Attached files
| file | filename |
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| 8-K - 8-K - BILL BARRETT CORP | bbg-12312016x8kxearningsre.htm |
 | Press Release | |
For immediate release
Company contact: Larry C. Busnardo, Senior Director, Investor Relations, 303-312-8514
Bill Barrett Corporation Reports Fourth Quarter and Year-End 2016 Financial and Operating Results, Provides 2017 Operating Guidance and Establishes
Initial 2018 Production Growth Outlook of 30%-50%
• | Production sales volumes of 6.1 million barrels of oil equivalent ("MMBoe") in 2016 were at the mid-point of guidance range; represents pro forma growth of 11% over 2015 |
• | Capital expenditures of $98 million in 2016 were below guidance range |
• | Lease operating expense ("LOE") of $4.58 per Boe in 2016, represents 29% improvement compared to 2015; Denver-Julesburg ("DJ") Basin LOE of $3.41 per Boe in 2016, represents 27% improvement compared to 2015 |
• | DJ Basin oil price differential averaged $3.45 per barrel in 2016; represents 58% improvement compared to 2015 |
• | XRL drilling days have averaged 7.4 days; represents a 33% improvement over 2015 |
• | Recently closed bolt-on transactions for 13,800 net acres in the DJ Basin |
• | Entered 2017 with $276 million of cash and an undrawn credit facility of $300 million |
• | 2017 operating plan has projected capital expenditures of $255-$285 million and production sales volumes of 6.0-6.5 MMBoe; representing growth of 7% at the mid-point pro forma for asset sales |
• | 2018 production sales volumes anticipated to be 30%-50% greater than 2017 |
DENVER - March 2, 2017 - Bill Barrett Corporation (the "Company") (NYSE: BBG) today reported fourth quarter and full year 2016 financial and operating results, provided 2017 operating guidance and establishes initial 2018 production growth outlook.
For the fourth quarter of 2016, the Company reported a net loss of $49 million, or $0.79 per diluted share. Adjusted net income (non-GAAP) for the fourth quarter of 2016 was a net loss of $11 million, or $0.18 per diluted share. EBITDAX for the fourth quarter of 2016 was $46 million. For 2016, the Company reported a net loss of $170 million, or $3.08 per diluted share. Adjusted net income (non-GAAP) for 2016 was a net loss of $38 million, or $0.68 per diluted share. EBITDAX for 2016 was $182 million. 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.
Chief Executive Officer and President Scot Woodall commented, "Despite a challenging year of lower oil prices, we did an excellent job of managing through the downturn and executing on our financial and operational goals. Focusing on the items within our control allowed us to report solid results for 2016, with the key drivers being production above our initial guidance expectations, capital spending coming in lower than anticipated, and LOE and G&A that were both significantly lower. We also meaningfully improved our DJ Basin oil price differentials, which helped us achieve best in class operating margins relative to our peers."
"Based on current well cost assumptions, our XRL drilling program generates attractive economic returns in the current commodity price environment. Accordingly, we are adding a second drilling rig to accelerate development and position us for increased production growth and stronger cash flows in the future. We are incorporating enhanced drilling and completion concepts that we believe will translate into improved well performance and recovery going forward. Our priority for this year is to maintain flexibility with respect to our balance sheet as we entered 2017 with $276 million of cash, an undrawn credit facility, and a strong underlying hedge position."
Mr. Woodall continued, "We plan to efficiently allocate capital to our asset portfolio, while managing our liquidity and financial flexibility. Our 2017 capital budget of $255-$285 million incorporates the addition of a drilling rig during the second quarter and will be funded with operating cash flow and cash on hand and we will maintain an undrawn credit facility. This will result in annual production growth of approximately 7% at the mid-point, pro forma for asset divestitures. The increased activity translates into very strong production growth for 2018 that is anticipated to be 30%-50% higher than 2017, with a greater increase in oil volumes."
OPERATING AND FINANCIAL RESULTS
Proved Reserves
Total estimated proved reserves at year-end 2016 were 54.9 MMBoe compared to 83.7 MMBoe at year-end 2015. Estimated proved reserves were 57% oil, 23% natural gas and 20% natural gas liquids (“NGLs”) and were 66% developed compared to 48% developed at year-end 2015. The decrease in estimated proved reserves compared to year-end 2015 is primarily the result of negative commodity price-related and other revisions totaling 30.4 MMBoe, offset in part by extensions and discoveries of 9.7 MMBoe. The Company elected to take a conservative approach to proved undeveloped ("PUD") reserve bookings based on the reduced development activity level that was employed during 2016. Revisions include approximately 24.3 MMBoe that were removed from the PUD reserves category as they are not included in near-term development plans. Of the 24.3 MMBoe revision, 18.2 MMBoe in the DJ Basin was removed because they would "age out" according to the SEC's five-year development window, which is based on when the PUD was added. Other than the timing of development, these locations technically meet the SEC PUD definition and could be added if the Company's future development plan were to be accelerated. Additionally, 6.1 MMBoe of Uinta Oil Program ("UOP") reserves were removed due to the Company electing to not develop these locations in the current business plan. Had these locations not been removed, the Company and its third-party engineers estimate that year-end 2016 proved reserves would have increased 8% compared to 2015, pro forma for asset sales. It is anticipated that with a more active development program than was employed during 2016, the Company will add back additional PUD locations during 2017.
