Bill Barrett Corporation Reports Second Quarter 2014 Results and Reaffirms Expected 30% Growth in Oil Production for 2014

Jul 31, 2014, 16:30 ET from Bill Barrett Corporation

DENVER, July 31, 2014 /PRNewswire/ -- Bill Barrett Corporation ("the Company") (NYSE: BBG) today reported second quarter 2014 results and announced operational updates highlighted by:

  • Total production of 2.62 MMBoe, meeting the upper end of Company guidance and reflecting strong year-over-year production growth from the Denver-Julesburg ("DJ") Basin at 141% and from East Bluebell at 56%
  • Oil production of more than 1 million barrels, up 11% sequentially from the first quarter of 2014
  • Commodity balanced production with 39% oil, 43% natural gas and 18% NGLs
  • Discretionary cash flow of $67.3 million, or $1.40 per diluted common share
  • Discretionary cash flow generated per Boe produced up 47% from the second quarter of 2013 as the Company drives improved margins from its core oil development programs
  • Accelerated drilling of Northeast Wattenberg extended reach lateral wells with 16 wells spud to date

Chief Executive Officer and President Scot Woodall commented: "In the first half of 2014 our team has demonstrated consistent execution at our core development programs, and we are delivering production growth right on track with our internal plan. In the Northeast Wattenberg, I am very pleased to report that we have been able to accelerate our development drilling of extended reach lateral wells, having drilled (not yet completed) 16 wells to date. In the first half of the year, our drilling program in the DJ Basin included drilling in the higher-gas prone Core Wattenberg and exploratory drilling in the Chalk Bluffs area. We have now directed our focus to the Northeast Wattenberg area, where we have three rigs drilling extended reach lateral wells, which offer the most favorable rates of return. In addition, in East Bluebell we continue to successfully drill our 23,000 acre position where high oil content and low drilling costs support strong rates of return. Oil production is up 20% over 2013 year-to-date, and the Company expects that full year 2014 oil production will meet our internal target of 30% year-over-year growth."

OPERATING AND FINANCIAL RESULTS

Oil, natural gas and natural gas liquids ("NGLs") production totaled 2.62 million barrels of oil equivalent ("MMBoe") (or 15.7 billion cubic feet equivalent of natural gas, "Bcfe") in the second quarter of 2014. Total production is down from 3.8 MMBoe in the second quarter of 2013, primarily due to the sale of a natural gas assets and production declines in the Gibson Gulch natural gas program. For the first half of 2014, production totaled 5.06 MMBoe and included 1.95 million barrels ("MMBbls") of oil.

Oil production averaged 11,281 barrels per day ("Bbls/d"), up 25% from the second quarter of 2013 and up 11% sequentially. Oil production increased to 39% of total production in the second quarter of 2014 compared with 22% in the second quarter of 2013, driving a 47% increase in discretionary cash flow (a non-GAAP measure, see "Discretionary Cash Flow Reconciliation" below) per barrel of oil equivalent ("Boe") produced. The Company achieved high year-over-year production growth from its two core oil programs, with DJ Basin production up 141% and East Bluebell production up 56% as the Company concentrates capital expenditures in these areas.

Product pricing, pre-hedge, was up 40% per Boe compared with the second quarter of 2013, driven by both an increase in commodity prices and a higher proportion of sales coming from oil production. Realized prices, after the effect of hedges, averaged $79.69 per barrel for oil, $4.46 per million cubic feet ("Mcf") for natural gas and $31.75 per barrel for NGLs. The Company settled net $8.9 million in cash commodity hedge losses for the second quarter of 2014. (See "Selected Operating Highlights" for more detail.)

Discretionary cash flow in the second quarter of 2014 was $67.3 million, or $1.40 per diluted common share, up slightly from $65.7 million in the second quarter of 2013. Growth in cash flow was driven by increased oil production, which more than offset the decline in natural gas production (described above), as oil sales have a significantly higher margin than natural gas. Cash operating costs (lease operating expense, gathering transportation and processing expense and production tax expense) per unit were higher in the second quarter of 2014 at $14.23 per Boe compared with the second quarter of 2013 at $11.36 per Boe, due to the higher proportion of oil production, as oil is more costly to produce per unit than natural gas. In addition, interest expense was reduced by 28% in the second quarter of 2014 compared with the prior year period. Discretionary cash flow per Boe was up 47% in the second quarter of 2014 compared with the second quarter of 2013. For the first six months of 2014, discretionary cash flow was $122.6 million or $2.56 per diluted common share, compared with $129.4, or $2.73 per diluted common share, in the first six months of 2013.

