2014

Bill Barrett Corporation Reports Third Quarter 2013 Results, Including Strong Well Results from the DJ Basin

DENVER, Oct. 31, 2013 /PRNewswire/ -- Bill Barrett Corporation (NYSE: BBG) today reported third quarter 2013 results and announced operational updates highlighted by:

  • Oil, natural gas and natural gas liquids ("NGL") production of 21.4 billion cubic feet equivalent ("Bcfe")
  • Oil production averaging 9,880 barrels per day, or 25% of production
  • Average realized price of $6.81 per Mcfe, reflecting the benefit of growing oil volumes. Oil sales accounted for 56% of pre-hedge sales revenues
  • Discretionary cash flow of $74.9 million, or $1.58 per diluted common share
  • Two new delineation wells in the southern portion of the Company's Northeast Wattenberg, Denver-Julesburg ("DJ") Basin acreage position. Initial production ("IP") rates from the two wells averaged more than 1,000 barrels of oil equivalent per day ("Boe/d") per well over a peak 24 hours and averaged approximately 500 Boe/d per well over 30 days
  • Six new pad wells, adjacent to earlier pad drilling in the Northeast Wattenberg area, averaged more than 1,000 Boe/d per well over a peak 24 hours and averaged approximately 600 Boe/d per well over 30 days
  • Signed agreement for $371 million sale of West Tavaputs natural gas assets, expected to close by year-end

Chief Executive Officer and President Scot Woodall commented: "Execution of our 2013 plan is right on track. Our commitment to complete an asset sale and maintain our debt level at or below year-end 2012 is being accomplished. Our objective to delineate all of our Northeast Wattenberg acreage position, test the development potential of the B and C benches of the Niobrara formation and the Codell formation as well as test down-spacing to 80-acres is all well underway. Year-to-date in the Wattenberg, we have drilled 43 wells in our 65-well program and have completed 26. Wells spud include 6 in the C bench, 4 in the Codell, and 8 in the southern acreage area. We are providing results from 8 wells today that demonstrate strong flow rates and continued success in the southern area. Further, we have completed the 2013 drilling plan in the Uinta Oil Program with 57 wells drilled and 56 completed, including 20 wells in the East Bluebell acreage position. We are diligently working to complete our 2013 drilling program, positioning our Company for solid oil reserve growth at year-end and cash flow growth in 2014."

OPERATING AND FINANCIAL RESULTS

Oil, natural gas and NGL production totaled 21.4 Bcfe in the third quarter of 2013. As of January 1, 2013, the Company adopted three-stream reporting for its natural gas, oil and NGL production volumes. As of the third quarter of 2013, to allow for consistent reporting of production volumes between periods whether we recover ethane as a separate sales product or elect ethane rejection, the Company modified its methodology for reporting ethane volumes.  Prior to the third quarter of 2013, ethane recovery rejected at the processing plant was included with natural gas production volumes; these ethane volumes are now included in the NGL volumes.  (On a comparable two-stream basis, production was 19.6 Bcfe in the third quarter of 2013.) Production is down from 31.3 Bcfe reported in the third quarter of 2012 (reported on a two-stream basis), primarily due to asset sales closed in the fourth quarter of 2012.  Oil production of 9,880 barrels per day ("Bbls/d") in the third quarter of 2013 was up 27% compared with the third quarter of 2012, including a 37% increase at the Uinta Oil Program and a 100% increase in the DJ Basin, partially offset by a reduction in oil production due to properties that were sold in the fourth quarter of 2012. Production for the first nine months of 2013 was 66.9 Bcfe compared with 89.4 Bcfe in the first nine months of 2012. Production for the first nine months of 2013 reflects the revised reported production volumes for the first and second quarters, as presented in the table below.