Changes in Proved Reserves (MMBoe) | ||
Proved reserves as of December 31, 2015 | 83.7 | |
Extensions and discoveries | 9.7 | |
Production | (6.1 | ) |
Sale of properties | (2.0 | ) |
Pricing revisions and other | (30.4 | ) |
Proved reserves as of December 31, 2016 | 54.9 | |
2016 Production and Financial Results
Oil, natural gas and natural gas liquids production totaled 6.1 MMBoe for 2016 and was at the mid-point of the Company’s guidance range of 6.0-6.2 MMBoe. Removing volumes associated with completed asset sales, production sales volumes totaled 5.8 MMBoe for 2016 and were approximately 11% higher compared to 2015.
Production sales volumes for the fourth quarter of 2016 totaled 1.6 MMBoe, an 8% decrease from the fourth quarter of 2015. Lower volumes were primarily the result of non-core asset divestitures completed during 2016 and the Company's decision to curtail drilling for a portion of 2016 in response to a low commodity price environment, which resulted in no new wells being placed on production
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during the second half of 2016. Adjusting for production sales volumes associated with asset sales, fourth quarter of 2016 production sales volumes were approximately 8% higher compared to the fourth quarter of 2015.
Production sales volumes for the fourth quarter of 2016 were weighted 62% oil, 20% natural gas and 18% NGLs. Fourth quarter sales volumes had a slightly higher natural gas and NGL component than previous quarters as a result of no new XRL wells being placed on production during the second half of 2016. This is primarily due to XRL wells having a higher percentage of oil production at the beginning of the production cycle.
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||
Production Data: | |||||||||||
Oil (MBbls) | 960 | 1,090 | 3,885 | 4,401 | |||||||
Natural gas (MMcf) | 1,866 | 1,986 | 7,170 | 7,764 | |||||||
NGLs (MBbls) | 279 | 264 | 1,010 | 898 | |||||||
Combined volumes (MBoe) | 1,550 | 1,685 | 6,090 | 6,593 | |||||||
Daily combined volumes (Boe/d) | 16,848 | 18,315 | 16,639 | 18,063 | |||||||
Pre-hedge commodity prices for 2016 were lower compared to full-year 2015 as oil and natural gas prices declined significantly during early 2016. West Texas Intermediate ("WTI") oil prices averaged $43.32 per barrel in 2016 compared to $48.80 per barrel in 2015. NYMEX natural gas prices averaged $2.45 per MMBtu in 2016 as compared to $2.67 per MMBtu in 2015.
For the fourth quarter of 2016, WTI oil prices averaged $49.29 per barrel, NWPL natural gas prices averaged $2.72 per MMBtu and NYMEX natural gas prices averaged $2.99 per MMBtu. Fourth quarter of 2016 commodity price differentials to benchmark pricing were: oil less $4.53 price per barrel versus WTI; and natural gas less $0.25 per Mcf compared to NWPL. The DJ Basin oil price differential averaged $3.67 per barrel as the Company benefits from having no long-term oil marketing agreements. The NGL price averaged approximately 33% of the WTI price per barrel.
For the fourth quarter of 2016, the Company had derivative commodity swaps in place for 7,750 barrels of oil per day tied to WTI pricing at $72.57 per barrel, 5,000 MMBtu of natural gas per day tied to NWPL regional pricing at $4.10 per MMBtu and no hedges in place for NGLs.
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Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
Average Sales Prices (before the effects of realized hedges): | |||||||||||||||
Oil (per Bbl) | $ | 44.76 | $ | 35.57 | $ | 38.83 | $ | 40.06 | |||||||
Natural gas (per Mcf) | 2.47 | 1.98 | 1.98 | 2.23 | |||||||||||
NGLs (per Bbl) | 16.04 | 11.98 | 13.15 | 12.16 | |||||||||||
Combined (per Boe) | 33.57 | 27.21 | 29.28 | 31.02 | |||||||||||
Average Realized Sales Prices (after the effects of realized hedges): | |||||||||||||||
Oil (per Bbl) | $ | 62.03 | $ | 78.98 | $ | 62.56 | $ | 78.19 | |||||||
Natural gas (per Mcf) | 2.80 | 3.72 | 2.46 | 3.75 | |||||||||||
NGLs (per Bbl) | 16.04 | 11.98 | 13.15 | 12.16 | |||||||||||
Combined (per Boe) | 44.65 | 57.36 | 44.98 | 58.27 | |||||||||||
Cash operating costs (LOE, gathering, transportation and processing costs, and production tax expense) totaled $6.37 per Boe in the fourth quarter of 2016 as compared to $6.54 per Boe in the fourth quarter of 2015.
