Bill Barrett Corporation Reports Third Quarter 2015 Results - Production Volume of 1.7 MMBoe Exceeds Guidance, 72% Production Growth from DJ Basin, Continued Cost Discipline with LOE of $5.67 per Boe; Expect Non-Core Asset Sales of $79 Million to be Accomplished during 2015

05 Nov, 2015, 16:18 ET from Bill Barrett Corporation

DENVER, Nov. 5, 2015 /PRNewswire/ -- Bill Barrett Corporation (the "Company") (NYSE: BBG) reports third quarter of 2015 results, including these highlights:

  • Production sales volumes of 1.7 MMBoe, exceeding guidance by 13% due to the performance of the DJ Basin extended reach lateral ("XRL") drilling program
  • Increased Denver-Julesburg ("DJ") Basin production by 72% year-over-year and 14% sequentially
  • Reported adjusted net income of $(0.09) per share excluding non-recurring charges and impairment expense; generated $1.11 per share of discretionary cash flow
  • Maintaining cost discipline as XRL well costs of $5.6 million are approximately 32% lower compared to wells drilled in the fourth quarter of 2014
  • Lease operating expense of $5.67 per Boe, a 19% sequential reduction
  • Lease operating expense guidance lowered by 8% at the mid-point to $45-$47 million
  • Executed agreements to sell non-core asset for aggregate proceeds of $79 million year-to-date
  • Borrowing base reaffirmed at $375 million in September 2015

Chief Executive Officer and President Scot Woodall commented, "We posted another quarter of solid results that was highlighted by production exceeding expectations for a third consecutive quarter and our ability to decrease drilling days for XRL wells and meaningfully lower well costs and cash expenses. We remain on track to meet full-year production guidance despite shutting in approximately 1,000 Boe/d of production in the Uinta Basin during the second quarter of 2015 and including a reduction in volumes associated with expected asset sales. This is clearly a reflection of the performance of our Northeast ("NE") Wattenberg assets. XRL drilling days have improved by 40% to approximately 10 days per well and we have been consistently drilling recent wells in 8 days or less. Furthermore, associated cost reductions have lowered completed XRL well costs to $5.6 million, or by 32%, and we are committed to continuous cost reduction measures as we endeavor to further improve our capital efficiency. Efficiency gains are also translating into tangible reductions in operating costs across our assets, as evidenced by third quarter LOE of $5.67 per Boe, which was 19% lower than the second quarter, and we will seek additional means to drive down costs.       

"We maintain a strong financial position. Year-to-date, we have executed agreements to sell assets that were not expected to compete for drilling capital in the near or mid-term for aggregate proceeds of $79 million, including transactions in the DJ, Uinta and Powder River Basins. This further augments our balance sheet and enhances our liquidity as we look to 2016. Our undrawn revolving credit facility was recently reaffirmed at $375 million and, when combined with our cash position, provides ample liquidity to navigate the current environment."

THIRD QUARTER 2015 OPERATING AND FINANCIAL RESULTS  (Prior year period results are pro forma for assets sold.)

The Company realized growth in production volumes from its core DJ Basin asset, driven by the results of the NE Wattenberg XRL well program that offset a production decline from the Uinta Oil Program ("UOP"). Oil, natural gas and natural gas liquids ("NGL") production from the DJ Basin and UOP totaled 1.7 million barrels of oil equivalent ("MMBoe") in the third quarter of 2015 compared with 1.4 MMBoe in the third quarter of 2014. DJ Basin production grew 72%, while UOP production was down 38% as compared to the third quarter of 2014. The decline in UOP production was primarily due to a decrease in drilling and workover activity and the decision to shut-in certain wells during the second quarter of 2015 due to higher operating costs. Third quarter of 2015 production was 63% oil, 22% natural gas and 15% NGLs. The increase in the proportion of natural gas and NGL volumes relative to oil volumes was primarily due to a greater amount of natural gas liquids yields that benefited from the expansion of regional processing capacity and the delay in timing of oil sales from inventory.