Net loss in the second quarter of 2014 was $26.6 million, or $(0.55) per diluted common share, compared with net income of $14.3 million in the second quarter of 2013. The net loss reflected a $46.8 million commodity derivative loss and higher per unit depreciation, depletion and amortization expenses. For the first six months of 2014, the net loss was $39.3 million, or $(0.82) per diluted common share, compared with a net loss of $18.9 million, or $(0.40) per diluted common share, in the first six months of 2013.

Adjusted net loss for the second quarter of 2014 (a non-GAAP measure, see "Adjusted Net Income (Loss) Reconciliation" below) was $8.6 million, or $(0.18) per diluted common share, compared with a loss of $9.1 million, or $(0.19) per diluted common share, in the second quarter of 2013. For the first six months of 2014, the adjusted net loss was $10.8 million, or $(0.23) per diluted common share, compared with a loss of $21.3 million or $(0.45) per diluted common share, in the first six months of 2013. Adjusted net income (loss) removes the effect of unrealized derivative gains and losses and non-recurring charges such as impairment expenses, property sales and certain one-time items.

DEBT AND LIQUIDITY

At June 30, 2014, the Company had total debt outstanding (principal balance) of $1,116.4 million. Debt outstanding included $250.0 million drawn on its revolving credit facility, $25.4 million in convertible senior notes, $400.0 million in 7.625% senior notes, $400.0 million in 7.000% senior notes and $41.0 million for a lease financing obligation. At quarter-end, the Company had $349.0 million in available capacity on its credit facility, after taking into account a $26.0 million letter of credit.

OPERATIONS

     Production, Wells Spud and Capital Expenditures

The following table lists production, wells spud and total capital expenditures by basin for the three and six months ended June 30, 2014:

Three Months Ended June 30, 2014

Six Months Ended June 30, 2014

Basin

Average Net Daily Production

(Boe)

Wells Spud Gross/Net*

Capital Expenditures ($ millions)

Average Net Daily Production

(Boe)

Wells Spud Gross/

Net*

Capital Expenditures ($ millions)

Denver-Julesburg

7,126

22/11

85.3

6,780

54/30

180.3

Uinta

6,733

20/14

44.3

6,251

33/21

74.0

Piceance

13,269

--

--

13,387

--

--

Powder River Deep Oil

1,685

6/1

8.9

1,516

13/2

18.8

& Other

Total

28,813

48/26

$138.5

27,934

100/53

$273.1

*Includes operated and non-operated wells

 

     Operating and Drilling Update

In 2014, the Company anticipates participating in approximately 190 gross/100 net development wells of which approximately 120 gross are to be operated by the Company. The Company's drilling program remains flexible to changes throughout the year, particularly if positive well results and technical changes expand opportunities.

          Denver-Julesburg Basin, Colorado and Wyoming

Northeast Wattenberg/DJ Basin – Second quarter of 2014 net production averaged 7,126 barrels of oil equivalent per day ("Boe/d"), a 141% increase from the second quarter of 2013 and up 11% sequentially from the first quarter of 2014. Production was 58% oil, 27% natural gas and 15% NGLs.

The Company is currently operating three rigs in the Northeast Wattenberg area, all of which are actively drilling extended reach lateral wells. To date, the Company has drilled 16 extended reach lateral wells, an acceleration of its original schedule. The wells typically have approximate 9,000 foot laterals and 40 fracture stimulation stages (four with planned approximate 7,000 foot laterals and 32 stages.) The Company intends to focus its DJ program on the Northeast Wattenberg area through the remainder of 2014.

