 | Press Release | |
For immediate release
Company contact: Larry C. Busnardo, Senior Director, Investor Relations, 303-312-8514
Bill Barrett Corporation Reports Third Quarter 2016 Financial and Operating Results
DENVER - November 3, 2016 - Bill Barrett Corporation (the "Company") (NYSE: BBG) reports third quarter of 2016 financial and operating results, including these highlights:
| • | Production sales volumes of 1.6 MMBoe (65% oil) |
| • | DJ Basin oil price differential narrowed to $2.21 per barrel, representing a 54% sequential improvement from the second quarter of 2016 |
| • | LOE averaged $3.06 per Boe, representing a 42% sequential improvement from the second quarter of 2016 |
| • | LOE guidance lowered to $29-$31 million from $31-$34 million to reflect cost reductions and the sale of higher operating cost properties in the Uinta Basin |
| • | 2016 capital expenditures expected to total approximately $100 million; anticipate cash flow to be in excess of capital expenditures for the year |
| • | Extended reach lateral ("XRL") development program in the Denver-Julesburg ("DJ") Basin resumed with up to 15 gross wells expected to spud prior to year-end |
| • | Completed sale of Uinta Basin properties for net cash proceeds of approximately $30 million |
| • | Exited the quarter financially well positioned with a cash position of $174 million and an undrawn credit facility that provides additional liquidity |
Chief Executive Officer and President Scot Woodall commented, "Our team has done an excellent job of maintaining positive financial and operational momentum in a challenging environment, which translated into solid results for the third quarter. Production sales volumes were near the upper end of guidance and EBITDA was better than expected as DJ Basin oil price differentials improved and we are seeing continued improvement in costs across the spectrum. Our XRL development program resumed in September and we have spud six wells with plans to spud up to 15 gross XRL wells by the end of the year. This results in an increasing production profile as the wells begin contributing to production during 2017. We are seeing consistent results across our acreage and our operations team has incorporated several new concepts that we believe will translate into improved well performance. The XRL drilling program generates attractive economic returns in the current commodity price environment and we are pursuing further capital efficiency measures designed to improve well costs and enhance economic returns. We continue to efficiently invest our capital and expect cash flow to be in excess of capital expenditures based on current internal projections. Our liquidity remains strong with a significant cash position, an undrawn credit facility and a solid hedge position."
OPERATING AND FINANCIAL RESULTS
The following table summarizes certain operating and financial results for the third quarter of 2016 and 2015 and the second quarter of 2016:
| Three Months Ended September 30, | Three Months Ended June 30, | ||||||||||||||||
| 2016 | 2015 | Change | 2016 | Change | |||||||||||||
| Combined production sales volumes (MBoe) | 1,566 | 1,699 | (8 | )% | 1,607 | (3 | )% | ||||||||||
| Net cash provided by (used in) operating activities ($ millions) | $ | 67.4 | $ | 74.8 | (10 | )% | $ | 8.3 | 712 | % | |||||||
Discretionary cash flow ($ millions) (1) | $ | 36.5 | $ | 53.5 | (32 | )% | $ | 32.8 | 11 | % | |||||||
| Combined realized prices with hedging (per Boe) | $ | 45.06 | $ | 55.77 | (19 | )% | $ | 44.84 | — | % | |||||||
| Net income (loss) ($ millions) | $ | (26.2 | ) | $ | (410.3 | ) | 94 | % | $ | (48.4 | ) | 46 | % | ||||
| Per share, basic | $ | (0.44 | ) | $ | (8.49 | ) | 95 | % | $ | (0.93 | ) | 53 | % | ||||
| Per share, diluted | $ | (0.44 | ) | $ | (8.49 | ) | 95 | % | $ | (0.93 | ) | 53 | % | ||||
Adjusted net income (loss) ($ millions) (1) | $ | (6.2 | ) | $ | (4.4 | ) | (41 | )% | $ | (6.7 | ) | 7 | % | ||||
| Per share, basic | $ | (0.10 | ) | $ | (0.09 | ) | (11 | )% | $ | (0.13 | ) | 23 | % | ||||
| Per share, diluted | $ | (0.10 | ) | $ | (0.09 | ) | (11 | )% | $ | (0.13 | ) | 23 | % | ||||
| Weighted average shares outstanding, basic (in thousands) | 58,852 | 48,340 | 22 | % | 51,832 | 14 | % | ||||||||||
| Weighted average shares outstanding, diluted (in thousands) | 58,852 | 48,340 | 22 | % | 51,832 | 14 | % | ||||||||||
EBITDAX ($ millions) (1) | $ | 49.8 | $ | 68.3 | (27 | )% | $ | 47.3 | 5 | % | |||||||
| (1) | Discretionary cash flow, adjusted net income (loss) and EBITDAX are non-GAAP (Generally Accepted Accounting Principles) measures. Please reference the reconciliations to GAAP financial statements at the end of this release. |
Oil, natural gas and natural gas liquids ("NGL") production totaled approximately 1.6 million barrels of oil equivalent ("MMBoe") in the third quarter of 2016 and was at the upper end of the guidance range of 1.5-1.6 MMBoe. Lower production sales volumes relative to the comparable 2015 period were primarily the result of non-core asset sales in the DJ Basin and Uinta Basin that were completed during 2015 and 2016.