LOE was $3.73 per Boe in the fourth quarter of 2016 compared to $3.06 per Boe in the third quarter of 2016 and $4.70 per Boe in the fourth quarter of 2015. The sequential increase in LOE was anticipated due to greater seasonal operating costs that are typically experienced during colder months, while the year-over-year improvement was primarily a result of improved operational efficiencies and lease operating cost reductions in both the DJ Basin and the Uinta Oil Program ("UOP").
DJ Basin LOE improved to $2.96 per Boe in the fourth quarter of 2016 compared to $3.25 per Boe in the fourth quarter of 2015, and was $3.41 per Boe in 2016 compared to $4.64 per Boe in 2015.
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
Average Costs (per Boe): | |||||||||||||||
Lease operating expenses | $ | 3.73 | $ | 4.70 | $ | 4.58 | $ | 6.48 | |||||||
Gathering, transportation and processing expense | 0.32 | 0.55 | 0.39 | 0.53 | |||||||||||
Production tax expenses | 2.32 | 1.29 | 1.75 | 1.85 | |||||||||||
Depreciation, depletion and amortization | 29.76 | 27.06 | 28.18 | 31.14 | |||||||||||
General and administrative expense | 6.86 | 8.82 | 6.92 | 8.17 | |||||||||||
The following table summarizes certain operating and financial results for the fourth quarter of 2016 and 2015 and the years ended 2016 and 2015:
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Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
Combined production sales volumes (MBoe) | 1,550 | 1,685 | 6,090 | 6,593 | |||||||||||
Net cash provided by (used in) operating activities ($ millions) | $ | 5.5 | $ | 27.8 | $ | 121.7 | $ | 193.7 | |||||||
Discretionary cash flow ($ millions) (1) | $ | 32.4 | $ | 53.3 | $ | 126.1 | $ | 206.3 | |||||||
Net income (loss) ($ millions) | $ | (49.3 | ) | $ | (21.1 | ) | $ | (170.4 | ) | $ | (487.8 | ) | |||
Per share, basic | $ | (0.79 | ) | $ | (0.45 | ) | $ | (3.08 | ) | $ | (10.10 | ) | |||
Per share, diluted | $ | (0.79 | ) | $ | (0.45 | ) | $ | (3.08 | ) | $ | (10.10 | ) | |||
Adjusted net income (loss) ($ millions) (1) | $ | (11.2 | ) | $ | 3.4 | $ | (37.8 | ) | $ | (9.4 | ) | ||||
Per share, basic | $ | (0.18 | ) | $ | 0.07 | $ | (0.68 | ) | $ | (0.20 | ) | ||||
Per share, diluted | $ | (0.18 | ) | $ | 0.07 | $ | (0.68 | ) | $ | (0.20 | ) | ||||
Weighted average shares outstanding, basic (in thousands) | 62,241 | 48,373 | 55,384 | 48,303 | |||||||||||
Weighted average shares outstanding, diluted (in thousands) | 62,241 | 48,373 | 55,384 | 48,303 | |||||||||||
EBITDAX ($ millions) (1) | $ | 45.8 | $ | 68.3 | $ | 182.4 | $ | 266.2 | |||||||
(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. |
At December 31, 2016, the Company’s $300 million revolving credit facility had zero drawn and $274.0 million in available capacity, after taking into account a $26.0 million letter of credit. The principal balance of long-term debt was $718.2 million and cash and cash equivalents were $275.8 million, resulting in net debt (principal balance of debt outstanding less the cash and cash equivalents balance) of $442.4 million. Cash and cash equivalents include approximately $110 million of net proceeds from the common stock offering completed in December 2016.
DJ Basin Acquisition
The Company recently closed a transaction to acquire approximately 13,000 net acres in the DJ Basin for $11.8 million. The acquired acreage extends southwest of the Company's current NE Wattenberg acreage position, including its six 1,280 acre “south of the river” DSUs currently under development. It is estimated that the acquired acreage contains approximately 80 operated XRL drilling locations and additional ownership in approximately 20 gross XRL locations, which are all prospective for the Niobrara "B", Niobrara "C" and Codell horizons.
In addition, the Company was the successful bidder on five lease parcels at the November 2016, Colorado state lease sale, comprising 830 acres, for bonus bids totaling approximately $1.5 million.
Capital Expenditures
Capital expenditures of $98.3 million for 2016 were 66% lower than 2015 and included drilling 15 net operated XRL wells in the DJ Basin. Capital expenditures included $86.3 million for drilling and completion operations, $5.6 million for leaseholds to expand development programs, and $6.4 million for infrastructure and corporate purposes.
