Bill Barrett Corporation Reports Fourth Quarter and Year-End 2015 Financial and Operating Results and Provides 2016 Operating Guidance

Mar 01, 2016, 16:17 ET from Bill Barrett Corporation

DENVER, March 1, 2016 /PRNewswire/ -- Bill Barrett Corporation (the "Company") (NYSE: BBG) reported fourth quarter and year-end 2015 results and provides 2016 operating guidance, including these highlights:

  • 2015 production sales volumes of 6.6 million barrels of oil equivalent ("MMBoe"), exceeded high-end of guidance and was 16% above the mid-point of original guidance
  • Denver-Julesburg ("DJ") Basin production for the fourth quarter of 2015 increased 55% year-over-year
  • 2015 lease operating expense ("LOE") of $43 million, 7% below the mid-point of guidance and 10% below the mid-point of original guidance
  • Fourth quarter LOE of $4.70 per Boe, represents a 17% sequential decrease
  • 2015 capital expenditures of $287 million, 10% below the mid-point of guidance
  • Exhibited cost discipline as current extended reach lateral ("XRL") well costs of $4.75 million are approximately 42% lower compared to wells drilled in the fourth quarter of 2014
  • Entered 2016 with $129 million of cash and an undrawn credit facility of $375 million
  • 2016 operating plan has projected capital expenditures of $100-$150 million, approximately 55% below 2015 levels, with total production of 5.8-6.2 MMBoe

Chief Executive Officer and President Scot Woodall commented, "This past year presented numerous challenges for the energy sector as oil prices fell to levels not witnessed in over a decade. We responded to these challenges and successfully executed on our operational objectives by focusing on the items within our control. We have taken a number of proactive steps to reset our operating cost and G&A structure and will realize tangible benefits during 2016, as evidenced by our cost guidance. Our priority for this year is to protect our balance sheet as we entered 2016 with a financial position consisting of $129 million of cash, an undrawn credit facility, and a strong 2016 hedge position."

Mr. Woodall continued, "In response to current commodity prices, we have set our 2016 capital budget at $100-$150 million. This level of spending allows us to sustain production at levels similar to 2015, pro forma for asset divestitures completed during 2015, while spending approximately 55% less capital than 2015 at the mid-point. Based on the uncertainty of an oil price recovery during 2016, we are making the decision to curtail drilling activity to preserve capital and will monitor industry conditions to determine the appropriate time to resume drilling. Accordingly, we recently released the sole rig we were operating.  Although this results in the deferral of production during the second half of the year, we believe it is the appropriate action to take in this commodity price environment as it allows us to retain operational and financial flexibility."

OPERATING AND FINANCIAL RESULTS

Reserves

Total estimated proved reserves at year-end 2015 were 83.7 MMBoe compared to 122.3 MMBoe at year-end 2014. Estimated proved reserves were 66% oil, 20% natural gas and 14% natural gas liquids ("NGLs") and were 48% developed compared to 34% developed at year-end 2014. The decrease in estimated proved reserves compared to year-end 2014 is primarily the result of asset divestitures of 16.1 MMBoe and negative commodity price-related and other revisions of 24.4 MMBoe, offset in part by extensions and discoveries of 8.5 MMBoe. The decrease in proved reserves is also a result of the Company electing to take a conservative approach to adding proved undeveloped ("PUD") reserves due to the present commodity price environment. Only well locations that were in the process of being drilled at year-end 2015 were included and no new undrilled locations were added to the PUD reserve inventory. Negative price-related revisions were a result of a 47% decrease in the average WTI oil price and a 41% decrease in the average Henry Hub natural gas price used to calculate the 2015 proved reserves compared to 2014.