Third quarter of 2016 production was 65% oil, 18% natural gas and 17% NGLs, which is consistent with guidance.
| Three Months Ended September 30, | Three Months Ended June 30, | |||||||||||||
| 2016 | 2015 | Change | 2016 | Change | ||||||||||
| Production Sales Data: | ||||||||||||||
| Oil (MBbls) | 1,016 | 1,066 | (5 | )% | 1,023 | (1 | )% | |||||||
| Natural gas (MMcf) | 1,734 | 2,214 | (22 | )% | 1,944 | (11 | )% | |||||||
| NGLs (MBbls) | 261 | 264 | (1 | )% | 260 | — | % | |||||||
| Combined volumes (MBoe) | 1,566 | 1,699 | (8 | )% | 1,607 | (3 | )% | |||||||
| Daily combined volumes (Boe/d) | 17,022 | 18,467 | (8 | )% | 17,659 | (4 | )% | |||||||
Cash operating costs (lease operating expense ("LOE"), gathering, transportation and processing costs and production tax expense) averaged $5.81 per Boe in the third quarter of 2016, down 26% compared to the second quarter of 2016, when average cash operating costs were $7.85 per Boe.
LOE averaged $3.06 per Boe in the third quarter of 2016, a 42% improvement to the second quarter of 2016 and 46% lower than the third quarter of 2015. LOE for the DJ Basin averaged $2.45 per Boe in the third quarter of 2016 compared to $3.74 per Boe in the second quarter of 2016 and $3.96 per Boe in the third quarter of 2015. The reduction in total LOE was primarily a result of an improvement in operating efficiencies, the DJ Basin becoming a greater component of corporate operations, and the sale of Uinta Basin properties that had a higher operating cost component. LOE
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per Boe is anticipated to be higher in the fourth quarter of 2016 relative to the third quarter due to greater seasonal operating costs that are typically experienced during colder months.
Production taxes are expected to approximate 8% of pre-hedge revenue for the fourth quarter of 2016.
| Three Months Ended September 30, | Three Months Ended June 30, | ||||||||||||||||
| 2016 | 2015 | Change | 2016 | Change | |||||||||||||
| Average Costs (per Boe): | |||||||||||||||||
| Lease operating expenses | $ | 3.06 | $ | 5.67 | (46 | )% | $ | 5.28 | (42 | )% | |||||||
| Gathering, transportation and processing expense | 0.30 | 0.40 | (25 | )% | 0.38 | (21 | )% | ||||||||||
| Production tax expenses | 2.45 | 2.16 | 13 | % | 2.19 | 12 | % | ||||||||||
| Depreciation, depletion and amortization | 27.51 | 32.22 | (15 | )% | 27.05 | 2 | % | ||||||||||
Debt and Liquidity
At September 30, 2016, the principal debt balance was $718.8 million, while cash and cash equivalents were $174.3 million, resulting in net debt (principal balance of debt outstanding less the cash and cash equivalents balance) of $544.5 million. Cash and cash equivalents were reduced subsequent to the end of the quarter as the Company made regularly scheduled interest payments of approximately $26 million related to its Senior Notes due 2019 and 2022.