During the first half of 2014, the Company drilled and completed two multi-well pads (total 16 wells) in the Core Wattenberg area. Initial production ("IP") rates for 11 wells that have at least 30 days of production averaged 729 Boe/d per well over a peak 24-hour period and averaged 329 Boe/d per well over 30 days. The Company encountered mechanical problems that affected flow rates on one of the pads and continues to assess the performance of these wells. Initial results on the second pad are in-line with expectations.   

The Company also drilled and completed four Codell exploration wells in the Chalk Bluffs area of the DJ Basin. These wells had IP rates that averaged 332 Boe/d per well over a peak 24-hour period and averaged 245 Boe/d per well over 30 days. The Company continues to assess the performance of these wells and the prospectivity of the area.

While the drilling program will remain somewhat flexible throughout the year, the Company expects to drill approximately 70 gross operated wells (56 net), and participate in an additional 45 gross wells (8 net) in the DJ Basin program during 2014.

At June 30, 2014, the Company had an approximate 81% working interest in production from 370 gross/241 net wells, including approximately 200 legacy vertical wells from prior DJ Basin property acquisitions. As of the end of the second quarter of 2014, the Company had approximately 76,300 net acres in the DJ Basin program.

          Uinta Basin, Utah

Uinta Oil Program (East Bluebell, Blacktail Ridge-Lake Canyon and South Altamont) - Second quarter of 2014 net production for all areas of the Uinta Oil Program averaged 6,733 Boe/d, flat with the second quarter of 2013 and up 17% sequentially from the first quarter of 2014. Total Uinta Oil Program production was 79% oil, 16% natural gas and 5% NGLs. The Company is concentrating its 2014 drilling within the East Bluebell region, driving strong production growth, up 56% from the second quarter of 2013.

The Company is operating two active rigs in the area and during 2014 expects to drill 54 gross wells (34 net) in the Uinta Oil Program.

At June 30, 2014, the Company had an approximate 78% working interest in production from 324 gross/186 net wells. As of the end of the second quarter of 2014, the Company had approximately 151,200 net acres (including approximately 51,000 net acres to be earned) in the Uinta Oil program, including 23,000 net acres in the East Bluebell area.

          Piceance Basin, Colorado

Gibson Gulch – Second quarter of 2014 net production in the Gibson Gulch program averaged 80 million cubic feet equivalent per day ("MMcfe/d").  Drilling in the area remains suspended as the Company focuses its operations plan on oil development. 

At June 30, 2014, the Company had an approximate 74% working interest in production from 956 gross/717 net wells and held 12,000 net acres in its Gibson Gulch program.

          Powder River Basin, Wyoming

Powder Deep Oil Program – Second quarter of 2014 net production averaged approximately 1,650 Boe/d from 22 net wells and was 77% oil. At June 30, 2014 the Company held 64,440 net acres in the Powder Deep Oil Program. The Company is actively marketing this asset for sale.  

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 next six quarters, 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 West Texas Intermediate.

  • Hedges in place for the second half of 2014 include an average 10,600 Bbls/d of oil at an average price of $93.93 per barrel and approximately 68,315 million British thermal units per day ("MMBtu/d") of natural gas at an average price of $3.95 per MMBtu.
  • Hedges in place for 2015 include an average 11,171 Bbls/d of oil at an average price of $90.13 per barrel and approximately 20,000 MMBtu/d of natural gas at an average price of $4.13 per MMBtu.

The following table summarizes hedge positions as of July 18, 2014:

Oil

Natural Gas

NGLs

        

Period

Volume Bbls/d

Price $/Bbl

Volume MMBtu/d

Price $/MMBtu

Volume Bbls/d

Price $Bbl

3Q14

10,600

93.98

65,000

4.02

1,029

60.18

4Q14

10,600

93.88

71,630

3.89

1,029

60.18

1Q15

11,800

90.46

20,000

4.13

--

--

2Q15

11,300

90.39

20,000

4.13

--

--

3Q15

10,800

89.81

20,000

4.13

--

--

4Q15

10,800

89.81

20,000

4.13

--

--

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

 

     2014 Operating Guidance

The Company's 2014 operating guidance (please reference "Forward-Looking Statements" below) is unchanged 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, before the effect of the expected sale of Powder Deep assets.
  • 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.