Capital expenditures for the fourth quarter of 2016 totaled $28.8 million and included drilling 11 net operated XRL wells in the DJ Basin. Capital expenditures included $25.5 million for drilling and completion operations, $3.0 million for leaseholds, and $0.3 million for infrastructure and corporate assets.
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Three Months Ended December 31, 2016 | Twelve Months Ended December 31, 2016 | ||||||||||||||||
Average Net Daily Production (Boe/d) | Operated Wells Drilled (Net) | Capital Expenditures ($ millions) | Average Net Daily Production (Boe/d) | Operated Wells Drilled (Net) | Capital Expenditures ($ millions) | ||||||||||||
Basin: | |||||||||||||||||
Denver-Julesburg | 14,826 | 11 | $ | 28.5 | 13,809 | 15 | $ | 95.5 | |||||||||
Uinta | 2,000 | — | 0.3 | 2,792 | — | 1.4 | |||||||||||
Other | 22 | — | — | 38 | — | 1.4 | |||||||||||
Total | 16,848 | 11 | $ | 28.8 | 16,639 | 15 | $ | 98.3 | |||||||||
OPERATIONAL HIGHLIGHTS
DJ Basin
In the fourth quarter of 2016, the Company produced an average of 14,826 Boe/d, which was a 15% increase from the fourth quarter of 2015 average of 12,864 Boe/d, excluding volumes associated with asset sales. DJ Basin oil volumes averaged 8,723 Bbls/d, which was an increase of 13% from the fourth quarter of 2015, excluding volumes associated with asset sales.
The Company resumed drilling operations during the third quarter of 2016 with the initial DSU being recently placed on initial flowback. Accordingly, the Company did not have any new wells on production during the fourth quarter of 2016. The Company is currently operating one drilling rig in NE Wattenberg and plans to add a rig to accelerate development during the second quarter of 2017.
The following provides a synopsis of the current DSU activity:
• | 4-62-20 - the DSU is located within the southern area of NE Wattenberg and includes 4 XRL wells. The wells incorporated increased proppant of up to 1,350 pounds of sand per lateral foot. The wells were placed on initial flowback in February 2017 and are connected to pipeline infrastructure that the Company constructed beneath the South Platte River in 2016. The infrastructure allows for the future development of the Company's acreage located south of the river. |
• | 5-62-27 - the DSU is located within the central area of NE Wattenberg and includes 9 XRL wells. Completion operations have commenced and it is expected that the wells will be placed on initial flowback during the second quarter of 2017. This DSU includes a combination of wells that incorporated enhanced proppant loading of approximately 1,500 pounds of sand per lateral foot and monobores. |
• | 6-62-10 - the Company has drilled a DSU which is located within the northern area of NE Wattenberg that includes 4 XRL wells. Based on lease configuration, an additional 10 mid-reach lateral wells are being drilled to develop the DSU. It is expected that the wells will be completed in second quarter of 2017 and placed on initial flowback during the third quarter of 2017. The wells will incorporate enhanced proppant loading of up to 1,500 pounds of sand per lateral foot and additional frac stages. |
• | Since resuming drilling operations in September 2016, XRL well drilling days to rig release have averaged approximately 7.4 days per well, including a best-in-class well that was drilled in approximately 5.6 days. This represents a 33% improvement from the average of 2015. |
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• | Drilling and completion costs for the most recent XRL wells have averaged approximately $4.25 million per well, which includes the cost of incorporating higher proppant concentrations. |
Uinta Oil Program
The Company produced an average of 2,000 Boe/d for the fourth quarter of 2016. There was no new drilling and completion activity in the UOP during the fourth quarter of 2016. Future operations consist of several planned recompletions during the second quarter of 2017.
2017 OPERATING GUIDANCE
The 2017 capital program is designed to maintain financial and operational flexibility, while accelerating development in NE Wattenberg. Accordingly, an additional drilling rig will be added during the second quarter of 2017. The capital program will primarily be focused on XRL well development in the DJ Basin with expenditures in the UOP consisting of planned well recompletions during the second quarter of 2017. Based on the forecasted timing of completions associated with the second drilling rig, the increased activity is expected to contribute minimally to 2017 production, but is expected to have a greater impact in 2018. It is expected that 2017 production levels will be approximately 7% higher than 2016 production at the mid-point of guidance, pro forma for previously completed asset sales, with 2018 corporate production anticipated to grow 30%-50%.
The Company enters 2017 well positioned having ample liquidity, a strong underlying hedge position with 60%-65% of its 2017 oil production currently hedged at an average of $58.47 per barrel of oil, nominal drilling commitments and no long-term drilling, completion or oil marketing contracts. As such, the Company retains the operational and financial flexibility to accelerate or decelerate development activity in response to any changes in economic conditions. The capital expenditure program is expected to be funded with operating cash flow and available cash on hand. The Company also expects to exit 2017 with a positive cash position and an undrawn credit facility.
The Company is providing the following guidance for its 2017 activities. See "Forward-Looking Statements" below.