The Company's semi-annual borrowing base review was completed in October 2016 with the lenders setting a borrowing base of $300 million, a 10% reduction due to the sale of non-core assets and the effect of a lower derivative position. There were no changes to the terms or conditions of the credit facility and there are no borrowings outstanding. The revolving credit facility has $274 million in available capacity, after taking into account a $26 million letter of credit.
Uinta Basin Asset Sale
The Company closed the sale of certain non-core assets located in the Uinta Basin on July 14, 2016, for net cash proceeds of approximately $30 million. The proceeds from the sale were used for general corporate purposes and to enhance the Company's liquidity position.
Capital Expenditures
Capital expenditures ("capex") for the third quarter of 2016 totaled $8.1 million as the Company did not operate a drilling rig for much of the quarter and no wells were completed. The DJ Basin XRL drilling program resumed during September and 3 XRL wells spud prior to the end of the quarter. Capex for the third quarter consisted of $4.6 million for drilling, $1.4 million for leaseholds, and $2.1 million for infrastructure and corporate assets.
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| Three Months Ended September 30, 2016 | Nine Months Ended September 30, 2016 | ||||||||||||||||||
| Average Net Daily Production (Boe/d) | Wells Spud Net | Capital Expenditures ($ millions) | Average Net Daily Production (Boe/d) | Wells Spud Net | Capital Expenditures ($ millions) | ||||||||||||||
| Basin: | |||||||||||||||||||
| Denver-Julesburg | 14,543 | 3 | $ | 7.7 | 13,467 | 7 | $ | 67.0 | |||||||||||
| Uinta | 2,457 | — | 0.1 | 3,058 | — | 1.1 | |||||||||||||
| Other | 22 | — | 0.3 | 44 | — | 1.4 | |||||||||||||
| Total | 17,022 | 3 | $ | 8.1 | 16,569 | 7 | $ | 69.5 | |||||||||||
OPERATIONAL HIGHLIGHTS
DJ Basin
| • | Produced an average of 14,543 Boe/d (62% oil) in the third quarter of 2016, which represents an increase of 3% from the second quarter of 2016 and an increase of 11% from the third quarter of 2015, pro forma for asset sales. |
| • | Oil volumes averaged 8,989 Bbls/d during the third quarter of 2016, an increase of 5% from the second quarter of 2016 and an 18% increase from the third quarter of 2015, pro forma for asset sales. |
| • | The XRL drilling program resumed in September and 6 wells have spud, including 3 wells that spud in October. No wells were completed during the quarter. Current plans are to drill up to 15 wells and complete 5 of the wells during the remainder of the year. |
| • | Efficiencies have been maintained since resuming the program as drilling times averaged approximately 8 days per well (spud to rig release) for the most recent wells. |
| • | Drilling and completion costs for the most recent drilling and spacing unit ("DSU") are expected to average $4.25 million per well, which incorporates an increased proppant loading of approximately 1,350 pounds of sand per lateral foot. The Company continues to pursue additional capital efficiency measures designed to improve drilling and completion costs and enhance economic returns. |
| • | The following provides a synopsis of the current DSU activity: |
| ◦ | Section 5-62-22 - the DSU is located within the central area of NE Wattenberg and includes 15 XRL wells that began initial flowback in April 2016. The wells are performing consistently during initial flowback and have not yet reached an initial peak rate. |
| ◦ | Section 4-62-9 - the DSU is located within the southern area of NE Wattenberg and includes 8 XRL wells that began initial flowback in June 2016. The wells are performing consistently during initial flowback and have not yet reached an initial peak rate. |
| ◦ | Section 4-62-20 - the DSU is located within the southern area of NE Wattenberg and includes 5 XRL wells that recently finished drilling to the Niobrara "B", Niobrara "C" and Codell horizons. It is expected that the wells will be completed in late 2016 and placed on initial flowback in early 2017. The wells will incorporate increased proppant of approximately 1,350 pounds of sand per lateral foot. |