SECOND QUARTER 2014 RESULTS WEBCAST AND CONFERENCE CALL

As previously announced, a webcast and conference call will be held tomorrow morning to discuss second quarter 2014 results. Please join Bill Barrett Corporation executive management at 11:00 a.m. Eastern time/9:00 a.m. Mountain time on August 1, 2014 for the live webcast, accessed at www.billbarrettcorp.com, or join by telephone by calling 877-415-3185 (857-244-7328 international callers) with passcode 22671991. The webcast will remain available on the Company's website for approximately 30 days, and a replay of the call will be available August 1 through August 8, 2014 at call-in number 888-286-8010 (617-801-6888 international) with passcode 60786334.

QUARTERLY REPORT ON FORM 10-Q

The Company plans to file later today its Quarterly Report on Form 10-Q for the quarter ended June 30, 2014. The Form 10-Q will be posted to the Company's website at www.billbarrettcorp.com and found under "SEC Filings".

UPCOMING EVENTS INVESTOR CONFERENCES

Updated investor presentations are posted to the homepage of the Company's website at www.billbarrettcorp.com prior to investor events.

Chief Executive Officer Scot Woodall will present at the Enercom Oil and Gas Conference on August 20, 2014 at 11:20 a.m. Mountain time. The event will be webcast, with the webcast accessible from the Company's website at www.billbarrettcorp.com. The presentation for this event will be posted on August 19, 2014 at 5:00 p.m. Mountain time.

Chief Executive Officer Scot Woodall will present at the Barclays CEO Energy Conference on September 4, 2014 at 1:45 p.m. Eastern time. The event will be webcast, with the webcast accessible from the Company's website at www.billbarrettcorp.com. The presentation for this event will be posted on September 2, 2014 at 5:00 p.m. Mountain time.

DISCLOSURE STATEMENTS

               Forward-Looking Statements

This press release contains forward-looking statements. Forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company's control. Actual results could differ materially from those discussed in these forward-looking statements. In particular, the Company is confirming "2014 Operating Guidance," which contains projections for certain 2014 operational and financial metrics. These and other forward-looking statements in this press release, including drilling and well performance and sale of the Powder Deep Oil Program, 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; delays or other impediments to drilling and completing wells arising from political or judicial developments at the local, state or federal level, including voter initiatives related to hydraulic fracturing; development drilling and testing results; the potential for production decline rates to be greater than expected; regulatory delays, including seasonal or other wildlife 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

Six Months Ended

June 30,

June 30,

2014

2013

2014

2013

Production Data:

Oil (MBbls)

1,026

825

1,948

1,619

Natural gas (MMcf)

6,696

14,314

13,116

28,976

NGLs (MBbls)

480

544

922

1,127

Combined volumes (MBoe)

2,622

3,755

5,056

7,575

Daily combined volumes (Boe/d)

28,813

41,264

27,934

41,851

Average Prices (before the effects of realized hedges):

Oil (per Bbl)

$ 86.64

$ 78.99

$ 84.73

$ 78.86

Natural gas (per Mcf)

4.74

4.06

5.14

3.89

NGLs (per Bbl)

31.64

27.80

32.87

27.09

Combined (per Boe)

51.80

36.87

51.98

35.75

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

Oil (per Bbl)

$ 79.69

$ 82.11

$ 79.26

$ 81.93

Natural gas (per Mcf)

4.46

3.92

4.62

4.01

NGLs (per Bbl)

31.75

29.90

32.35

28.49

Combined (per Boe)

48.39

37.32

48.43

37.10

Average Costs (per Boe):

Lease operating expense

$   6.07

$   4.29

$   6.35

$   4.60

Gathering, transportation and processing expense

4.48

5.00

4.64

4.54

Production tax expense

3.68

2.07

3.42

1.81

Depreciation, depletion and amortization

24.75

19.79

23.81

18.84

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

(1)

4.58

2.68

4.71

3.33

(1)

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. See "Operating Expenses" in the Consolidated Statements of Operations.