Three Months Ended  September 30,

Three Months Ended  June 30,

2015

2014

Change

2015

Change

Production Sales Data:

Oil (MBbls)

1,066

934

14

%

1,120

(5)

%

Natural gas(MMcf)

2,214

1,842

20

%

1,800

23

%

NGLs (MBbls)

264

148

78

%

208

27

%

Combined volumes (MBoe)

1,699

1,389

22

%

1,628

4

%

Daily combined volumes (Boe/d)

18,467

15,098

22

%

17,890

3

%

Pre-hedge commodity prices were down significantly compared with 2014. For the third quarter of 2015, 93% of oil production and 83% of natural gas production benefited from commodity derivative swaps that averaged $89.81 per barrel of oil (WTI) and $4.13 per MMBtu of natural gas (regionally priced at NWPL). The Company had no NGL hedges in place.

Three Months Ended  September 30,

Three Months Ended  June 30,

2015 Pre- hedge

2015 Including hedge

2014 Pre- hedge

2015 Pre- hedge

2015 Including hedge

Average Sales Price:

Oil (per Bbl)

$

38.71

$

79.15

$

82.25

$

48.68

$

78.44

Natural gas (per Mcf)

2.08

3.36

4.32

2.33

4.10

NGLs (per Bbl)

11.17

11.17

24.27

12.76

12.76

Combined (per Boe)

28.73

55.77

63.64

37.70

60.13

Cash operating costs (lease operating expense ("LOE"), gathering, transportation and processing costs and production tax expense) were $8.23 per Boe in the third quarter of 2015, down 17% compared to the second quarter of 2015. LOE was $5.67 per Boe, down 19% compared to the second quarter of 2015. This was primarily a result of increased operational efficiencies, lease operating cost reductions and the Company's decision during the second quarter of 2015 to reduce workover activity in the UOP and to shut-in certain UOP wells in the current commodity price environment. LOE for the DJ Basin improved to an average of $3.96 per Boe in the third quarter of 2015. Production tax expense for the third quarter of 2015 averaged 7.5% of pre-hedge revenue. Normalized production taxes are expected to approximate 8% of pre-hedge revenue for the fourth quarter of 2015.

Three Months Ended  September 30,

Three Months Ended  June 30,

2015

2014

Change

2015

Change

Average Costs (per Boe):

Lease operating expenses

$

5.67

$

7.53

(25)

%

$

7.01

(19)

%

Gathering, transportation and processing expense

0.40

0.63

(37)

%

0.57

(30)

%

Production tax expenses

2.16

5.48

(61)

%

2.34

(8)

%

Depreciation, depletion and amortization

32.22

34.31

(6)

%

32.36

%

Corporate Discretionary Cash Flow and Adjusted Net Loss  (Prior period totals are total company results and are not pro forma for assets sold.)

Discretionary cash flow and adjusted net loss are non-GAAP measures. These measures are reconciled to net income (loss) in the schedule attached to this press release. Discretionary cash flow and adjusted net income as previously reported for the 2014 period includes cash flow and income generated from assets sold over the past two years.

Discretionary cash flow in the third quarter of 2015 was $53.5 million, or $1.11 per share, compared to $70.1 million, or $1.46 per share, in the third quarter of 2014. Discretionary cash flow in the third quarter of 2015 compared to 2014 was impacted by lower revenues due to a 36% decline in production volumes as a result of asset sales.

Net loss for the third quarter of 2015 was $(410.3) million, or $(8.49) per share, compared with the third quarter of 2014 at $(34.6) million, or $(0.72) per share. Adjusted net loss was $(4.4) million, or $(0.09) per share, in the third quarter of 2015 compared with $(3.1) million, or $(0.06) per share, in the third 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  September 30,

2015

2014

Discretionary Cash Flow ($ millions)

$

53.5

$

70.1

Discretionary Cash Flow per share

1.11

1.46

Adjusted Net Loss ($ millions)

(4.4)

(3.1)

Adjusted Net Loss per share

(0.09)

(0.06)

Non-Cash Impairment

The Company recognized a non-cash impairment charge of $571.9 million in the third quarter of 2015 related to the UOP proved and unproved oil and gas assets. The impairment was the result of reduced future net revenues compared against the current carrying value from the second quarter of 2015 to the third quarter of 2015.

Primarily as a result of this quarter's impairment charge, the Company recorded a valuation allowance against its net deferred tax asset of $66.4 million.