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| ◦ | Section 5-62-27 - the DSU is located within the central area of NE Wattenberg and includes 9 XRL wells that will target the Niobrara "B" and Niobrara "C" horizons. Drilling operations have commenced and it is expected that the wells will be completed during the first quarter of 2017 and placed on initial flowback during the second quarter of 2017. This DSU will include a combination of wells that incorporates enhanced proppant loading and monobores. |
| • | DJ Basin oil price differentials averaged $2.21 per barrel during the third quarter of 2016, a 54% improvement from the second quarter of 2016 average of $4.82 per barrel and a 70% decrease from the third quarter of 2015 average of $7.43 per barrel. The Company's oil pricing continues to benefit from having no firm takeaway capacity commitments as regional infrastructure has improved. The fourth quarter of 2016 oil differential is expected to average approximately $3.00 per barrel less than WTI. |
| • | DJ Basin LOE averaged $2.45 per barrel during the third quarter of 2016, a 34% improvement from the second quarter of 2016 average of $3.74 per barrel and a 38% decrease from the third quarter of 2015 average of $3.96 per barrel. The reduction in LOE was primarily a result of an improvement in operating efficiencies. |
Uinta Oil Program
Production sales volumes averaged 2,457 Boe/d (83% oil) during the third quarter of 2016. The Company expects to have minimal activity related to the Uinta Basin for the remainder of 2016.
2016 OPERATING GUIDANCE
The Company is providing the following update to its 2016 operating guidance. See "Forward-Looking Statements" below.
| • | Capital expenditures of approximately $100 million, which was updated to reflect drilling activity associated with the XRL drilling program that resumed in September 2016. |
| ◦ | Assumes up to 15 XRL wells are spud and 5 wells are completed prior to the end of the year |
| ◦ | Anticipate being free cash flow positive as cash flows from operations are expected to exceed capital expenditures |
| • | Production of 6.0-6.2 MMBoe, with the low end of guidance increased to reflect actual production sales volumes for the first nine months of 2016. |
| • | LOE of $29-$31 million, decreased from $31-$34 million to reflect cost reductions and the sale of higher operating cost properties in the Uinta Basin. |
| ◦ | LOE per Boe is anticipated to be higher in the fourth quarter of 2016 relative to the third quarter due to greater seasonal operating costs that are typically experienced during colder months |
| • | General and administrative expenses of $30-$33 million, unchanged |
| • | Gathering, transportation and processing costs of $2-$4 million, unchanged |
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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 the hedge position as of November 3, 2016:
| Oil (WTI) | Natural Gas (NWPL) | |||||||||||
| Period | Volume Bbls/d | Price $/Bbl | Volume MMBtu/d | Price $/MMBtu | ||||||||
| 4Q16 | 7,750 | 72.57 | 5,000 | 4.10 | ||||||||
| 1Q17 | 5,750 | 59.17 | 10,000 | 2.96 | ||||||||
| 2Q17 | 5,875 | 59.04 | 10,000 | 2.96 | ||||||||
| 3Q17 | 3,375 | 63.14 | 10,000 | 2.96 | ||||||||
| 4Q17 | 3,375 | 63.14 | 10,000 | 2.96 | ||||||||
| 1Q18 | 750 | 52.58 | ||||||||||
| 2Q18 | 750 | 52.58 | ||||||||||
| 3Q18 | 500 | 53.88 | ||||||||||
| 4Q18 | 500 | 53.88 | ||||||||||
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 4, 2016, to discuss the results and management's outlook for the future. 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 1407243. The webcast will remain on the Company's website for approximately 7 days and a replay of the call will be available through November 11, 2016 at (855) 859-2056 ((404) 537-3406 international) with passcode 1407243.
DISCLOSURE STATEMENTS
Forward-Looking Statements
All statements in this press release, other than statements of historical fact, are 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, costs, projects and opportunities.
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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. Please refer to the Company's Annual Report on Form 10-K for the year ended December 31, 2015 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.