• | Capital expenditures of approximately $255-$285 million |
◦ | Assumes the addition of a second drilling rig in the second quarter. |
◦ | Approximately 70-75 gross XRL wells are expected to be drilled in the NE Wattenberg field of the DJ Basin. |
◦ | XRL well costs are expected to average approximately $4.75 million per well; reflecting enhanced completion designs and potential increases in service costs, partially offset by additional drilling efficiencies. |
◦ | First quarter of 2017 capital expenditures are expected to be approximately $60-$65 million, which includes approximately $12 million for the portion of the aforementioned DJ Basin acreage acquisition that closed in 2017. |
• | Production of 6.0-6.5 MMBoe |
◦ | Represents a production level that is approximately 7% higher at the mid-point than pro forma 2016 production sales volumes of 5.8 MMBoe, excluding assets divested in 2016. |
◦ | Production is estimated to be approximately 60-65% oil, 20% natural gas and 15-20% NGLs. |
◦ | First quarter of 2017 production is expected to approximate 1.35-1.45 MMBoe, which represents lower sequential production from the fourth quarter of 2016, in part, due to no new wells being placed on production during the fourth quarter of 2016 and the timing of wells being placed on flowback during the first quarter of 2017. |
• | Lease operating expense of $27-$30 million |
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• | Cash general and administrative expense of $30-$33 million |
• | Gathering, transportation and processing costs of $2-$3 million |
• | Unused commitment for firm natural gas transportation charges of $18-$19 million |
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.
For 2017, 6,846 barrels per day of oil is hedged at an average WTI price of $58.47 per barrel and 10,000 MMBtu/d of natural gas is hedged at an average NWPL price of $2.96 per MMBtu.
For 2018, 2,616 barrels per day of oil is hedged at an average WTI price of $55.00 per barrel and no natural gas hedges in place.
As of March 2, 2017, the Company had the following commodity hedge positions in place for 2017 and 2018:
Oil (WTI) | Natural Gas (NWPL) | |||||||||||||
Period | Volume Bbls/d | Price $/Bbl | Volume MMBtu/d | Price $/MMBtu | ||||||||||
1Q17 | 6,500 | $ | 58.20 | 10,000 | $ | 2.96 | ||||||||
2Q17 | 6,625 | 58.10 | 10,000 | 2.96 | ||||||||||
3Q17 | 7,125 | 58.77 | 10,000 | 2.96 | ||||||||||
4Q17 | 7,125 | 58.77 | 10,000 | 2.96 | ||||||||||
1Q18 | 3,750 | 54.97 | — | — | ||||||||||
2Q18 | 3,750 | 54.97 | — | — | ||||||||||
3Q18 | 1,500 | 55.06 | — | — | ||||||||||
4Q18 | 1,500 | 55.06 | — | — | ||||||||||
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 Friday, March 3, 2017, 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 60765706. The webcast will remain on the Company's website for approximately 30 days and a replay of the call will be available through Friday, March 10, 2017 at 855-859-2056 (404-537-3406 international) with passcode 60765706.
For additional information, reference the Fourth Quarter and Full-Year 2016 Results presentation that will be available on the Investor Relations page of the Company's website prior to the start of the conference call.
Investor Events
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Members of management are scheduled to participate in the following investor events:
• | March 16, 2017 - Wells Fargo Securities High Yield group meeting in Denver, CO |
• | March 27, 2017 - Scotia Howard Weil Energy Conference in New Orleans, LA |
Presentation materials for the conference will be posted to the Company's website at www.billbarrettcorp.com in the Investor Relations section.
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, 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 "2017 Operating Guidance," which contains projections for certain 2017 operational and financial metrics, and an outlook for 2018 production. Additional forward-looking statements in this release relate to, among other things, future capital expenditures, projects, rates of return, costs, operational improvements 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
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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, 2015 filed with the SEC and for the year 2016 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.