Debt and Liquidity

The Company's semi-annual borrowing base review was completed in September 2015 with the bank group reaffirming the Company's $375 million borrowing base related to its revolving credit facility maturing in April 2020. At September 30, 2015, the 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 $802.9 million and cash and short-term investments were $112.8 million, resulting in net debt (principal balance of debt outstanding less the cash and investment balance) of $690.1 million. Liquidity was $461.8 million.

In addition, as of November 5, 2015, the Company has not issued any shares under its previously announced "at-the-market" equity offering program and does not anticipate currently utilizing it due to market conditions.

Divestitures

During the third quarter, the Company announced the signing of an agreement to sell certain properties located in the Uinta Basin for after-tax cash proceeds of approximately $27 million. The transaction is expected to close on or before November 30, 2015, subject to customary closing conditions. The properties produced approximately 484 Boe/d during September 2015, had estimated proved reserves of 11 million barrels of oil equivalent ("MMBoe") (9% proved developed) as of December 31, 2014 and included 17,632 net acres.

Subsequent to the end of the quarter, the Company executed agreements to sell certain assets in the DJ Basin that are located outside of the core NE Wattenberg area for after-tax cash proceeds of approximately $31 million. The transaction is expected to close on or before November 30, 2015, and is subject to customary closing conditions.

Including this transaction, the Company has completed or announced three separate DJ Basin transactions for aggregate after-tax proceeds of $43 million during 2015. None of the assets sold are located within the Company's NE Wattenberg focus area, and they were not expected to compete for drilling capital in the near or mid-term. The assets primarily included legacy vertical wells that had estimated production of approximately 1,265 Boe/d (29% natural gas), estimated proved reserves of 4 MMBoe (76% proved developed) as of December 31, 2014 and included 23,735 net acres. Based on the Company's internal estimates, the sale price amounts to approximately 8x estimated 2016 operating cash flow (excluding general and administrative expense) based on current strip pricing.

In aggregate, the Company expects to receive proceeds of approximately $58 million, prior to customary purchase price adjustments, for the Uinta Basin and recent DJ Basin divestitures in the fourth quarter of 2015. The sale of these properties will not result in a reduction of the Company's borrowing base related to its revolving credit facility.

Capital Expenditures

Capital expenditures ("Capex") for the third quarter of 2015 were $63.2 million and totaled $242.6 million for the nine months ended September 30, 2015. Capex included 18 gross/ 16.9 net spud wells in the DJ Basin, all of which were XRL wells operated by the Company, and 3 gross/ 1 net operated wells in the UOP. In the third quarter, 8 gross/ 7.8 net XRL wells began flowback operations and were placed on initial sales. Capital expenditures included $59.3 million for drilling, $0.8 million for leaseholds, and $3.1 million for infrastructure and corporate assets.

Basin Summary

Three Months Ended  September 30, 2015

Nine Months Ended  September 30, 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

14,250

18

$

55.8

12,828

38

$

214.3

Uinta

4,185

2

7.2

5,059

8

26.3

Other (2)

32

0.2

91

2.0

Total

18,467

20

$

63.2

17,978

46

$

242.6

(1)

Includes operated and non-operated wells

(2)

Primarily non-operated production in Wyoming and New Mexico

OPERATIONAL HIGHLIGHTS

DJ Basin

Third quarter DJ Basin highlights include:

  • Produced an average of 14,250 Boe/d, an increase of 72% from the third quarter of 2014 and an increase of 14% sequentially.
  • DJ Basin oil volumes averaged 8,283 Bbls/d, an increase of 72% from the third quarter of 2014 and an increase of 3% sequentially.
  • Spud 18 gross/ 16.9 net operated XRL wells during the third quarter of 2015.
  • Placed 8 gross/ 7.8 net XRL wells on initial sales during the third quarter of 2015.
  • Placed 9 gross/ 8.1 net XRL wells on initial sales in November 2015.
  • Operational efficiency increased by reducing the number of drilling days for XRL wells by 40% to an average of approximately 10 days per well. Recent wells have consistently been drilled in approximately 8 days per well, including a best-in-class well drilled in 6.9 days. These improved efficiencies allow the remainder of 2015 drilling program to be accomplished with one-rig drilling program.
  • Maintaining a sharp focus on cost discipline as recently contracted XRL drilling and completion costs of $5.6 million are approximately 32% lower compared to wells drilled in the fourth quarter of 2014.