Changes in Proved Reserves (MMBoe)

Proved reserves as of December 31, 2014

122.3

Extensions and discoveries

8.5

Production

(6.6)

Sale of properties

(16.1)

Pricing revisions and other

(24.4)

Proved reserves as of December 31, 2015

83.7

2015 Production and Financial Results

Oil, natural gas and natural gas liquids production totaled 6.6 MMBoe in 2015, exceeding the Company's guidance range of 6.3-6.5 MMBoe. The outperformance was driven by new XRL well results and achieved despite a reduction in volumes associated with non-core asset sales in both the DJ Basin and Uinta Oil Program ("UOP") that were completed in the fourth quarter of 2015 and from UOP production declines that included approximately 1,000 Boe/d that was shut-in for economic reasons beginning in the second quarter of 2015.

Fourth quarter of 2015 production totaled 1.7 MMBoe, a 20% increase over the fourth quarter of 2014, and was 65% oil, 19% natural gas and 16% NGLs. Fourth quarter of 2015 production in the DJ Basin increased 55%, while UOP production was down 26% compared with the fourth quarter of 2014.

Three Months Ended  December 31,

Twelve Months Ended  December 31,

2015

2014 (1)

2015

2014 (1)

Production Data:

Oil (MBbls)

1,090

956

4,401

4,012

Natural gas (MMcf)

1,986

1,794

7,764

21,744

NGLs (MBbls)

264

146

898

1,476

Combined volumes (MBoe)

1,685

1,401

6,593

9,112

Daily combined volumes (Boe/d)

18,315

15,233

18,063

24,964

(1)

2014 data represents total company as previously reported for the period, including assets subsequently sold.

Pre-hedge commodity prices for 2015 were down significantly compared to both the fourth quarter and full-year 2014 as oil and natural gas prices declined significantly throughout 2015. For the fourth quarter of 2015, the Company had derivative commodity swaps in place for 10,800 barrels of oil per day tied to WTI pricing at $89.81 per barrel, 20,000 MMBtu of natural gas per day tied to Northwest Pipeline ("NWPL") regional pricing at $4.13 per MMBtu and no hedges in place for NGLs.

Three Months Ended  December 31,

Twelve Months Ended  December 31,

2015

2014 (1)

2015

2014 (1)

Average Sales Prices (before the effects of realized hedges):

Oil (per Bbl)

$

35.57

$

58.36

$

40.06

$

77.92

Natural gas (per Mcf)

1.98

4.16

2.23

4.78

NGLs (per Bbl)

11.98

20.16

12.16

31.55

Combined (per Boe)

27.21

47.26

31.02

50.82

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

Oil (per Bbl)

$

78.98

$

79.47

$

78.19

$

79.51

Natural gas (per Mcf)

3.72

3.88

3.75

4.45

NGLs (per Bbl)

11.98

21.44

12.16

31.51

Combined (per Boe)

57.36

61.44

58.27

50.73

(1)

2014 data represents total company as previously reported for the period, including assets subsequently sold.

Cash operating costs (LOE, gathering, transportation and processing costs, and production tax expense) totaled $6.54 per Boe in the fourth quarter of 2015, 21% lower on a sequential basis and 45% lower compared to the fourth quarter of 2014. LOE was $4.70 per Boe, 17% lower compared to the third quarter of 2015 and 45% lower on a year over year basis. This was primarily a result of improved operational efficiencies and lease operating cost reductions in both the DJ Basin and the UOP. LOE for the DJ Basin improved to an average of $3.25 per Boe in the fourth quarter of 2015 compared to $3.96 per Boe in the third quarter of 2015 and $5.56 per Boe in the fourth quarter of 2014. Production tax expense averaged 6.0% of pre-hedge revenue for the year ended December 31, 2015, compared with 6.8% of pre-hedge revenue for the year ended December 31, 2014.

Three Months Ended  December 31,

Twelve Months Ended  December 31,

2015

2014 (1)

2015

2014 (1)

Average Costs (per Boe):

Lease operating expenses

$

4.70

$

8.52

$

6.48

$

6.62

Gathering, transportation and processing expense

0.55

0.86

0.53

3.89

Production tax expenses

1.29

2.54

1.85

3.44

Depreciation, depletion and amortization

27.06

33.10

31.14

25.88

General and administrative expense, excluding long-term incentive compensation expense (2)

7.03

7.55

6.53

4.61

(1)

2014 data represents total company as previously reported for the period, including assets subsequently sold.