Pre-hedge pricing in the third quarter of 2013 was $6.88 per thousand cubic feet equivalent ("Mcfe"), up 35% from the third quarter of 2012, reflecting the higher contribution from oil production in the commodity mix. The average realized price in the third quarter of 2013 was $6.81 per Mcfe, negatively affected by $0.07 per Mcfe as realized benefits on natural gas hedges were more than offset by realized losses on oil hedges. The average realized prices by commodity for the third quarter of 2013 were $83.51 per barrel ("Bbl") of oil, $4.30 per Mcfe of natural gas and $28.74 per Bbl of NGLs. (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. 2013 production reflects the effects of the 2012 asset sale, the change to three-stream reporting, and the change in methodology to report rejected ethane in the NGL stream:




3Q12

4Q12

1Q13

2Q13

3Q13

Reported Production Volumes 3-Stream:








Oil (Bbls/d)


N/A

N/A

8,827

9,060

9,880


Natural gas (MMcf/d)


N/A

N/A

163

157

141


NGLs (Bbls/d)


N/A

N/A

6,469

5,979

5,438








Reported Production Volumes 2-Stream:








Oil (Bbls/d)


7,766

9,315

N/A

N/A

N/A


Natural gas, including NGLs (MMcf/d)


294

251

N/A

N/A

N/A








Sales Volumes:1








Oil (Bbls/d)


7,766

9,315

8,827

9,060

9,880


Natural gas sold as dry gas (MMcf/d)


265

223

163

157

141


NGLs (Bbls/d)


10,341

8,687

6,469

5,979

5,438








Reported Realized Prices:2








Oil (per Bbl)


$

84.08

$

83.84

$

81.74

$

82.11

$

83.51


Natural gas sold as dry gas (per Mcf)


N/A

N/A

$

4.10

$

3.92

$

4.30


Natural gas including benefit of NGL realizations (per Mcf)


$

4.90

$

5.18

N/A

N/A

N/A


NGLs (per Bbl)


N/A

N/A

$

25.01

$

29.90

$

28.74



(1)

(see "Disclosure Statements" below)

(2)

(see footnote 3 under "Selected Operating Highlights" below)

Discretionary cash flow (a non-GAAP measure, see "Discretionary Cash Flow Reconciliation" below) in the third quarter of 2013 was $74.9 million, or $1.58 per diluted common share, down from $105.8 million in the third quarter of 2012. The decline in discretionary cash flow in the third quarter of 2013 compared with the third quarter of 2012 was primarily due to lower production (described above). Cash operating costs (lease operating expense, gathering transportation and processing expense and production tax expense) per unit were higher in the third quarter of 2013 at $1.99 compared with the third quarter of 2012 at $1.65, as oil is more costly to produce per unit than natural gas. In addition, higher per unit lease operating expenses in the third quarter of 2013 were a result of  workover activity as well as non-recurring charges associated with the sale of the West Tavaputs assets, changes in the artificial lift systems in the DJ Basin and weather-related road work in both the Uinta and DJ Basins. Higher costs per Mcfe were more than offset by higher realized prices per Mcfe.  For the first nine months of 2013, discretionary cash flow was $204.2 million compared with $299.4 million for the first nine months of 2012.

Net loss in the third quarter of 2013 was $166.7 million, or ($3.51) per diluted common share, compared with a net loss of $52.6 million in the third quarter of 2012. The net loss in the quarter was predominantly due to impairment charges of $216.6 million, associated with the expected 2013 sale of the West Tavaputs assets and exploration properties located in the Southern Alberta Basin in Montana. The third quarter loss was also affected by the same items that affected discretionary cash flow (described above) and higher per unit depreciation and depletion expense. For the first nine months of 2013, net loss was $185.5 million compared with a net loss of $13.4 million in the first nine months of 2012.  Adjusted net income (loss) for the third quarter of 2013 (a non-GAAP measure, see "Adjusted Net Income (Loss) Reconciliation" below) was a loss of $4.4 million, or ($0.09) per diluted common share, compared with a loss of $9.7 million, or ($0.20) per diluted common share, in the third quarter of 2012. Adjusted net income (loss) removes the effect of non-recurring charges such as unrealized derivative gains and losses, impairment expenses, property sales and certain one-time items. For the first nine months of 2013, adjusted net income was a loss of $25.7 million compared with a loss of $2.7 million for the first nine months of 2012.

DEBT AND LIQUIDITY

At September 30, 2013, the Company had total debt outstanding (principal balance) of $1,306.2 million, including $390.0 million drawn on its $825.0 million revolving credit facility due 2016.  The Company anticipates paying down the revolving credit facility with proceeds from the sale of West Tavaputs. In addition, the purchaser of West Tavaputs will assume $46.0 million of the Company's lease financing obligation. The Company has no term debt due before 2019.

