated as three-streams and adjusted for those factors, January production is estimated at approximately 220 million cubic feet equivalent per day ("MMcfe/d) with 22% oil, 70% natural gas and 8% NGLs.

2012 Capital Expenditures

Preliminary, unaudited capital expenditures for 2012 were $963 million and included drilling 288 gross/185 net wells, including participation in non-operated wells. Capital included $677 million for drilling at development programs, $124 million for acquisitions and leaseholds to expand development programs, $62 million for infrastructure and corporate, and $100 million for exploration drilling and leaseholds.  During 2012, drilling activity was stopped in West Tavaputs and Piceance in the second and third quarters, respectively, as a result of low natural gas and NGL prices. The following is a summary of unaudited capital expenditures by area and wells spud for 2012:

 

Table: Capital Expenditures and Wells Spud by Area



Wells Spud

Capital Expenditures

Basin

(gross)

(millions)




Uinta:



Uinta Oil Program

105

$   284

West Tavaputs

16

107

Piceance

91

200

Denver-Julesburg

53

141

Other including exploration and corporate

23

107

Acquisitions at development programs


124




Total

288

$   963


(Includes non-operated wells)

 

Other

Under successful efforts accounting, the Company expects to record impairment, dry hole and abandonment expenses in the fourth quarter of 2012 of approximately $7.7 million (pre-tax), of which approximately $5.1 million relates primarily to one exploratory dry hole in the Southern Alberta Basin, approximately $2.4 million relates to abandonment and $0.2 million relates to impairment.  For the full year 2012, impairment, dry hole and abandonment expenses are estimated at $67.9 million of which $21.0 million relates to dry holes, $37.3 million to impairment and $9.6 million to abandonment. These amounts are unaudited and subject to further review by management and independent auditors.

2012 YEAR-END DEBT AND LIQUIDITY

At December 31, 2012 the Company had borrowing capacity of $799.0 million and total debt outstanding of $1.17 billion. The Company had zero drawn on its revolving credit facility. The facility has a borrowing base of $825.0 million less an outstanding letter of credit for $26.0 million.  Debt outstanding included $25.3 million of convertible senior notes, $250.0 million in 9.875% senior notes, $400.0 million in 7.625% senior notes, $400.0 million in 7.000% senior notes and $97.6 million for a lease financing obligation. 

2013 OPERATING GUIDANCE

Effective as of January 1, 2013, the Company plans to report its reserves and production in three streams, separating NGLs from the natural gas stream. In an effort to put year-end 2012 results and 2013 guidance into better context, certain results and data are presented below in both formats.

The Company plans to spend between $475 and $525 million for capital expenditures in 2013.  The Company expects to participate in approximately 180 gross/100 net development wells, including approximately 30 non-operated wells, and which will include approximately 90 gross wells at the Uinta Oil Program and approximately 85 gross wells in the DJ Basin plus at least five wells in the Powder River Oil Program.

The Company is providing the following guidance for its 2013 activities. See "Forward-Looking Statements" below.

Table: Guidance for 2013 Capital Expenditures, Production and Costs









Capital expenditures ($millions)

$475 – $525

Production (2-stream basis; Bcfe)

83 – 87

Production (3-stream basis; Bcfe)

86 – 90

Operating costs: Lease operating ($millions)

$62 – $67

Operating costs: Gathering, processing and transportation ($millions)

$72 – $75

General and administrative, before non-cash, stock based compensation and including approximately $4 million of estimated one-time employee transition costs ($millions)

$50 – $54

 

Production guidance for 2013 projects 50%-55% growth in oil production compared with 2012 and estimates approximately 6%-8% of production will be NGLs under three-stream reporting. NGL production declines from 2012 are due to the partial sale of Gibson Gulch and assumes the Company rejects ethane for the full year. Lower projected production in 2013 compared to 2012 is due to the sale of natural gas assets and ceasing drilling at the Company's natural gas programs.

COMMODITY HEDGES UPDATE

The Company has hedges in place for approximately 70% of forecast 2013 production. Natural gas hedges are all tied to Rocky Mountain regional pricing. Generally, it is the Company's strategy to hedge 50% to 70% of production through basis at regional sales points on a forward 12-month basis in order to reduce the risks associated with unpredictable future commodity prices and to provide certainty for a portion of its cash flow to support its capital expenditure program.