(2)

This separate presentation is a non-GAAP (Generally Accepted Accounting Principles) measure. Management believes the presentation of general and administrative expense excluding the long-term incentive compensation component of general and administrative expense is useful because it provides a better understanding of current period 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 stock-based/long-term incentive compensation expense.

Discretionary cash flow and adjusted net income (loss) are non-GAAP measures and are reconciled to net income (loss) in the schedule attached to this press release.

Discretionary cash flow for 2015 was $206.3 million, or $4.27 per share, compared to $231.6 million, or $4.78 per share, for 2014. Discretionary cash flow in the fourth quarter of 2015 was $53.3 million, or $1.10 per share, compared to $38.9 million, or $0.80 per share, in the fourth quarter of 2014.

Net income for 2015 was a loss of $487.8 million, or $(10.10) per diluted common share, compared with net income of $15.1 million, or $0.31 per diluted common share in 2014. Net income for 2015 and 2014 includes impairment charges of $572.4 million (pre-tax) and $40.2 million (pre-tax), respectively, as well as a derivative gain of $104.1 million (pre-tax) in 2015 and a derivative gain of $197.4 million (pre-tax) in 2014. Impairment charges in 2015 were primarily the result of a reduction of future net revenues compared to the carrying value of the UOP assets.

Net loss for the fourth quarter of 2015 was $21.1 million, or $(0.45) per share, compared with net income for the fourth quarter of 2014 of $89.1 million, or $1.84 per share. Adjusted net income (loss) (a non-GAAP measure, see the relevant reconciliation table below) was $3.4 million, or $0.07 per share, in the fourth quarter of 2015 compared with a loss of $11.3 million, or $(0.23) per share, in the fourth quarter of 2014. 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.

Three Months Ended  December 31,

Twelve Months Ended  December 31,

2015

2014

2015

2014

Discretionary Cash Flow ($ millions)

$

53.3

$

38.9

$

206.3

$

231.6

Discretionary Cash Flow (per share)

$

1.10

$

0.80

$

4.27

$

4.78

Adjusted Net Income (Loss) ($ millions)

$

3.4

$

(11.3)

$

(9.4)

$

(25.2)

Adjusted Net Income (Loss) (per share)

$

0.07

$

(0.23)

$

(0.20)

$

(0.52)

At December 31, 2015, the Company's revolving credit facility had zero drawn and $349.0 million in available capacity, after taking into account a $26.0 million letter of credit. The principal balance of long-term debt was $803.8 million and cash and cash equivalents were $128.8 million, resulting in net debt (principal balance of debt outstanding less the cash and cash equivalents balance) of $675.0 million.

Capital Expenditures

Capital expenditures for 2015 of $287.4 million was 49% lower than 2014 and included drilling 43 gross/39.8 net wells in the DJ Basin, which were primarily XRL wells operated by the Company, and 15 gross/9.6 net operated wells drilled in the UOP. Capital expenditures included $264.3 million for drilling and completion operations, $7.7 million for leaseholds to expand development programs, and $15.4 million for infrastructure and corporate purposes.

Capital expenditures for the fourth quarter of 2015 of $44.8 million included 9 gross/8.0 net wells in the DJ Basin, which were primarily XRL wells operated by the Company, and 4 gross/2.1 net operated wells drilled in the UOP. Capital expenditures included $37.3 million for drilling and completion operations, $3.4 million for leaseholds, and $4.1 million for infrastructure and corporate assets.