OPERATIONS

Production, Wells Spud and Capital Expenditures

The following table lists production, wells spud and total capital expenditures by basin for the three and nine months ended September 30, 2013:



Three Months Ended September 30, 2013

Nine Months Ended September 30, 2013



Average Net
Daily
Production
(MMcfe)

Wells
Spud
Gross*

Capital
Expenditures 
(in millions)

Average Net
Daily
Production
(MMcfe)

Wells
Spud
Gross*

Capital
Expenditures
(in millions)

Basin







Uinta:








Uinta Oil Program

48

8

$61

43

56

$193


West Tavaputs

58

0

(2)

66

0

0

Piceance

100

0

0

110

0

5

Denver-Julesburg

20

22

64

18

34

120

Powder River Deep Oil & Other

7

0

3

8

5

45

Total

233

30

$126

245

95

$363

* Operated wells

Operating and Drilling Update

The Company anticipates drilling or participating in approximately 177 gross/95 net development wells in 2013, including participation in approximately 50 gross non-operated wells.

Denver-Julesburg Basin, Colorado and Wyoming

Northeast Wattenberg/DJ Basin - Third quarter net production averaged 3,300 Boe/d, a 111% increase from the third quarter of 2012 and up 12% sequentially. Today, the Company is providing results on two new delineation wells in the southern portion of the Northeast Wattenberg. One of these wells had a 24-hour peak IP rate of 1,270 Boe/d and a 30-day rate of 560 Boe/d, and the second a 24-hour peak IP rate of 850 Boe/d and a 30-day rate of 430 Boe/d.  The Company is also providing results on six wells drilled on a pad on the western portion of the Northeast Wattenberg position where 24-hour peak IP rates averaged more than 1,000 Boe/d per well and 30-day rates averaged approximately 600 Boe/d per well. The wells were drilled to approximately 6,100 feet vertical depth with approximate 4,000 foot laterals and were completed with 17 fracture stimulation stages for an average cost of $4.2 million.

The Company is operating four active rigs in the area and is on track to drill approximately 65 gross/45 net operated wells by year-end, of which approximately 50 gross operated wells should be completed by year-end. The 2013 drilling program is focused on delineating the Company's approximate 40,000 net acre Northeast Wattenberg acreage position, testing 80-acre down-spacing, and testing the development potential of the Niobrara B and C benches along with the deeper Codell formation. The 2013 drilling schedule was modified slightly to include drilling a 10-well pad in its core Wattenberg position, deferring spud dates of wells in the western area, as the Company intends to exploit its entire 75,000-plus acre position in the DJ Basin over the coming years. Year-to-date through October 2013, in the DJ Basin the Company has spud 43 wells of which 26 are completed. The Company also anticipates participating in approximately 20 non-operated wells for the full year. 

At September 30, 2013, the Company had an approximate 80% working interest in production from 293 gross wells, including approximately 200 vertical wells mostly acquired in DJ Basin property acquisitions. As of the end of the third quarter of 2013, the Company had approximately 75,300 net acres in the DJ Basin program.

Uinta Basin, Utah

Uinta Oil Program (Blacktail Ridge, Lake Canyon, East Bluebell and South Altamont) - Third quarter net production averaged 7,950 Boe/d, up 43% from the third quarter of 2012 and up 18% sequentially. The Company has completed drilling a 57-well program for 2013.

Performance from the East Bluebell/South Altamont areas continues to be particularly strong with returns exceeding program averages, benefiting from consistent geology and lower costs. In East Bluebell, the Company is moving forward with 80-acre spacing,  and the area offers the potential for further downspacing. Drilling in these areas are vertical wells targeting the Wasatch and Green River formations.

The Company continues to test two vertical 80-acre spacing pilot programs in the Blacktail Ridge area.  Results are encouraging, and the Company will continue to assess each area. The Company continues to optimize drilling and operating costs in this sizable program.

At September 30, 2013, the Company had an approximate 76% working interest in production from 295 gross wells. As of the end of the third quarter of 2013, the Company had approximately 151,400 net acres (including acreage to be earned) in the Uinta Oil program.

West Tavaputs - Third quarter net production averaged 58 million cubic feet equivalent per day ("MMcfe/d"). As previously announced, the Company has entered into an agreement to sell this property and the transaction is expected to close by year-end.