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BILL BARRETT CORPORATION
Selected Operating Highlights
(Unaudited)
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
Production Data: | |||||||||||||||
Oil (MBbls) | 960 | 1,090 | 3,885 | 4,401 | |||||||||||
Natural gas (MMcf) | 1,866 | 1,986 | 7,170 | 7,764 | |||||||||||
NGLs (MBbls) | 279 | 264 | 1,010 | 898 | |||||||||||
Combined volumes (MBoe) | 1,550 | 1,685 | 6,090 | 6,593 | |||||||||||
Daily combined volumes (Boe/d) | 16,848 | 18,315 | 16,639 | 18,063 | |||||||||||
Average Sales Prices (before the effects of realized hedges): | |||||||||||||||
Oil (per Bbl) | $ | 44.76 | $ | 35.57 | $ | 38.83 | $ | 40.06 | |||||||
Natural gas (per Mcf) | 2.47 | 1.98 | 1.98 | 2.23 | |||||||||||
NGLs (per Bbl) | 16.04 | 11.98 | 13.15 | 12.16 | |||||||||||
Combined (per Boe) | 33.57 | 27.21 | 29.28 | 31.02 | |||||||||||
Average Realized Sales Prices (after the effects of realized hedges): | |||||||||||||||
Oil (per Bbl) | $ | 62.03 | $ | 78.98 | $ | 62.56 | $ | 78.19 | |||||||
Natural gas (per Mcf) | 2.80 | 3.72 | 2.46 | 3.75 | |||||||||||
NGLs (per Bbl) | 16.04 | 11.98 | 13.15 | 12.16 | |||||||||||
Combined (per Boe) | 44.65 | 57.36 | 44.98 | 58.27 | |||||||||||
Average Costs (per Boe): | |||||||||||||||
Lease operating expenses | $ | 3.73 | $ | 4.70 | $ | 4.58 | $ | 6.48 | |||||||
Gathering, transportation and processing expense | 0.32 | 0.55 | 0.39 | 0.53 | |||||||||||
Production tax expenses | 2.32 | 1.29 | 1.75 | 1.85 | |||||||||||
Depreciation, depletion and amortization | 29.76 | 27.06 | 28.18 | 31.14 | |||||||||||
General and administrative expense (1) | 6.86 | 8.82 | 6.92 | 8.17 | |||||||||||
(1) | Includes long-term cash and equity incentive compensation of $2.12 per Boe and $1.79 per Boe for the three months ended December 31, 2016 and 2015, respectively, and $1.96 per Boe and $1.64 per Boe for the twelve months ended December 31, 2016 and 2015, respectively. |
11
BILL BARRETT CORPORATION
Consolidated Condensed Balance Sheets
(Unaudited)
As of December 31, | As of December 31, | ||||||
2016 | 2015 | ||||||
(in thousands) | |||||||
Assets: | |||||||
Cash and cash equivalents | $ | 275,841 | $ | 128,836 | |||
Other current assets (1) | 42,611 | 145,481 | |||||
Property and equipment, net | 1,062,149 | 1,170,684 | |||||
Other noncurrent assets | 4,740 | 61,519 | |||||
Total assets | $ | 1,385,341 | $ | 1,506,520 | |||
Liabilities and Stockholders' Equity: | |||||||
Current liabilities (1) | $ | 85,018 | $ | 145,231 | |||
Long-term debt, net of debt issuance costs | 711,808 | 794,652 | |||||
Other long-term liabilities (1) | 16,972 | 17,221 | |||||
Stockholders' equity | 571,543 | 549,416 | |||||
Total liabilities and stockholders' equity | $ | 1,385,341 | $ | 1,506,520 | |||
(1) | At December 31, 2016, the estimated fair value of all of the Company's commodity derivative instruments was a net asset of $3.2 million, comprised of $8.4 million of current assets, $4.3 million of current liabilities and $0.9 million of noncurrent 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 December 31, | Twelve Months Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
(in thousands, except per share amounts) | |||||||||||||||
Operating Revenues: | |||||||||||||||
Oil, gas and NGLs | $ | 52,049 | $ | 45,870 | $ | 178,328 | $ | 204,537 | |||||||
Other operating revenues | (429 | ) | 691 | 491 | 3,355 | ||||||||||
Total operating revenues | 51,620 | 46,561 | 178,819 | 207,892 | |||||||||||
Operating Expenses: | |||||||||||||||
Lease operating | 5,785 | 7,919 | 27,886 | 42,753 | |||||||||||
Gathering, transportation and processing | 494 | 923 | 2,365 | 3,482 | |||||||||||
Production tax | 3,601 | 2,177 | 10,638 | 12,197 | |||||||||||
Exploration | 19 | 8 | 83 | 153 | |||||||||||
Impairment, dry hole costs and abandonment | 2,483 | 314 | 4,249 | 575,310 | |||||||||||
(Gain) loss on sale of properties | (128 | ) | 2,504 | 1,078 | 1,745 | ||||||||||
Depreciation, depletion and amortization | 46,150 | 45,609 | 171,641 | 205,275 | |||||||||||
Unused commitments | 4,569 | 5,936 | 18,272 | 19,099 | |||||||||||
General and administrative (1) | 10,634 | 14,864 | 42,169 | 53,890 | |||||||||||
Other operating expenses, net | (316 | ) | — | (316 | ) | — | |||||||||