 

BILL BARRETT CORPORATION

Consolidated Statements of Operations

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2014

2013

2014

2013

(in thousands, except per share amounts)

Operating and Other Revenues:

Oil, gas and NGLs

(1)

$ 136,220

$ 140,380

$ 263,389

$ 274,785

Other

8,788

1,919

9,307

5,791

Total operating and other revenues

145,008

142,299

272,696

280,576

Operating Expenses:

Lease operating

15,919

16,112

32,083

34,858

Gathering, transportation and processing

11,750

18,772

23,454

34,360

Production tax 

9,651

7,781

17,275

13,732

Exploration

116

141

419

236

Impairment, dry hole costs and abandonment

1,743

1,182

3,504

8,283

Depreciation, depletion and amortization

64,894

74,307

120,402

142,745

General and administrative

(2)

11,998

10,047

23,817

25,195

Non-cash stock-based compensation

(2)

2,523

3,226

6,111

8,660

Total operating expenses

118,594

131,568

227,065

268,069

Operating Income

26,414

10,731

45,631

12,507

Other Income and Expense:

Interest and other income

352

32

727

71

Interest expense

(17,821)

(24,726)

(35,252)

(49,268)

Commodity derivative gain (loss)

(1)

(46,775)

36,839

(71,930)

6,988

Total other income and expense

(64,244)

12,145

(106,455)

(42,209)

Income (Loss) before Income Taxes

(37,830)

22,876

(60,824)

(29,702)

Provision for (Benefit from) Income Taxes

(11,244)

8,603

(21,489)

(10,824)

Net Income (Loss)

$  (26,586)

$   14,273

$  (39,335)

$  (18,878)

Net Income (Loss) Per Common Share

Basic

$      (0.55)

$        0.30

$      (0.82)

$      (0.40)

Diluted

$      (0.55)

$        0.30

$      (0.82)

$      (0.40)

Weighted Average Common Shares Outstanding

Basic

47,997

47,469

47,944

47,411

Diluted

47,997

47,616

47,944

47,411

(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 June 30, 

 Six Months Ended June 30, 

2014

2013

2014

2013

Included in oil gas and NGL production revenue:

Certain realized gains on hedges

$          382

$       1,936

$          538

$       4,003

Included in commodity derivative gain (loss):

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

$      (9,326)

$         (227)

$    (18,526)

$       6,226

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

(37,449)

37,066

(53,404)

762

   Total commodity derivative gain (loss)

$    (46,775)

$     36,839

$    (71,930)

$       6,988

(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

June 30, 2014

December 31, 2013

(in thousands)

Assets:

Cash and cash equivalents

$            55,779

$                        54,595

Other current assets

(1)

110,202

102,652

Property and equipment, net

2,350,956

2,202,496

Other noncurrent assets

(1)

17,375

21,770

Total assets

$      2,534,312

$                  2,381,513

Liabilities and Stockholders' Equity:

Current liabilities       

(1)

$          237,969

$                     192,719

Notes payable to bank

250,000

115,000

Capitalized lease obligation

36,359

38,738

Senior notes

800,000

800,000

Convertible senior notes

25,344

25,344

Other long-term liabilities      

(1)

214,045

203,994

Stockholders' equity

970,595

1,005,718

Total liabilities and stockholders' equity

$      2,534,312

$                  2,381,513

(1)

At June 30, 2014, the estimated fair value of all of the Company's commodity derivative instruments was a net liability of $57.2 million, comprised of: $41.4 million current liabilities and $15.8 million non-current liabilities. This amount will fluctuate quarterly based on estimated future commodity prices and the current hedge position.

 

BILL BARRETT CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)

Three Months Ended

Six Months Ended

June 30,

June 30,

2014

2013

2014

2013

(in thousands)

Operating Activities:

Net income (loss)

$   (26,586)

$     14,273

$   (39,335)

$   (18,878)

Adjustments to reconcile to net cash provided by operations:

Depreciation, depletion and amortization

64,894

74,307

120,402

142,745

Impairment, dry hole costs and abandonment expense

1,743

1,182

3,504

8,283

Total derivative (gain)/loss

37,449

(37,066)

53,404

(762)

Deferred income taxes

(11,286)

8,603

(21,531)

(10,824)

Stock compensation and other non-cash charges

2,463

3,219

6,155

9,289

Amortization of debt discounts and deferred financing costs

1,065

1,734

2,132

3,466

Gain on sale of properties

(2,570)

(674)