At September 30, 2013, the Company had an approximate 97% working interest in production from 301 gross wells in West Tavaputs.

Piceance Basin, Colorado

Gibson Gulch - Third quarter net production averaged 100 MMcfe/d.  As previously described, the production reporting of ethane rejected at the processing plant has been moved from the natural gas stream to the NGL stream for the three quarters of 2013. Considering this revised method, Piceance production in the first and second quarters of 2013 was 119 MMcfe/d and 112 MMcfe/d, respectively. Drilling in the area remains suspended as the Company focuses its operations plan on oil development. 

At September 30, 2013, the Company had an approximate 81% working interest in production from 956 gross wells and held 12,600 net acres in its Gibson Gulch program.

Powder River Basin, Wyoming

Powder Deep Oil Program - Third quarter net production averaged approximately 1,140 Boe/d. The Company completed its drilling program in the first half of 2013 with five wells to the Shannon formation, and all of these wells continue to have positive results. During 2013, the Company is actively participating in approximately 15 non-operated wells throughout the area targeting the Shannon, Frontier, Parkman and Turner formations, five of which have extended reach laterals. The Company believes the Powder Deep Oil Program offers a new, growing oil position in a relatively low risk basin.

At September 30, 2013, the Company had an approximate 52% working interest in production from 99 gross wells and held 68,300 net acres in its Powder Deep Oil Program.

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 the remainder of 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 fourth quarter of 2013, 15.7 Bcfe is hedged, or approximately 70% of production, at a weighted average price of $8.13 per Mcfe.
  • For 2014, approximately 46.0 Bcfe is hedged at a weighted average blended price of $8.80 per Mcfe.
  • For 2015, approximately 6.9 Bcfe is hedged at a weighted average blended price of $10.06 per Mcfe.

The following table summarizes hedge positions as of October 21, 2013:



Natural Gas


NGLs*


Oil

Period


Volume
MMBtu/d


Price
$/MMBtu


Volume
Bbls/d


Price
$/Bbl


Volume
Bbls/d


Price
$/Bbl

4Q13


123,424


3.72


1,068


69.47


8,764


98.01

1Q14


85,000


3.87


99


42.00


9,000


94.27

2Q14


85,000


3.87


98


42.00


9,000


94.27

3Q14


85,000


3.87


97


42.00


7,600


94.62

4Q14


78,370


3.85


97


42.00


7,600


94.62














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

2013 Guidance

The Company's updated 2013 guidance (please reference "Forward-Looking Statements" below) is as follows.  Guidance ranges are before the effect of the sale of West Tavaputs, which is expected to close by year-end. The Company may update guidance as business conditions warrant.

  • Capital expenditures of $465 million to $485 million, unchanged.
  • Oil, natural gas and NGL production of 85 to 87 Bcfe, narrowed and adjusted to reflect the effect of reclassifying rejected ethane volumes as NGL volumes. Oil production is expected to increase approximately 30% to 35% in 2013 over 2012, unchanged.
  • Lease operating costs of $69 million to $71 million, increased from $64 million to $67 million, due to increased workover activity as well as non-recurring charges associated with the sale of West Tavaputs, changes in the artificial lift systems in the DJ Basin and weather-related road work in both the Uinta and DJ Basins. It also includes one-time charges of $1.4 million associated with the West Tavaputs compressor fire.
  • Gathering, transportation and processing costs of $65 million to $68 million, unchanged.
  • General and administrative expenses, before non-cash stock-based compensation cost, of $50 million to $52 million, narrowed from $50 million to $54 million.

The Company intends to provide guidance for its 2014 capital and operating plan in late January 2014.

THIRD QUARTER 2013 RESULTS WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held tomorrow morning to discuss third quarter 2013 results. Please join Bill Barrett Corporation executive management at 11:00 a.m. Eastern time/9:00 a.m. Mountain time on November 1, 2013 for the live webcast, accessed at www.billbarrettcorp.com, or join by telephone by calling 866-270-6057 (617-213-8891 international callers) with passcode 81445497. The webcast will remain available on the Company's website for approximately 30 days, and a replay of the call will be available November 1 through November 8, 2013 at call-in number 888-286-8010 (617-801-6888 international) with passcode 18134202.