Total operating expenses | 73,291 | 80,254 | 278,065 | 913,904 | |||||||||||
Operating Income (Loss) | (21,671 | ) | (33,693 | ) | (99,246 | ) | (706,012 | ) | |||||||
Other Income and Expense: | |||||||||||||||
Interest and other income | 69 | 46 | 235 | 565 | |||||||||||
Interest expense | (14,213 | ) | (15,731 | ) | (59,373 | ) | (65,305 | ) | |||||||
Commodity derivative gain (loss) (2) | (13,462 | ) | 28,233 | (20,720 | ) | 104,147 | |||||||||
Gain (loss) on extinguishment of debt | — | — | 8,726 | 1,749 | |||||||||||
Total other income and expense | (27,606 | ) | 12,548 | (71,132 | ) | 41,156 | |||||||||
Income (Loss) before Income Taxes | (49,277 | ) | (21,145 | ) | (170,378 | ) | (664,856 | ) | |||||||
(Provision for) Benefit from Income Taxes | — | — | — | 177,085 | |||||||||||
Net Income (Loss) | $ | (49,277 | ) | $ | (21,145 | ) | $ | (170,378 | ) | $ | (487,771 | ) | |||
Net Income (Loss) per Common Share | |||||||||||||||
Basic | $ | (0.79 | ) | $ | (0.45 | ) | $ | (3.08 | ) | $ | (10.10 | ) | |||
Diluted | $ | (0.79 | ) | $ | (0.45 | ) | $ | (3.08 | ) | $ | (10.10 | ) | |||
Weighted Average Common Shares Outstanding | |||||||||||||||
Basic | 62,241 | 48,373 | 55,384 | 48,303 | |||||||||||
Diluted | 62,241 | 48,373 | 55,384 | 48,303 | |||||||||||
(1) | Includes long-term cash and equity incentive compensation of $3.3 million and $3.0 million for the three months ended December 31, 2016 and 2015, respectively, and $11.9 million and $10.8 million for the twelve months ended December 31, 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 December 31, | Twelve Months Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
(in thousands) | |||||||||||||||
Included in commodity derivative gain (loss): | |||||||||||||||
Realized gain (loss) on derivatives | $ | 17,181 | $ | 50,818 | $ | 95,598 | $ | 179,652 | |||||||
Reversal of prior year unrealized gain transferred to realized gain | (20,754 | ) | (46,681 | ) | (99,809 | ) | (145,226 | ) | |||||||
Unrealized gain (loss) on derivatives | (9,889 | ) | 24,096 | (16,509 | ) | 69,721 | |||||||||
Total commodity derivative gain (loss) | $ | (13,462 | ) | $ | 28,233 | $ | (20,720 | ) | $ | 104,147 | |||||
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BILL BARRETT CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
(in thousands) | |||||||||||||||
Operating Activities: | |||||||||||||||
Net income (loss) | $ | (49,277 | ) | $ | (21,145 | ) | $ | (170,378 | ) | $ | (487,771 | ) | |||
Adjustments to reconcile to net cash provided by operations: | |||||||||||||||
Depreciation, depletion and amortization | 46,150 | 45,609 | 171,641 | 205,275 | |||||||||||
Impairment, dry hole costs and abandonment expense | 2,483 | 314 | 4,249 | 575,310 | |||||||||||
Unrealized derivative (gain) loss | 30,643 | 22,585 | 116,318 | 75,505 | |||||||||||
Deferred income tax benefit | — | — | — | (176,797 | ) | ||||||||||
Incentive compensation and other non-cash charges | 1,774 | 2,759 | 8,982 | 10,040 | |||||||||||
Amortization of debt discounts and deferred financing costs | 759 | 641 | 2,834 | 4,624 | |||||||||||
(Gain) loss on sale of properties | (128 | ) | 2,504 | 1,078 | 1,745 | ||||||||||
(Gain) loss on extinguishment of debt | — | — | (8,726 | ) | (1,749 | ) | |||||||||
Change in operating assets and liabilities: | |||||||||||||||
Accounts receivable | (2,928 | ) | 601 | 10,624 | 20,995 | ||||||||||
Prepayments and other assets | 1,318 | 572 | 350 | 311 | |||||||||||
Accounts payable, accrued and other liabilities | (21,796 | ) | (23,145 | ) | (2,893 | ) | (18,798 | ) | |||||||
Amounts payable to oil and gas property owners | (6,571 | ) | (2,680 | ) | (9,465 | ) | (3,530 | ) | |||||||
Production taxes payable | 3,102 | (838 | ) | (2,878 | ) | (11,482 | ) | ||||||||
Net cash provided by (used in) operating activities | $ | 5,529 | $ | 27,777 | $ | 121,736 | $ | 193,678 | |||||||
Investing Activities: | |||||||||||||||
Additions to oil and gas properties, including acquisitions | (13,166 | ) | (68,475 | ) | (106,870 | ) | (324,534 | ) | |||||||
Additions of furniture, equipment and other | (11 | ) | (187 | ) | (1,195 | ) | (1,223 | ) | |||||||
Proceeds from sale of properties and other investing activities | (644 | ) | 56,505 | 24,927 | 123,122 | ||||||||||