(2,570)

(4,193)

Change in assets and liabilities:

Accounts receivable

169

(2,729)

5,699

16,506

Prepayments and other assets

660

767

1,068

1,585

Accounts payable, accrued and other liabilities

(8,929)

(9,654)

(2,795)

(23,743)

Amounts payable to oil & gas property owners

(7,465)

7,331

1,936

9,737

Production taxes payable

617

(5,190)

(651)

(10,182)

Net cash provided by operating activities

$     52,224

$     56,103

$  127,418

$  123,029

Investing Activities:

Additions to oil and gas properties, including acquisitions

(135,407)

(101,328)

(264,345)

(216,652)

Additions of furniture, equipment and other

(582)

(742)

(856)

(1,187)

Proceeds from sale of properties and other investing activities

8,563

(2,338)

8,175

4,086

Net cash used in investing activities

$ (127,426)

$ (104,408)

$ (257,026)

$ (213,753)

Financing Activities:

Proceeds from debt

70,000

55,000

135,000

80,000

Principal payments on debt

(1,148)

(2,260)

(2,285)

(4,501)

Deferred financing costs and other

(103)

(85)

(2,049)

(1,348)

Proceeds from stock option exercises

-

3

126

3

Net cash provided by financing activities

$     68,749

$     52,658

$  130,792

$     74,154

Increase (Decrease) in Cash and Cash Equivalents

(6,453)

4,353

1,184

(16,570)

Beginning Cash and Cash Equivalents

62,232

58,522

54,595

79,445

Ending Cash and Cash Equivalents

$     55,779

$     62,875

$     55,779

$     62,875

 

BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow & Adjusted Net Income

(Unaudited)

Discretionary Cash Flow Reconciliation

Three Months Ended

Six Months Ended

June 30,

June 30,

2014

2013

2014

2013

(in thousands, except per share amounts)

Net Income (Loss)

$ (26,586)

$ 14,273

$  (39,335)

$  (18,878)

Adjustments to reconcile to discretionary cash flow:

Depreciation, depletion and amortization

64,894

74,307

120,402

142,745

Impairment, dry hole and abandonment expense

1,743

1,182

3,504

8,283

Exploration expense

116

141

419

236

Total derivative (gain) loss

37,449

(37,066)

53,404

(762)

Deferred income taxes

(11,286)

8,603

(21,531)

(10,824)

Stock compensation and other non-cash charges

2,463

3,219

6,155

9,289

Amortization of debt discounts and deferred financing costs 

1,065

1,734

2,132

3,466

Gain on sale of properties

(2,570)

(674)

(2,570)

(4,193)

Discretionary Cash Flow

$  67,288

$ 65,719

$ 122,580

$ 129,362

Per share, diluted

$       1.40

$      1.38

$        2.56

$        2.73

Per Boe

$     25.66

$   17.50

$      24.24

$      17.08

Adjusted Net Income (Loss) Reconciliation

Three Months Ended

Six Months Ended

June 30,

June 30,

2014

2013

2014

2013

(in thousands except per share amounts)

Net Income (Loss)

$ (26,586)

$ 14,273

$  (39,335)

$  (18,878)

Adjustments to net income (loss):

Total derivative (gain) loss

37,449

(37,066)

53,404

(762)

Impairment expense

340

-

1,378

-

Gain on sale of properties

(2,570)

(674)

(2,570)

(4,193)

One-time items:

West Tavaputs NGL processing true-up

(5,677)

-

(5,677)

-

Expenses (credit) relating to compressor station fire

(570)

-

(570)

1,175

Subtotal Adjustments

28,972

(37,740)

45,965

(3,780)

Effective tax rate

38%

38%

38%

36%

Tax effected adjustments

(1)

17,963

(23,399)

28,498

(2,419)

Adjusted Net Loss

$   (8,623)

$  (9,126)

$  (10,837)

$  (21,297)

Per share, diluted

$     (0.18)

$    (0.19)

$      (0.23)

$      (0.45)

Per Boe

$     (3.29)

$    (2.43)

$      (2.14)

$      (2.81)

(1) 2014 periods apply the statutory corporate tax rate.

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 one-time or 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 (loss) 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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