QUARTERLY REPORT ON FORM 10-Q

The Company plans to file later today its Quarterly Report on Form 10-Q for the quarter ended September 30, 2013. The Form 10-Q will be posted to the Company's website at www.billbarrettcorp.com and found under "SEC Filings".

UPCOMING EVENTS

Updated investor presentations are posted to the homepage of the Company's website at www.billbarrettcorp.com prior to investor events. An updated presentation will be posted at 5:00 p.m. Mountain time on Monday, November 4, 2013 and Tuesday, December 10, 2013. 

Investor Conferences

Chief Executive Officer and President Scot Woodall will present at the Wells Fargo 12th Annual Pipeline, MLP and Energy Symposium on Wednesday, December 11, 2013 (time not yet confirmed.) The event will be webcast, and the live and archived webcast will be accessible on the Company's homepage at www.billbarrettcorp.com.  

Mr. Woodall will also participate in the Capital One Southcoast, Inc. 2013 Energy Conference the same week.

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 from the natural gas stream.  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.

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 revised "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 other forward-looking statements 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; the ability to complete property sales or other transactions; 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; performance of acquired properties and newly drilled wells; costs and availability of third party facilities for gathering, processing, refining and transportation; 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
September 30,


Nine Months Ended
September 30,



2013


2012


2013


2012

Production Data:










Natural gas (MMcf)


12,988


27,010


41,959


78,417


Oil (MBbls)


909


714


2,528


1,830


NGLs (MBbls)


500


N/A


1,627


N/A


Combined volumes (MMcfe)


21,442


31,294


66,889


89,397


Daily combined volumes (MMcfe/d)


233


340


245


326

Average Prices (before the effects of realized hedges):










Natural gas (per Mcf)

(1)

$

3.98


$

3.85


$

3.92


$

3.84


Oil (per Bbl)

(2)

90.41


77.99


83.01


81.42


NGLs (per Bbl)


27.14


N/A


26.34


N/A


Combined (per Mcfe)


6.88


5.10


6.23


5.03

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

(3)









Natural gas (per Mcf)

(1)

$

4.30


$

4.90


$

4.10


$

5.04


Oil (per Bbl)

(2)

83.51


84.08


82.50


85.49


NGLs (per Bbl)


28.74


N/A


27.79


N/A


Combined (per Mcfe)


6.81


6.15


6.37


6.17

Average Costs (per Mcfe):










Lease operating expense


$

0.85


$

0.54


$

0.79


$

0.61


Gathering, transportation and processing expense

(2)

0.76


0.85


0.76


0.89


Production tax expense


0.38


0.26


0.33


0.24


Depreciation, depletion and amortization


3.36


2.92


3.21


2.81


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

(4)

0.52


0.44


0.54


0.44


(1)

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

(2)

Average oil prices for the three and nine months ended September 30, 2013 include an approximate $5.31 per Bbl transportation deduct related to certain production within the Uinta Oil Program. These costs were previously included in 2012 within gathering, transportation and processing expense. The effect on the average per unit oil price is approximately $1.95 per Bbl.

(3)

Average realized prices shown in the table are net of the effects of all settled commodity hedging transactions related to current period production. This presentation is a non-GAAP measure as it only represents the cash settled portion of our total commodity derivative gain loss in the Unaudited Consolidated Statements of Operations. Management believes the presentation of average prices including the effects of settled commodity derivative gains and losses is useful because the cash settlement portion provides a better understanding of the Company's average prices received for production volumes. We also believe that this disclosure allows for a more accurate comparison to our peers.

(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

September 30,


Nine Months Ended

September 30,



2013


2012


2013


2012

(in thousands, except per share amounts)







Operating and Other Revenues:








Oil, gas and NGLs

(1)

$

149,345


$

180,024


$

424,130


$

516,556


Other


(790)


842


5,001


3,838


Total operating and other revenues


148,555


180,866


429,131


520,394








Operating Expenses:








Lease operating


18,280


17,003


53,138


54,671


Gathering, transportation and processing


16,374


26,725


50,734


79,939


Production tax


8,183


8,094


21,915


21,193


Exploration


(24)


3,562


212


8,063


Impairment, dry hole costs and abandonment


219,363


38,540


227,646


60,179


Depreciation, depletion and amortization


72,047


91,392


214,792


251,417


General and administrative

(2)