The NE Wattenberg XRL program remains the focus of the 2015 operating plan as it offers the best returns in the Company's portfolio. Approximately 90% of the 2015 capital expenditures are planned for the NE Wattenberg area.

Uinta Oil Program

Drilling and completion activity in the UOP for the remainder of the year includes 4 commitment wells as the Company has elected to focus the majority of its 2015 capital program on its higher-return DJ Basin assets. Operations are focused on operational efficiencies, and associated cost reductions have been realized as a result of lower lease operating costs following the Company's decision to proactively reduce workover activity in the UOP and to shut-in certain wells in the current commodity price environment.

2015 OPERATING GUIDANCE

The Company is providing the following update to guidance for its 2015 activities. See "Forward-Looking Statements" below.

  • Capital expenditures of $315-$325 million, unchanged.
    • Includes the reduction in the operated rig count from two rigs to one rig in NE Wattenberg as previously announced.
  • Production of 6.3-6.5 MMBoe, unchanged.
    • It is estimated that the aggregate production reduction from the pending DJ and Uinta Basin asset sales, which are scheduled to close on or before November 30, 2015, will be approximately 42 MBoe in December 2015.
  • Lease operating expense of $45-$47 million, decreased from $48-$52 million to correspond with lease operating cost reductions in both the DJ Basin and UOP.

COMMODITY HEDGES UPDATE

Generally, it is the Company's strategy to hedge 50%-70% of production on a forward 12-month to 18-month basis to reduce the risks associated with unpredictable future commodity prices to provide certainty for a portion of its cash flow and to support its capital expenditure program.

The following table summarizes hedge positions as of November 5, 2015:

Oil (WTI)

Natural Gas (NWPL)

Period

Volume Bbls/d

Price $/Bbl

Volume MMBtu/d

Price $/MMBtu

4Q15

10,800

$

89.81

20,000

$

4.13

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

Third Quarter Conference Call and Webcast

The Company plans to host a conference call on Friday, November 6, 2015, to discuss the results and management's outlook for the future (not part of this earnings 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 63826020. The webcast will remain on the Company's website for approximately 30 days and a replay of the call will be available through November 13, 2015 at 855-859-2056 (404-537-3406 international) with passcode 63826020.

DISCLOSURE STATEMENTS

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 "2015 Operating Guidance," which contains projections for certain 2015 operational and financial metrics as well as certain projections for the fourth quarter of 2015. Additional forward-looking statements in this release relate to, among other things, the closing of, and proceeds from the planned asset sales and 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; 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 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  www.billbarrettcorp.com.

BILL BARRETT CORPORATION

Selected Operating Highlights

(Unaudited)

Three Months Ended  September 30,

Nine Months Ended  September 30,

2015

2014 (1)

2015

2014 (1)

Production Data:

Oil (MBbls)

1,066

1,107

3,311

3,056

Natural gas (MMcf)

2,214

6,834

5,772

19,950

NGLs (MBbls)

264

408

635

1,330

Combined volumes (MBoe)

1,699

2,654

4,908

7,711

Daily combined volumes (Boe/d)

18,467

28,848

17,978

28,245

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

Oil (per Bbl)

$

38.71

$

82.83

$

41.54

$

84.04

Natural gas (per Mcf)

2.08

4.24

2.31

4.83

NGLs (per Bbl)

11.17

32.65

12.24

32.80

Combined (per Boe)

28.73

50.48

32.33

51.47

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

Oil (per Bbl)

$

79.15

$

79.98

$

77.93

$

79.52

Natural gas (per Mcf)

3.36

4.27

3.76

4.50

NGLs (per Bbl)

11.17

33.19

12.24

32.61

Combined (per Boe)

55.77

49.46

58.58

48.78

Average Costs (per Boe):

Lease operating expenses

$

5.67

$

6.14

$

7.10

$

6.27

Gathering, transportation and processing expense

0.40

4.06

0.52

4.44

Production tax expenses

2.16

3.95

2.04

3.60

Depreciation, depletion and amortization

32.22

26.01

32.53

24.57

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

5.31

2.86

6.36

4.07

(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 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 September 30,

As of

December 31,

2015

2014

(in thousands)