Three Months Ended December 31, 2015

Twelve Months Ended December 31, 2015

Average Net Daily Production (Boe/d)

Wells Spud Net (1)

Capital Expenditures ($ millions)

Average Net Daily Production (Boe/d)

Wells Spud Net (1)

Capital Expenditures ($ millions)

Basin:

Denver-Julesburg

13,837

8

$

36.0

13,082

44

$

250.3

Uinta

4,445

2

8.3

4,904

12

34.6

Other

33

0.5

77

2.5

Total

18,315

10

$

44.8

18,063

56

$

287.4

(1)

Includes operated and non-operated wells and UOP wells that were drilled, but not completed

OPERATIONAL HIGHLIGHTS

DJ Basin

Fourth quarter DJ Basin highlights include:

  • Produced an average of 13,837 Boe/d, an increase of 55% from the fourth quarter of 2014
  • DJ Basin oil volumes averaged 8,263 Bbls/d, an increase of 51% from the fourth quarter of 2014
  • Spud 9.0 gross/8.0 net operated XRL wells during the fourth quarter of 2015.
  • Placed 9.0 gross/8.1 net XRL wells on initial sales during the fourth quarter of 2015.
  • 17 XRL wells are currently in various stages of flowback and ramping up to a peak oil rate, including two four-well XRL pads and a ten-well pad that includes 9 XRL wells.
  • 16 wells, including 15 XRL wells, are in various stages of completion and are expected to be placed on initial flowback in April 2016.
  • 8 XRL wells have recently finished drilling and will begin completion operations beginning in March 2016.
  • XRL well drilling days to rig release have been reduced to an average of approximately 8 days per well, including a best-in-class well that was drilled in approximately 6.5 days. This represents a 49% improvement from the average of 2014.
  • XRL drilling and completion costs of $4.75 million per well are approximately 42% lower compared to XRL wells drilled in the fourth quarter of 2014.

Uinta Oil Program

Drilling and completion activity in the UOP during the fourth quarter of 2015 included drilling 4 gross commitment wells. Operations continue to be focused on improving operational efficiencies, and associated cost reductions have been realized as a result of lower lease operating costs.

2016 OPERATING GUIDANCE

The 2016 capital program is designed to align capital expenditures with expected cash flow as certain drilling activity may be deferred to protect the Company's liquidity position. This will result in 2016 production levels being similar to or slightly higher than 2015 production, pro forma for asset sales, with planned spending approximately 55% lower than 2015 capital expenditures. The capital program will be focused on XRL well development in the DJ Basin with minimal planned expenditures in the UOP. The Company is well positioned for 2016 having ample liquidity, a strong hedge position with approximately 65% of its 2016 oil production hedged at $80.47 per barrel of oil, nominal drilling commitments and no long-term drilling, completion or oil marketing contracts. The Company intends to fund its capital expenditure program with cash flow from operations and from its available cash balance.

The Company is providing the following guidance for its 2016 activities. See "Forward-Looking Statements" below.

  • Capital expenditures of $100-$150 million
    • This is approximately 55% below 2015 spending at the mid-point and represents a one-rig program for a portion of the year to drill up to 20 XRL wells in the NE Wattenberg field of the DJ Basin.
    • The Company has spud 4 XRL wells since the beginning of the year and recently released the drilling rig that it was operating due to low oil prices.
    • The low-end of the guidance range assumes that all wells that have been drilled are completed and placed on production and no new wells are drilled in 2016, while the high-end of the guidance range assumes that drilling activity resumes during the second half of 2016.
    • Assumes an XRL well cost of approximately $4.75 million.
    • First quarter of 2016 capital expenditures are expected to be approximately $55-$60 million and includes capital for completions of wells drilled during 2015.
  • Production of 5.8-6.2 MMBoe
    • Represents a production level that is similar to or slightly higher than pro forma 2015 sales volumes of 5.9 MMBoe at the mid-point, which excludes asset divestitures completed during 2015.
    • Production is estimated to be approximately 65% oil, 20% natural gas and 15% NGLs.
    • Production is expected to be weighted higher in the second half of 2016 as current completion and flowback operations on a 16-well drilling and spacing unit ("DSU"), including 15 XRL wells, and a 8-well DSU, all of which are XRL wells, will contribute to second half production rates. The Company anticipates that the fourth quarter of 2016 exit rate will be similar to the fourth quarter of 2015. This also represents an approximate 20-25% increase from the first quarter of 2016 to the fourth quarter of 2016.
    • First quarter of 2016 production is expected to approximate 1.3-1.4 MMBoe, which represents lower sequential production from the fourth quarter of 2015, in part, due to the sale of non-core assets that were completed during the quarter.
  • Lease operating expense of $33-$36 million, approximately 20% lower than 2015
  • Gathering, transportation and processing costs of $3-$5 million
  • Unused commitment for firm natural gas transportation charges of $18-$19 million
  • General and administrative expenses of $31-$34 million, which excludes non-cash, performance-based compensation and other one-time costs, approximately 25% lower than 2015