11,083


13,912


36,278


39,026


Non-cash stock-based compensation

(2)

3,319


4,053


$

11,979


$

12,415


Total operating expenses


348,625


203,281


616,694


526,903

Operating Loss


(200,070)


(22,415)


(187,563)


(6,509)

Other Income and Expense:








Interest income and other income


52


53


123


128


Interest expense


(20,078)


(24,527)


(69,346)


(70,029)


Commodity derivative gain (loss)

(1)

(25,595)


(38,340)


(18,607)


53,431


Gain (loss) on extinguishment of debt


(21,460)



(21,460)


1,601


Total other income and expense


(67,081)


(62,814)


(109,290)


(14,869)

Loss before Income Taxes


(267,151)


(85,229)


(296,853)


(21,378)

Benefit from Income Taxes


(100,495)


(32,603)


(111,319)


(7,943)

Net Loss


$

(166,656)


$

(52,626)


$

(185,534)


$

(13,435)








Net Loss Per Common Share








Basic


$

(3.51)


$

(1.11)


$

(3.91)


$

(0.28)


Diluted


$

(3.51)


$

(1.11)


$

(3.91)


$

(0.28)








Weighted Average Common Shares Outstanding








Basic


47,535


47,230


47,453


47,173


Diluted


47,535


47,230


47,453


47,173



(1)

The table below summarizes the realized and unrealized gains and losses the Company recognized related to its oil, natural gas and NGL derivative instruments for the periods indicated:




Three Months Ended

September 30,


Nine Months Ended

September 30,


2013


2012


2013


2012

Included in oil and gas production revenue:







Certain realized gains on hedges

$

1,899


$

20,391


$

5,902


$

66,654

Included in commodity derivative gain (loss):







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

$

(3,255)


$

12,295


$

2,971


$

35,014

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

(22,340)


(50,635)


(21,578)


18,417

Total commodity derivative gain (loss)

$

(25,595)


$

(38,340)


$

(18,607)


$

53,431



(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




September 30, 2013


December 31, 2012

(in thousands)

 






Assets:





Cash and cash equivalents



$

60,530


$

79,445


Other current assets

(1)


108,521


148,894


Property and equipment, net



2,533,145


2,611,337


Other noncurrent assets

(1)


24,065


29,773


Total assets



$

2,726,261


$

2,869,449








Liabilities and Stockholders' Equity:






Current liabilities

(1)


$

206,237


213,133


Notes payable to bank



390,000



Lease financing obligation



39,899


88,519


Senior notes



800,000


1,042,791


Convertible senior notes



25,344


25,344


Other long-term liabilities

(1)


257,783


316,887


Stockholders' equity



1,006,998


1,182,775


Total liabilities and stockholders' equity


$

2,726,261


$

2,869,449



(1)

At September 30, 2013, the estimated fair value of all of the Company's commodity derivative instruments was a net asset of $5.1 million, comprised of $3.5 million current assets, $3.9 million non-current assets and $2.3 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
September 30, 2013


Nine Months Ended
September 30, 2013


2013


2012


2013


2012

(in thousands)








Operating Activities:









Net loss

$

(166,656)


$

(52,626)


$

(185,534)


$

(13,435)


Adjustments to reconcile to net cash provided by operations:










Depreciation, depletion and amortization

72,047


91,392


214,792


251,417



Impairment, dry hole costs and abandonment expense

219,363


38,540


227,646


60,179



Total commodity derivative gain (loss)

25,595


38,340


18,607


(53,431)



Settlements of commodity derivatives

(3,255)


12,295


2,971


35,014



Deferred income taxes

(99,212)


(32,329)


(110,036)


(7,669)



Stock compensation and other non-cash charges

3,392


5,008


12,681


14,249



Amortization of debt discounts and deferred financing costs

1,069


1,708


4,535


6,710



(Gain) loss on extinguishment of debt

21,460



21,460


(1,601)



(Gain) loss on sale of properties

1,091


(108)


(3,102)


(108)



Change in assets and liabilities:











Accounts receivable

(4,163)


(13,661)


12,343


4,475




Prepayments and other current assets

(110)


7,581


1,475


1,515




Accounts payable, accrued and other liabilities

(1,058)