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 | $ | (13,821 | ) | $ | 7,843 | $ | (83,138 | ) | $ | (202,518 | ) | ||||
Financing Activities: | |||||||||||||||
Principal payments on debt | (111 | ) | (108 | ) | (440 | ) | (25,191 | ) | |||||||
Deferred financing costs and other | (21 | ) | 488 | (1,156 | ) | (3,037 | ) | ||||||||
Proceeds from sale of common stock | 110,002 | — | 110,003 | — | |||||||||||
Net cash provided by (used in) financing activities | $ | 109,870 | $ | 380 | $ | 108,407 | $ | (28,228 | ) | ||||||
Increase (Decrease) in Cash and Cash Equivalents | 101,578 | 36,000 | 147,005 | (37,068 | ) | ||||||||||
Beginning Cash and Cash Equivalents | 174,263 | 92,836 | 128,836 | 165,904 | |||||||||||
Ending Cash and Cash Equivalents | $ | 275,841 | $ | 128,836 | $ | 275,841 | $ | 128,836 | |||||||
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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 December 31, | Twelve Months Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
(in thousands) | |||||||||||||||
Net Cash Provided by (Used in) Operating Activities | $ | 5,529 | $ | 27,777 | $ | 121,736 | $ | 193,678 | |||||||
Adjustments to reconcile to discretionary cash flow: | |||||||||||||||
Exploration expense | 19 | 8 | 83 | 153 | |||||||||||
Changes in working capital | 26,875 | 25,490 | 4,262 | 12,504 | |||||||||||
Discretionary Cash Flow | $ | 32,423 | $ | 53,275 | $ | 126,081 | $ | 206,335 | |||||||
Adjusted Net Income (Loss) Reconciliation
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
(in thousands, except per share amounts) | |||||||||||||||
Net Income (Loss) | $ | (49,277 | ) | $ | (21,145 | ) | $ | (170,378 | ) | $ | (487,771 | ) | |||
Provision for (Benefit from) income taxes | — | — | — | (177,085 | ) | ||||||||||
Income (Loss) before Income Taxes | (49,277 | ) | (21,145 | ) | (170,378 | ) | (664,856 | ) | |||||||
Adjustments to Net Income (Loss): | |||||||||||||||
Unrealized derivative (gain) loss | 30,643 | 22,585 | 116,318 | 75,505 | |||||||||||
Impairment expense | — | 72 | 183 | 572,438 | |||||||||||
(Gain) loss on sale of properties | (128 | ) | 2,504 | 1,078 | 1,745 | ||||||||||
(Gain) loss on extinguishment of debt | — | — | (8,726 | ) | (1,749 | ) | |||||||||
One-time items: | |||||||||||||||
CO2 unused commitment | — | 1,429 | — | 1,429 | |||||||||||
West Tavaputs NGL processing true-up | — | (268 | ) | — | (1,273 | ) | |||||||||
Expenses relating to amending credit facility | — | — | — | 1,617 | |||||||||||
(Income) expense related to properties sold | 576 | — | 576 | — | |||||||||||
Adjusted Income (Loss) before Income Taxes | (18,186 | ) | 5,177 | (60,949 | ) | (15,144 | ) | ||||||||
Adjusted (provision for) benefit from income taxes (1) | 7,003 | (1,804 | ) | 23,167 | 5,714 | ||||||||||
Adjusted Net Income (Loss) | $ | (11,183 | ) | $ | 3,373 | $ | (37,782 | ) | $ | (9,430 | ) | ||||
Per share, diluted | $ | (0.18 | ) | $ | 0.07 | $ | (0.68 | ) | $ | (0.20 | ) | ||||
(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. |
16
EBITDAX Reconciliation
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
(in thousands) | |||||||||||||||
Net Income (Loss) | $ | (49,277 | ) | $ | (21,145 | ) | $ | (170,378 | ) | $ | (487,771 | ) | |||
Adjustments to reconcile to EBITDAX: | |||||||||||||||
Depreciation, depletion and amortization | 46,150 | 45,609 | 171,641 | 205,275 | |||||||||||
Impairment, dry hole and abandonment expense | 2,483 | 314 | 4,249 | 575,310 | |||||||||||
Exploration expense | 19 | 8 | 83 | 153 | |||||||||||
Unrealized derivative (gain) loss | 30,643 | 22,585 | 116,318 | 75,505 | |||||||||||
Incentive compensation and other non-cash charges | 1,774 | 2,759 | 8,982 | 10,040 | |||||||||||
(Gain) loss on sale of properties | (128 | ) | 2,504 | 1,078 | 1,745 | ||||||||||
(Gain) loss on extinguishment of debt | — | — | (8,726 | ) | (1,749 | ) | |||||||||
Interest and other income | (69 | ) | (46 | ) | (235 | ) | (565 | ) | |||||||
Interest expense | 14,213 | 15,731 | 59,373 | 65,305 | |||||||||||
Provision for (benefit from) income taxes | — | — | — | (177,085 | ) | ||||||||||
EBITDAX | $ | 45,808 | $ | 68,319 | $ | 182,385 | $ | 266,163 | |||||||
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 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.
17