COMMODITY HEDGES UPDATE

For 2016, 6,772 barrels per day of oil is hedged at an average WTI price of $80.47 per barrel and 5,000 MMBtu/d of natural gas is hedged at an average NWPL price of $4.10 per MMBtu. The current value of the hedge position is approximately $136 million, as of February 26, 2016.

The following table summarizes hedge positions as of February 26, 2016:

Oil (WTI)

Natural Gas (NWPL)

Period

Volume Bbls/d

Price $/Bbl

Volume MMBtu/d

Price $/MMBtu

1Q16

7,300

$

81.65

5,000

$

4.10

2Q16

7,300

81.65

5,000

4.10

3Q16

6,250

79.11

5,000

4.10

4Q16

6,250

79.11

5,000

4.10

1Q17

2,250

73.88

2Q17

2,250

73.88

3Q17

1,500

78.16

4Q17

1,500

78.16

Realized sales prices will reflect basis differentials from the index prices to the sales location.

UPCOMING EVENTS

Teleconference Call and Webcast

The Company plans to host a conference call on Wednesday, March 2, 2016, to discuss the results and other items presented in this press release. The call is scheduled at 10:00 a.m. Eastern time (8:00 a.m. Mountain time). Please join the webcast conference call live or for replay via the Internet at www.billbarrettcorp.com, accessible from the home page. To join by telephone, call 855-760-8152 (631-485-4979 international callers) with passcode 38878862. The webcast will remain on the Company's website for approximately 30 days and a replay of the call will be available through March 9, 2016 at 855-859-2056 (404-537-3406 international) with passcode 38878862.

DISCLOSURE STATEMENTS

Reserve Disclosure

The Company may from time to time provide internally generated estimates of its probable and possible reserves. These estimates conform to SPEE methodology but are not prepared or reviewed by third party engineers. Unless otherwise indicated, probable and possible reserve estimates are determined using year-end pricing, as used in the calculation of proved reserves. Probable and possible reserves are subject to significantly greater risk of recovery than proved reserves.

Forward-Looking Statements

All statements in this press release, other than statements of historical fact, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Words such as expects, forecast, guidance, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein; however, these are not the exclusive means of identifying forward-looking statements. In particular, the Company is providing "2016 Operating Guidance," which contains projections for certain 2016 operational and financial metrics. Additional forward-looking statements in this release relate to, among other things, future capital expenditures, projects and opportunities.

These and other forward-looking statements in this press release are based on management's judgment as of the date of this release and are subject to numerous risks and uncertainties. Actual results may vary significantly from those indicated in the forward-looking statements due to, among other things: oil, NGL and natural gas price volatility, including regional price differentials; changes in operational and capital plans; changes in capital costs, operating 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, and our potential inability to achieve expected cost savings; 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, including new emission control requirements; derivative and hedging activities; risks associated with operating in one major geographic area; the success of the Company's risk management activities; unexpected obstacles to closing anticipated transactions or unfavorable purchase price adjustments; title to properties; litigation; and environmental liabilities. Please refer to the Company's Annual Report on Form 10-K for the year ended December 31, 2014 filed with the SEC and for the year 2015 upon filing, and other filings, including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, all of which are incorporated by reference herein, for further discussion of risk factors that may affect the forward-looking statements. The Company encourages you 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 at www.billbarrettcorp.com.