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BILL BARRETT CORPORATION
Selected Operating Highlights
(Unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Production Data: | |||||||||||||||
| Oil (MBbls) | 1,016 | 1,066 | 2,925 | 3,311 | |||||||||||
| Natural gas (MMcf) | 1,734 | 2,214 | 5,298 | 5,772 | |||||||||||
| NGLs (MBbls) | 261 | 264 | 732 | 635 | |||||||||||
| Combined volumes (MBoe) | 1,566 | 1,699 | 4,540 | 4,908 | |||||||||||
| Daily combined volumes (Boe/d) | 17,022 | 18,467 | 16,569 | 17,978 | |||||||||||
| Average Sales Prices (before the effects of realized hedges): | |||||||||||||||
| Oil (per Bbl) | $ | 41.92 | $ | 38.71 | $ | 36.88 | $ | 41.54 | |||||||
| Natural gas (per Mcf) | 2.29 | 2.08 | 1.81 | 2.31 | |||||||||||
| NGLs (per Bbl) | 13.65 | 11.17 | 12.05 | 12.24 | |||||||||||
| Combined (per Boe) | 32.02 | 28.73 | 27.82 | 32.33 | |||||||||||
| Average Realized Sales Prices (after the effects of realized hedges): | |||||||||||||||
| Oil (per Bbl) | $ | 61.30 | $ | 79.15 | $ | 62.74 | $ | 77.93 | |||||||
| Natural gas (per Mcf) | 2.71 | 3.36 | 2.34 | 3.76 | |||||||||||
| NGLs (per Bbl) | 13.65 | 11.17 | 12.05 | 12.24 | |||||||||||
| Combined (per Boe) | 45.06 | 55.77 | 45.09 | 58.58 | |||||||||||
| Average Costs (per Boe): | |||||||||||||||
| Lease operating expenses | $ | 3.06 | $ | 5.67 | $ | 4.87 | $ | 7.10 | |||||||
| Gathering, transportation and processing expense | 0.30 | 0.40 | 0.41 | 0.52 | |||||||||||
| Production tax expenses | 2.45 | 2.16 | 1.55 | 2.04 | |||||||||||
| Depreciation, depletion and amortization | 27.51 | 32.22 | 27.64 | 32.53 | |||||||||||
General and administrative expense (1) | 5.86 | 6.49 | 6.95 | 7.95 | |||||||||||
| (1) | Includes long-term cash and equity incentive compensation of $1.37 per Boe and $1.18 per Boe for the three months ended September 30, 2016 and 2015, respectively, and $1.91 per Boe and $1.59 per Boe for the nine months ended September 30, 2016 and 2015, respectively. |
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BILL BARRETT CORPORATION
Consolidated Condensed Balance Sheets
(Unaudited)
| As of September 30, | As of December 31, | ||||||
| 2016 | 2015 | ||||||
| (in thousands) | |||||||
| Assets: | |||||||
| Cash and cash equivalents | $ | 174,263 | $ | 128,836 | |||
Other current assets (1) | 62,597 | 145,481 | |||||
| Property and equipment, net | 1,081,066 | 1,170,684 | |||||
Other noncurrent assets (1) | 17,627 | 61,519 | |||||
| Total assets | $ | 1,335,553 | $ | 1,506,520 | |||
| Liabilities and Stockholders' Equity: | |||||||
| Current liabilities | $ | 99,782 | $ | 145,231 | |||
| Long-term debt, net of debt issuance costs | 711,544 | 794,652 | |||||
Other long-term liabilities (1) | 15,048 | 17,221 | |||||
| Stockholders' equity | 509,179 | 549,416 | |||||
| Total liabilities and stockholders' equity | $ | 1,335,553 | $ | 1,506,520 | |||
| (1) | At September 30, 2016, the estimated fair value of all of the Company's commodity derivative instruments was a net asset of $33.8 million, comprised of $30.7 million of current assets, $3.3 million of non-current assets and $0.3 million of non-current liabilities. This amount will fluctuate based on estimated future commodity prices and the current hedge position. |
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BILL BARRETT CORPORATION
Consolidated Statements of Operations
(Unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| (in thousands, except per share amounts) | |||||||||||||||