4,040


(24,801)


(4,813)




Amounts payable to oil & gas property owners

(3,227)


5,950


6,510


567




Production taxes payable

6,937


5,229


(3,245)


(2,466)



 

Net cash provided by operating activities

$

73,273


$

111,359


$

196,302


$

290,603

Investing Activities:









Additions to oil and gas properties, including acquisitions

(118,945)


(291,486)


(335,597)


(751,545)


Additions of furniture, equipment and other

(319)


(1,278)


(1,506)


(5,519)


Proceeds from sale of properties and other investing activities

(3,302)


(43)


784


91



 

Net cash used in investing activities

$

(122,566)


$

(292,807)


$

(336,319)


$

(756,973)

Financing Activities:









Proceeds from debt

310,000


260,826


390,000


785,826


Principal and redemption premium payments on debt

(264,624)


(76,007)


(269,125)


(343,163)


Deferred financing costs and other

(78)


(277)


(1,426)


(10,363)


Proceeds from stock option exercises

1,650


5


1,653


672



 

Net cash provided by financing activities

$

46,948


$

184,547


$

121,102


$

432,972

Increase (Decrease) in Cash and Cash Equivalents

(2,345)


3,099


(18,915)


(33,398)

 

Beginning Cash and Cash Equivalents

62,875


20,834


79,445


57,331

 

Ending Cash and Cash Equivalents

$

60,530


$

23,933


$

60,530


$

23,933

 

BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow & Adjusted Net Income (Loss)

(Unaudited)

Discretionary Cash Flow Reconciliation



Three Months Ended
September 30,


Nine Months Ended
September 30,


2013



2012


2013



2012

(in thousands, except per share amounts)










Net Loss

$

(166,656)



$

(52,626)



$

(185,534)



$

(13,435)

Adjustments to reconcile to discretionary cash flow:











Depreciation, depletion and amortization

72,047



91,392



214,792



251,417


Impairment, dry hole and abandonment expense

219,363



38,540



227,646



60,179


Exploration expense

(24)



3,562



212



8,063


Total commodity derivative gain (loss)

25,595



38,340



18,607



(53,431)


Settlements of commodity derivatives

(3,255)



12,295



2,971



35,014


Deferred income taxes

(99,212)



(32,329)



(110,036)



(7,669)


Stock compensation and other non-cash charges

3,392



5,008



12,681



14,249


Amortization of debt discounts and deferred financing costs

1,069



1,708



4,535



6,710


Loss (gain) on extinguishment of debt

21,460





21,460



(1,601)


Loss (gain) on sale of properties

1,091



(108)



(3,102)



(108)

Discretionary Cash Flow

$

74,870



$

105,782



$

204,232



$

299,388












Per share, diluted

$

1.58



$

2.24



$

4.30



$

6.35


Per Mcfe

$

3.49



$

3.38



$

3.05



$

3.35



Adjusted Net Income (Loss) Reconciliation



Three Months Ended
September 30,


Nine Months Ended
September 30,


2013



2012



2013



2012

(in thousands except per share amounts)











Net Loss

$

(166,656)



$

(52,626)



$

(185,534)



$

(13,435)

Adjustments to net loss:












Total commodity derivative gain (loss)

25,595



38,340



18,607



(53,431)


Settlements of commodity derivatives

(3,255)



12,295



2,971



35,014


Impairment expense

216,564



18,772



216,564



37,109


Loss (gain) on sale of properties

1,091



(108)



(3,102)



(108)


One-time items:













Expenses relating to compressor station fire

192





1,367





Loss (gain) on extinguishment of debt

21,460





21,460



(1,601)


Subtotal Adjustments

261,647



69,299



257,867



16,983


Effective tax rate

38%



38%



38%



37%


Tax effected adjustments

162,221



42,965



159,878



10,699

Adjusted Net Loss

$

(4,435)



$

(9,661)



$

(25,656)



$

(2,736)














Per share, diluted

$

(0.09)



$

(0.20)



$

(0.54)



$

(0.06)


Per Mcfe

$

(0.21)



$

(0.31)



$

(0.38)



$

(0.03)



Discretionary cash flow and adjusted net income (loss) 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.

SOURCE Bill Barrett Corporation



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http://www.billbarrettcorp.com

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