Assets:

Cash and cash equivalents

$

92,836

$

165,904

Short-term investments

19,992

Other current assets (1)

157,312

260,201

Property and equipment, net

1,238,947

1,753,121

Other noncurrent assets (1)

87,173

65,258

Total assets

$

1,596,260

$

2,244,484

Liabilities and Stockholders' Equity:

Current liabilities, other

$

199,635

$

239,343

Current liabilities, convertible senior notes

579

25,344

Capitalized lease obligation

2,894

3,222

Senior notes

800,000

800,000

Other long-term liabilities

25,386

147,087

Stockholders' equity

567,766

1,029,488

Total liabilities and stockholders' equity

$

1,596,260

$

2,244,484

(1)

At September 30, 2015, the estimated fair value of all of the Company's commodity derivative instruments was a net asset of $142.1 million, comprised of $109.9 million of current assets and $32.2 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  September 30,

Nine Months Ended  September 30,

2015

2014

2015

2014

(in thousands, except per share amounts)

Operating and Other Revenues:

Oil, gas and NGLs (1)

$

48,799

$

134,342

$

158,667

$

397,731

Other

880

921

2,664

7,658

Total operating and other revenues

49,679

135,263

161,331

405,389

Operating Expenses:

Lease operating

9,638

16,284

34,834

48,367

Gathering, transportation and processing

684

10,784

2,559

34,238

Production tax

3,670

10,495

10,020

27,770

Exploration

20

23

145

442

Impairment, dry hole costs and abandonment

572,651

29,109

574,996

32,613

(Gain) Loss on divestitures

(77)

99,466

(759)

96,896

Depreciation, depletion and amortization

54,738

69,024

159,666

189,426

Unused commitments

4,388

13,163

General and administrative (2)

9,018

7,591

31,200

31,408

Long-term incentive compensation (2)

2,007

3,520

7,826

9,631

Total operating expenses

656,737

246,296

833,650

470,791

Operating Income (Loss)

(607,058)

(111,033)

(672,319)

(65,402)

Other Income and Expense:

Interest and other income

100

264

519

991

Interest expense

(15,754)

(18,033)

(49,574)

(53,285)

Commodity derivative gain (loss) (1)

69,133

72,299

75,914

369

Gain (loss) on extinguishment of debt

1,749

Total other income and expense

53,479

54,530

28,608

(51,925)

Income (Loss) before Income Taxes

(553,579)

(56,503)

(643,711)

(117,327)

(Provision for) Benefit from Income Taxes

143,265

21,854

177,085

43,343

Net Income (Loss)

$

(410,314)

$

(34,649)

$

(466,626)

$

(73,984)

Net Income (Loss) per Common Share

Basic

$

(8.49)

$

(0.72)

$

(9.67)

$

(1.54)

Diluted

$

(8.49)

$

(0.72)

$

(9.67)

$

(1.54)

Weighted Average Common Shares Outstanding

Basic

48,340

48,060

48,280

47,983

Diluted

48,340

48,060

48,280

47,983

(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  September 30,

Nine Months Ended  September 30,

2015

2014

2015

2014

(in thousands)

Included in oil, gas and NGL production revenue:

Certain realized gains on hedges

$

$

351

$

$

889

Included in commodity derivative gain (loss):

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

$

45,936

$

(3,054)

$

128,834

$

(21,580)

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

23,197

75,353

(52,920)

21,949

Total commodity derivative gain (loss)

$

69,133

$

72,299

$

75,914

$

369

(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  September 30,

Nine Months Ended  September 30,

2015

2014

2015

2014

(in thousands)

Operating Activities:

Net income (loss)

$

(410,314)

$

(34,649)

$

(466,626)

$

(73,984)

Adjustments to reconcile to net cash provided by operations:

Depreciation, depletion and amortization

54,738

69,024

159,666

189,426

Impairment, dry hole costs and abandonment expense

572,651

29,109

574,996

32,613

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

(23,197)

(75,353)

52,920

(21,949)

Deferred income tax benefit

(142,977)

(22,073)

(176,797)

(43,604)

Incentive compensation and other non-cash charges

2,068

3,496

7,281

9,651

Amortization of debt discounts and deferred financing costs

633

1,068

3,983

3,200

(Gain) loss on sale of properties

(77)