| Operating and Other Revenues: | |||||||||||||||
| Oil, gas and NGLs | $ | 50,133 | $ | 48,799 | $ | 126,279 | $ | 158,667 | |||||||
| Other | 348 | 880 | 920 | 2,664 | |||||||||||
| Total operating and other revenues | 50,481 | 49,679 | 127,199 | 161,331 | |||||||||||
| Operating Expenses: | |||||||||||||||
| Lease operating | 4,795 | 9,638 | 22,101 | 34,834 | |||||||||||
| Gathering, transportation and processing | 472 | 684 | 1,871 | 2,559 | |||||||||||
| Production tax | 3,832 | 3,670 | 7,037 | 10,020 | |||||||||||
| Exploration | 16 | 20 | 64 | 145 | |||||||||||
| Impairment, dry hole costs and abandonment | 974 | 572,651 | 1,766 | 574,996 | |||||||||||
| (Gain) Loss on divestitures | 1,914 | (77 | ) | 1,206 | (759 | ) | |||||||||
| Depreciation, depletion and amortization | 43,083 | 54,738 | 125,491 | 159,666 | |||||||||||
| Unused commitments | 4,567 | 4,388 | 13,703 | 13,163 | |||||||||||
General and administrative (1) | 9,178 | 11,025 | 31,535 | 39,026 | |||||||||||
| Total operating expenses | 68,831 | 656,737 | 204,774 | 833,650 | |||||||||||
| Operating Income (Loss) | (18,350 | ) | (607,058 | ) | (77,575 | ) | (672,319 | ) | |||||||
| Other Income and Expense: | |||||||||||||||
| Interest and other income | 72 | 100 | 166 | 519 | |||||||||||
| Interest expense | (13,991 | ) | (15,754 | ) | (45,160 | ) | (49,574 | ) | |||||||
Commodity derivative gain (loss) (2) | 6,054 | 69,133 | (7,258 | ) | 75,914 | ||||||||||
| Gain (loss) on extinguishment of debt | 29 | — | 8,726 | 1,749 | |||||||||||
| Total other income and expense | (7,836 | ) | 53,479 | (43,526 | ) | 28,608 | |||||||||
| Income (Loss) before Income Taxes | (26,186 | ) | (553,579 | ) | (121,101 | ) | (643,711 | ) | |||||||
| (Provision for) Benefit from Income Taxes | — | 143,265 | — | 177,085 | |||||||||||
| Net Income (Loss) | $ | (26,186 | ) | $ | (410,314 | ) | $ | (121,101 | ) | $ | (466,626 | ) | |||
| Net Income (Loss) per Common Share | |||||||||||||||
| Basic | $ | (0.44 | ) | $ | (8.49 | ) | $ | (2.28 | ) | $ | (9.67 | ) | |||
| Diluted | $ | (0.44 | ) | $ | (8.49 | ) | $ | (2.28 | ) | $ | (9.67 | ) | |||
| Weighted Average Common Shares Outstanding | |||||||||||||||
| Basic | 58,852 | 48,340 | 53,082 | 48,280 | |||||||||||
| Diluted | 58,852 | 48,340 | 53,082 | 48,280 | |||||||||||
| (1) | Includes long-term cash and equity incentive compensation of $2.1 million and $2.0 million for the three months ended September 30, 2016 and 2015, respectively, and $8.7 million and $7.8 million for the nine months ended September 30, 2016 and 2015, respectively. |
| (2) | 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: |
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| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| (in thousands) | |||||||||||||||
| Included in commodity derivative gain (loss): | |||||||||||||||
Realized gain (loss) on derivatives (1) | $ | 20,412 | $ | 45,936 | $ | 78,417 | $ | 128,834 | |||||||
Prior year unrealized (gain) loss transferred to realized (gain) loss (1) | (21,706 | ) | (34,374 | ) | (79,055 | ) | (113,342 | ) | |||||||
Unrealized gain (loss) on derivatives (1) | 7,348 | 57,571 | (6,620 | ) | 60,422 | ||||||||||
| Total commodity derivative gain (loss) | $ | 6,054 | $ | 69,133 | $ | (7,258 | ) | $ | 75,914 | ||||||
| (1) | Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of the Company's hedge position. The Company also believes that this disclosure allows for a more accurate comparison to its peers. |