BILL BARRETT CORPORATION

Selected Operating Highlights

(Unaudited)

Three Months Ended  December 31,

Twelve Months Ended  December 31,

2015

2014

2015

2014

Production Data:

Oil (MBbls)

1,090

956

4,401

4,012

Natural gas (MMcf)

1,986

1,794

7,764

21,744

NGLs (MBbls)

264

146

898

1,476

Combined volumes (MBoe)

1,685

1,401

6,593

9,112

Daily combined volumes (Boe/d)

18,315

15,233

18,063

24,964

Average Sales Prices (before the effects of realized hedges):

Oil (per Bbl)

$

35.57

$

58.36

$

40.06

$

77.92

Natural gas (per Mcf)

1.98

4.16

2.23

4.78

NGLs (per Bbl)

11.98

20.16

12.16

31.55

Combined (per Boe)

27.21

47.26

31.02

50.82

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

Oil (per Bbl)

$

78.98

$

79.47

$

78.19

$

79.51

Natural gas (per Mcf)

3.72

3.88

3.75

4.45

NGLs (per Bbl)

11.98

21.44

12.16

31.51

Combined (per Boe)

57.36

61.44

58.27

50.73

Average Costs (per Boe):

Lease operating expenses

$

4.70

$

8.52

$

6.48

$

6.62

Gathering, transportation and processing expense

0.55

0.86

0.53

3.89

Production tax expenses

1.29

2.54

1.85

3.44

Depreciation, depletion and amortization

27.06

33.10

31.14

25.88

General and administrative expense, excluding long-term incentive compensation expense (1)

7.03

7.55

6.53

4.61

(1)

This separate presentation is a non-GAAP (Generally Accepted Accounting Principles) measure. Management believes the separate presentation of the long-term incentive compensation component of general and administrative expense is useful because it provides a better understanding of current period 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 stock-based/long-term incentive compensation expense.

 

BILL BARRETT CORPORATION

Consolidated Condensed Balance Sheets

(Unaudited)

As of December 31,

As of

December 31,

2015

2014

(in thousands)

Assets:

Cash and cash equivalents

$

128,836

$

165,904

Other current assets (1)

145,481

260,201

Property and equipment, net

1,170,684

1,753,121

Other noncurrent assets (1)

70,228

65,258

Total assets

$

1,515,229

$

2,244,484

Liabilities and Stockholders' Equity:

Current liabilities, other

$

144,791

$

238,917

Current liabilities, convertible senior notes

25,344

Capitalized lease obligation

3,222

3,648

Senior notes

800,579

800,000

Other long-term liabilities

17,221

147,087

Stockholders' equity

549,416

1,029,488

Total liabilities and stockholders' equity

$

1,515,229

$

2,244,484

(1)

At December 31, 2015, the estimated fair value of all of the Company's commodity derivative instruments was a net asset of $119.5 million, comprised of $99.8 million of current assets and $19.7 million of non-current assets. This amount will fluctuate based on estimated future commodity prices and the current hedge position.

 

BILL BARRETT CORPORATION

Consolidated Statements of Operations

(Unaudited)

Three Months Ended December 31,

Twelve Months Ended December 31,

2015

2014

2015

2014

(in thousands, except per share amounts)

Operating and Other Revenues:

Oil, gas and NGLs (1)

$

45,870

$

66,406

$

204,537

$

464,137

Other

691

496

3,355

8,154

Total operating and other revenues

46,561

66,902

207,892

472,291

Operating Expenses:

Lease operating

7,919

11,941

42,753

60,308

Gathering, transportation and processing

923

1,199

3,482

35,437

Production tax

2,177

3,563

12,197

31,333

Exploration

8

11

153

453

Impairment, dry hole costs and abandonment

314

14,268

575,310

46,881

(Gain) Loss on divestitures

2,504

3,511

1,745

100,407

Depreciation, depletion and amortization

45,609

46,379

205,275

235,805

Unused commitments

5,936

4,434

19,099

4,434

General and administrative (2)

11,850

10,573

43,050

41,981

Long-term incentive compensation (2)

3,014

1,749

10,840

11,380

Total operating expenses

80,254

97,628

913,904

568,419

Operating Income (Loss)

(33,693)

(30,726)

(706,012)

(96,128)

Other Income and Expense:

Interest and other income

46

303

565

1,294

Interest expense

(15,731)

(16,338)

(65,305)

(69,623)

Commodity derivative gain (loss) (1)

28,233

197,078

104,147

197,447

Gain (loss) on extinguishment of debt

1,749

Total other income and expense

12,548

181,043

41,156

129,118

Income (Loss) before Income Taxes

(21,145)

150,317

(664,856)

32,990

(Provision for) Benefit from Income Taxes

(61,252)

177,085

(17,909)

Net Income (Loss)

$

(21,145)

$

89,065

$

(487,771)

$

15,081

Net Income (Loss) per Common Share

Basic

$

(0.45)

$

1.85

$

(10.10)

$

0.31

Diluted

$

(0.45)

$

1.84

$

(10.10)

$

0.31

Weighted Average Common Shares Outstanding

Basic

48,373

48,093

48,303

48,011

Diluted

48,373

48,329

48,303

48,436

(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,

2015

2014

2015

2014

(in thousands)

Included in oil, gas and NGL production revenue:

Certain realized gains on hedges

$

$

181

$

$

1,070

Included in commodity derivative gain (loss):

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

$

50,818

$

19,692

$

179,652

$

(1,888)

Prior period unrealized (gain) loss transferred to realized (gain) loss

(46,681)

(2,905)

(145,226)

6,706

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

24,096

180,291

69,721

192,629

Total commodity derivative gain (loss)

$

28,233

$

197,078

$

104,147

$

197,447

(2)

This separate presentation is a non-GAAP (Generally Accepted Accounting Principles) measure. Management believes the separate presentation of the long-term incentive compensation component of general and administrative expense is useful because it provides a better understanding of current period 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 stock-based/long-term incentive compensation expense.

 

BILL BARRETT CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)

Three Months Ended  December 31,

Twelve Months Ended  December 31,

2015

2014

2015

2014

(in thousands)

Operating Activities:

Net income (loss)

$

(21,145)

$

89,065

$

(487,771)

$

15,081

Adjustments to reconcile to net cash provided by operations:

Depreciation, depletion and amortization

45,609

46,379

205,275

235,805

Impairment, dry hole costs and abandonment expense

314

14,268

575,310

46,881

Unrealized derivative (gain) loss, non-cash flow hedges

22,585

(177,386)

75,505

(199,335)

Deferred income tax benefit

60,248

(176,797)

16,644

Incentive compensation and other non-cash charges

2,759

1,701

10,040

11,352

Amortization of debt discounts and deferred financing costs

641

1,064

4,624

4,264

(Gain) loss on sale of properties

2,504

3,511

1,745

100,407

(Gain) loss on extinguishment of debt

(1,749)

Change in operating assets and liabilities:

Accounts receivable

601

23,138

20,995

32,163

Prepayments and other assets

572

729

311

1,643

Accounts payable, accrued and other liabilities

(23,145)

(15,604)

(18,798)

5,119

Amounts payable to oil and gas property owners

(2,680)

(9,068)

(3,530)

(7,132)

Production taxes payable

(838)

(7,630)

(11,482)

(1,175)

Net cash provided by (used in) operating activities

$

27,777

$

30,415

$

193,678

$

261,717

Investing Activities:

Additions to oil and gas properties, including acquisitions

(68,475)

(154,965)

(324,534)

(580,943)