99,466

(759)

96,896

(Gain) loss on extinguishment of debt

(1,749)

Change in operating assets and liabilities:

Accounts receivable

3,285

3,326

20,394

9,025

Prepayments and other assets

878

(154)

(261)

914

Accounts payable, accrued and other liabilities

18,025

23,518

4,347

20,723

Amounts payable to oil and gas property owners

(4,161)

(850)

1,936

Production taxes payable

3,208

7,106

(10,644)

6,455

Net cash provided by (used in) operating activities

$

74,760

$

103,884

$

165,901

$

231,302

Investing Activities:

Additions to oil and gas properties, including acquisitions

(61,936)

(161,633)

(256,059)

(425,978)

Additions of furniture, equipment and other

(158)

(1,254)

(1,036)

(2,110)

Proceeds from sale of properties and other investing activities

99

549,572

66,617

557,747

Proceeds from the sale of short-term investments

45,000

95,000

Cash paid for short-term investments

(114,883)

Net cash provided by (used in) investing activities

$

(16,995)

$

386,685

$

(210,361)

$

129,659

Financing Activities:

Proceeds from debt

30,000

165,000

Principal payments on debt

(107)

(281,157)

(25,083)

(283,442)

Deferred financing costs and other

(704)

(413)

(3,525)

(2,462)

Proceeds from stock option exercises

126

Net cash provided by (used in) financing activities

$

(811)

$

(251,570)

$

(28,608)

$

(120,778)

Increase (Decrease) in Cash and Cash Equivalents

56,954

238,999

(73,068)

240,183

Beginning Cash and Cash Equivalents

35,882

55,779

165,904

54,595

Ending Cash and Cash Equivalents

$

92,836

$

294,778

$

92,836

$

294,778

 

BILL BARRETT CORPORATION

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

(Unaudited)

Discretionary Cash Flow Reconciliation

Three Months Ended  September 30,

Nine Months Ended  September 30,

2015

2014

2015

2014

(in thousands, except per share amounts)

Net Income (Loss)

$

(410,314)

$

(34,649)

$

(466,626)

$

(73,984)

Adjustments to reconcile to discretionary cash flow:

Depreciation, depletion and amortization

54,738

69,024

159,666

189,426

Impairment, dry hole and abandonment expense

572,651

29,109

574,996

32,613

Exploration expense

20

23

145

442

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

(23,197)

(75,353)

52,920

(21,949)

Deferred income taxes

(142,977)

(22,073)

(176,797)

(43,604)

Stock compensation and other non-cash charges

2,068

3,496

7,281

9,651

Amortization of debt discounts and deferred financing costs

633

1,068

3,983

3,200

(Gain) loss on sale of properties

(77)

99,466

(759)

96,896

(Gain) loss on extinguishment of debt

(1,749)

Discretionary Cash Flow

$

53,545

$

70,111

$

153,060

$

192,691

Per share, diluted

$

1.11

$

1.46

$

3.17

$

4.02

Per Boe

$

31.52

$

26.42

$

31.19

$

24.99

Adjusted Net Income (Loss) Reconciliation

Three Months Ended  September 30,

Nine Months Ended  September 30,

2015

2014

2015

2014

(in thousands, except per share amounts)

Net Income (Loss)

$

(410,314)

$

(34,649)

$

(466,626)

$

(73,984)

Adjustments to net income (loss):

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

(23,197)

(75,353)

52,920

(21,949)

Impairment expense

571,863

26,743

572,366

28,121

(Gain) loss on sale of properties

(77)

99,466

(759)

96,896

(Gain) loss on extinguishment of debt

(1,749)

One-time items:

West Tavaputs NGL processing true-up

(1,005)

(5,677)

Expenses (credit) relating to compressor station fire

(570)

Expenses relating to amending credit facility

1,617

Subtotal adjustments

548,589

50,856

623,390

96,821

Effective tax rate

26

%

38

%

28

%

38

%

Tax effected adjustments

405,956

31,531

448,841

60,029

Adjusted Net Income (Loss)

$

(4,358)

$

(3,118)

$

(17,785)

$

(13,955)

Per share, diluted

$

(0.09)

$

(0.06)

$

(0.37)

$

(0.29)

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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