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BILL BARRETT CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| (in thousands) | |||||||||||||||
| Operating Activities: | |||||||||||||||
| Net income (loss) | $ | (26,186 | ) | $ | (410,314 | ) | $ | (121,101 | ) | $ | (466,626 | ) | |||
| Adjustments to reconcile to net cash provided by operations: | |||||||||||||||
| Depreciation, depletion and amortization | 43,083 | 54,738 | 125,491 | 159,666 | |||||||||||
| Impairment, dry hole costs and abandonment expense | 974 | 572,651 | 1,766 | 574,996 | |||||||||||
| Unrealized derivative (gain) loss | 14,358 | (23,197 | ) | 85,675 | 52,920 | ||||||||||
| Deferred income tax benefit | — | (142,977 | ) | — | (176,797 | ) | |||||||||
| Incentive compensation and other non-cash charges | 1,777 | 2,068 | 7,208 | 7,281 | |||||||||||
| Amortization of deferred financing costs | 573 | 633 | 2,075 | 3,983 | |||||||||||
| (Gain) loss on sale of properties | 1,914 | (77 | ) | 1,206 | (759 | ) | |||||||||
| (Gain) loss on extinguishment of debt | (29 | ) | — | (8,726 | ) | (1,749 | ) | ||||||||
| Change in operating assets and liabilities: | |||||||||||||||
| Accounts receivable | 4,008 | 3,285 | 13,552 | 20,394 | |||||||||||
| Prepayments and other assets | (66 | ) | 878 | (968 | ) | (261 | ) | ||||||||
| Accounts payable, accrued and other liabilities | 22,846 | 18,025 | 18,903 | 4,347 | |||||||||||
| Amounts payable to oil and gas property owners | 493 | (4,161 | ) | (2,894 | ) | (850 | ) | ||||||||
| Production taxes payable | 3,683 | 3,208 | (5,980 | ) | (10,644 | ) | |||||||||
| Net cash provided by (used in) operating activities | $ | 67,428 | $ | 74,760 | $ | 116,207 | $ | 165,901 | |||||||
| Investing Activities: | |||||||||||||||
| Additions to oil and gas properties, including acquisitions | (7,024 | ) | (61,936 | ) | (93,704 | ) | (256,059 | ) | |||||||
| Additions of furniture, equipment and other | (193 | ) | (158 | ) | (1,184 | ) | (1,036 | ) | |||||||
| Proceeds from sale of properties and other investing activities | 26,796 | 99 | 25,571 | 66,617 | |||||||||||
| 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 | $ | 19,579 | $ | (16,995 | ) | $ | (69,317 | ) | $ | (210,361 | ) | ||||
| Financing Activities: | |||||||||||||||
| Principal payments on debt | (111 | ) | (107 | ) | (329 | ) | (25,083 | ) | |||||||
| Deferred financing costs and other | (56 | ) | (704 | ) | (1,134 | ) | (3,525 | ) | |||||||
| Net cash provided by (used in) financing activities | $ | (167 | ) | $ | (811 | ) | $ | (1,463 | ) | $ | (28,608 | ) | |||
| Increase (Decrease) in Cash and Cash Equivalents | 86,840 | 56,954 | 45,427 | (73,068 | ) | ||||||||||
| Beginning Cash and Cash Equivalents | 87,423 | 35,882 | 128,836 | 165,904 | |||||||||||
| Ending Cash and Cash Equivalents | $ | 174,263 | $ | 92,836 | $ | 174,263 | $ | 92,836 | |||||||
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BILL BARRETT CORPORATION
Reconciliation of Discretionary Cash Flow, Adjusted Net Income (Loss) and EBITDAX
(Unaudited)
Discretionary Cash Flow Reconciliation
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| (in thousands) | |||||||||||||||
| Net Cash Provided by (Used in) Operating Activities | $ | 67,428 | $ | 74,760 | $ | 116,207 | $ | 165,901 | |||||||
| Adjustments to reconcile to discretionary cash flow: | |||||||||||||||
| Exploration expense | 16 | 20 | 64 | 145 | |||||||||||