Additions of furniture, equipment and other

(187)

(1,548)

(1,223)

(3,658)

Proceeds from sale of properties and other investing activities

56,505

(2,451)

123,122

555,296

Proceeds from the sale of short-term investments

20,000

115,000

Cash paid for short-term investments

(114,883)

Net cash provided by (used in) investing activities

$

7,843

$

(158,964)

$

(202,518)

$

(29,305)

Financing Activities:

Proceeds from debt

165,000

Principal payments on debt

(108)

(104)

(25,191)

(283,546)

Deferred financing costs and other

488

(221)

(3,037)

(2,683)

Proceeds from stock option exercises

126

Net cash provided by (used in) financing activities

$

380

$

(325)

$

(28,228)

$

(121,103)

Increase (Decrease) in Cash and Cash Equivalents

36,000

(128,874)

(37,068)

111,309

Beginning Cash and Cash Equivalents

92,836

294,778

165,904

54,595

Ending Cash and Cash Equivalents

$

128,836

$

165,904

$

128,836

$

165,904

 

BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow, Adjusted Net Income (Loss) and Pre-tax PV10

(Unaudited)

Discretionary Cash Flow Reconciliation

Three Months Ended  December 31,

Twelve Months Ended  December 31,

2015

2014

2015

2014

(in thousands, except per share amounts)

Net Income (Loss)

$

(21,145)

$

89,065

$

(487,771)

$

15,081

Adjustments to reconcile to discretionary cash flow:

Depreciation, depletion and amortization

45,609

46,379

205,275

235,805

Impairment, dry hole and abandonment expense

314

14,268

575,310

46,881

Exploration expense

8

11

153

453

Unrealized derivative (gain) loss, non-cash flow hedges

22,585

(177,386)

75,505

(199,335)

Deferred income taxes

60,248

(176,797)

16,644

Stock compensation and other non-cash charges

2,759

1,701

10,040

11,352

Amortization of debt discounts and deferred financing costs

641

1,064

4,624

4,264

(Gain) loss on sale of properties

2,504

3,511

1,745

100,407

(Gain) loss on extinguishment of debt

(1,749)

Discretionary Cash Flow

$

53,275

$

38,861

$

206,335

$

231,552

Per share, diluted

$

1.10

$

0.80

$

4.27

$

4.78

Per Boe

$

31.60

$

27.74

$

31.30

$

25.41

Adjusted Net Income (Loss) Reconciliation

Three Months Ended  December 31,

Twelve Months Ended  December 31,

2015

2014

2015

2014

(in thousands, except per share amounts)

Net Income (Loss)

$

(21,145)

$

89,065

$

(487,771)

$

15,081

  (Provision for) Benefit from income taxes

(61,252)

177,085

(17,909)

Income (Loss) before income taxes

(21,145)

150,317

(664,856)

32,990

Adjustments to net income (loss):

Unrealized derivative (gain) loss, non-cash flow hedges

22,585

(177,386)

75,505

(199,335)

Impairment expense

72

12,062

572,438

40,183

(Gain) loss on sale of properties

2,504

3,511

1,745

100,407

(Gain) loss on extinguishment of debt

(1,749)

One-time items:

CO2 unused commitment

1,429

1,429

West Tavaputs NGL processing true-up

(268)

(1,273)

(5,677)

Expenses (credit) relating to compressor station fire

(570)

Expenses relating to amending credit facility

1,617

Adjusted Income (Loss) before income taxes

5,177

(11,496)

(15,144)

(32,002)

  (Provision for) Benefit from income taxes

(1,804)

237

5,714

6,787

Adjusted Net Income (Loss)

$

3,373

$

(11,259)

$

(9,430)

$

(25,215)

Per share, diluted

$

0.07

$

(0.23)

$

(0.20)

$

(0.52)

Per Boe

$

2.00

$

(8.04)

$

(1.43)

$

(2.77)

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.

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SOURCE Bill Barrett Corporation



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