The following table summarizes hedge positions as of January 25, 2013:

 



Natural Gas


NGLs*


Oil



 

Volume


 

Price


 

Volume


 

Price


 

Volume


 

Price

Period


MMBtu/d


$/MMBtu


Gallons

Qtr Total


$/Gal


Bopd


$/Bbl














1Q13


150.0


3.69


3,375,000


1.78


7,000


98.00

2Q13


140.0


3.70


3,375,000


1.78


7,000


98.00

3Q13


140.0


3.70


3,375,000


1.78


7,000


98.00

4Q13


123.4


3.72


3,375,000


1.78


7,000


98.00

1Q14


75.0


3.83


-


-


3,200


96.17

2Q14


75.0


3.83


-


-


3,200


96.17

3Q14


75.0


3.83


-


-


3,200


96.17

4Q14


75.0


3.83


-


-


3,200


96.17


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

 

ADDITIONAL INFORMATION

Total estimated proved reserves year-end 2012 by commodity, presented in both two-stream and three-stream formats were as follows:

 

Table: Year-end 2012 Total Proved Reserves Two & Three Stream Formats



2 Streams

3 Streams




Oil (MMBbls)

50.8

50.8

Natural gas liquids (MMBbls)

-

30.5

Natural gas (Bcf)

739.1

682.1




Total Bcfe

1,043.7

1,169.9

 

Estimated proved reserves reported in three streams were 26% oil, 58% natural gas and 16% NGLs.

UPCOMING EVENTS

Credit Suisse Conference

Interim Chief Executive Officer and Chief Operating Officer Scot Woodall will participate in investor meetings on February 6-7, 2013 at the Credit Suisse Energy Summit 2013. The Company will post an updated investor presentation to be used for this event on Tuesday, February 5, 2013 at 5:00 p.m. Mountain time. 

Simmons Conference

Chief Financial Officer Bob Howard will participate in investor meetings on March 1, 2013 at the Simmons Thirteenth Annual Energy Conference. The Company will post an updated presentation to be used for this event on Thursday, February 28, 2013 at 5:00 p.m. Mountain time.

DISCLOSURE STATEMENTS

Year-end 2012 Financial Results Presented are Unaudited

Results for year-end 2012 presented in this press release are preliminary and unaudited. These unaudited amounts are subject to further review by management and independent auditors.

Calculation of Natural Gas Liquids as a Percent of Sales Volumes

The Company's 2012 natural gas production included in this press release is based on wellhead volumes and its 2012 natural gas revenue includes the incremental revenue benefit of receiving NGL sales prices for NGL volumes processed by the purchasers of our natural gas deliveries.  Many oil and gas producing companies report NGL volumes and revenues separate from natural gas volumes and revenues.  In order to provide a metric that is comparable to other oil and gas production companies, the Company is providing the percentage of total company sales volumes that receive NGL pricing based on the barrel of oil equivalent NGL volumes for revenues received from our gas purchasers.  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.

Effective January 1, 2013, the Company intends to report its production volumes on a three-stream basis, which separately reports NGLs extracted from the natural gas stream and sold as a separate product. 

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 in this release, such as "risked resources," that the SEC's guidelines strictly prohibit us from including in filings with the SEC. 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, 2011, 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.

Forward-Looking Statements

This press release contains forward-looking statements, including preliminary and unaudited results for 2012 and projections for future events. In particular, the Company is providing "2013 Operating 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, 2011 filed with the SEC, and other filings including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, for a list of certain risk factors that may affect these forward-looking statements. The Company provided unaudited estimates of certain year-end financial results, which are subject to revision in our audited financial statements to be included in our Annual Report on Form 10-K to be filed in February 2013.

Actual results may differ materially from Company projections and can be affected by a variety of factors outside the control of the Company including, among other things: oil, NGL and natural gas price volatility; costs and availability of third party facilities for gathering, processing, refining and transportation; the ability to receive drilling and other permits and rights-of-way; regulatory approvals, including regulatory restrictions on federal lands; legislative or regulatory changes, including initiatives related to hydraulic fracturing; exploration risks such as drilling unsuccessful wells; higher than expected costs and expenses, including the  availability and cost of services and materials; unexpected future capital expenditures; economic and competitive conditions; debt and equity market conditions, including the  availability and costs of financing to fund the Company's operations; the ability to obtain industry partners to jointly explore certain prospects, and the willingness and ability of those partners to meet capital obligations when requested; declines in the values of our oil and gas properties resulting in impairments; changes in estimates of proved reserves; development drilling and testing results; the potential for production decline rates to be greater than we expect; performance of acquired properties; compliance with environmental and other regulations; derivative and hedging activities; risks associated with operating in one major geographic area; the success of the Company's risk management activities; title to properties; litigation; environmental liabilities; and, other factors discussed in the Company's reports filed with the SEC.  Bill Barrett Corporation encourages readers to consider the risks and uncertainties associated with projections and other forward-looking statements. In addition, the Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances.

ABOUT BILL BARRETT CORPORATION

Bill Barrett Corporation (NYSE: BBG), headquartered in Denver, Colorado, explores for and develops 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.

SOURCE Bill Barrett Corporation



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