| Changes in working capital | (30,964 | ) | (21,235 | ) | (22,613 | ) | (12,986 | ) | |||||||
| Discretionary Cash Flow | $ | 36,480 | $ | 53,545 | $ | 93,658 | $ | 153,060 | |||||||
Adjusted Net Income (Loss) Reconciliation
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| (in thousands, except per share amounts) | |||||||||||||||
| Net Income (Loss) | $ | (26,186 | ) | $ | (410,314 | ) | $ | (121,101 | ) | $ | (466,626 | ) | |||
| Provision for (Benefit from) income taxes | — | (143,265 | ) | — | (177,085 | ) | |||||||||
| Income (Loss) before income taxes | (26,186 | ) | (553,579 | ) | (121,101 | ) | (643,711 | ) | |||||||
| Adjustments to net income (loss): | |||||||||||||||
| Unrealized derivative (gain) loss | 14,358 | (23,197 | ) | 85,675 | 52,920 | ||||||||||
| Impairment expense | — | 571,863 | 183 | 572,366 | |||||||||||
| (Gain) loss on sale of properties | 1,914 | (77 | ) | 1,206 | (759 | ) | |||||||||
| (Gain) loss on extinguishment of debt | (29 | ) | — | (8,726 | ) | (1,749 | ) | ||||||||
| One-time item: | |||||||||||||||
| West Tavaputs NGL processing true-up | — | — | — | (1,005 | ) | ||||||||||
| Expenses relating to amending credit facility | — | — | — | 1,617 | |||||||||||
| Adjusted Income (Loss) before income taxes | (9,943 | ) | (4,990 | ) | (42,763 | ) | (20,321 | ) | |||||||
Adjusted (provision for) benefit from income taxes (1) | 3,791 | 632 | 16,164 | 2,536 | |||||||||||
| Adjusted Net Income (Loss) | $ | (6,152 | ) | $ | (4,358 | ) | $ | (26,599 | ) | $ | (17,785 | ) | |||
| Per share, diluted | $ | (0.10 | ) | $ | (0.09 | ) | $ | (0.50 | ) | $ | (0.37 | ) | |||
| (1) | Adjusted (provision for) benefit from income taxes is calculated using the Company's current effective tax rate prior to applying the valuation allowance against deferred tax assets. |
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EBITDAX Reconciliation
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| (in thousands) | |||||||||||||||
| Net Income (Loss) | $ | (26,186 | ) | $ | (410,314 | ) | $ | (121,101 | ) | $ | (466,626 | ) | |||
| Adjustments to reconcile to EBITDAX: | |||||||||||||||
| Depreciation, depletion and amortization | 43,083 | 54,738 | 125,491 | 159,666 | |||||||||||
| Impairment, dry hole and abandonment expense | 974 | 572,651 | 1,766 | 574,996 | |||||||||||
| Exploration expense | 16 | 20 | 64 | 145 | |||||||||||
| Unrealized derivative (gain) loss | 14,358 | (23,197 | ) | 85,675 | 52,920 | ||||||||||
| Incentive compensation and other non-cash charges | 1,777 | 2,068 | 7,208 | 7,281 | |||||||||||
| (Gain) loss on sale of properties | 1,914 | (77 | ) | 1,206 | (759 | ) | |||||||||
| (Gain) loss on extinguishment of debt | (29 | ) | — | (8,726 | ) | (1,749 | ) | ||||||||
| Interest and other income | (72 | ) | (100 | ) | (166 | ) | (519 | ) | |||||||
| Interest expense | 13,991 | 15,754 | 45,160 | 49,574 | |||||||||||
| Provision for (Benefit from) Income Taxes | — | (143,265 | ) | — | (177,085 | ) | |||||||||
| EBITDAX | $ | 49,826 | $ | 68,278 | $ | 136,577 | $ | 197,844 | |||||||
Discretionary cash flow, adjusted net income (loss) and EBITDAX 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 certain 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. The definition of these measures may vary among companies, and, therefore, the amounts presented may not be comparable to similarly titled measures of other companies.
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