HOUSTON--(BUSINESS WIRE)--Black Stone Minerals, L.P. (NYSE:BSM) (“Black Stone Minerals,” “Black Stone,” or “the Partnership”) today announces its financial and operating results for the fourth quarter and full year of 2017, provides detailed guidance for 2018, and presents an updated five-year production forecast.
Fourth Quarter 2017 Highlights
- Reported a new quarterly production record in the fourth quarter of 38.1 Mboe/d, representing a 3% increase from the third quarter and a 28% increase from the fourth quarter of last year.
- Increased mineral and royalty volumes by 15% over the third quarter.
- Recognized net income and Adjusted EBITDA for the quarter of $19.4 million and $79.5 million, respectively.
- Reported distributable cash flow of $69.4 million, resulting in distribution coverage for all units of 1.3x.
- Announced and closed the acquisition of a diverse set of mineral and royalty assets from subsidiaries of Noble Energy, Inc. for $335 million, funded primarily by the private placement of $300 million in convertible preferred units.
- Entered into farmout agreement covering substantially all of Black Stone's remaining working interests in the Shelby Trough area of East Texas targeting the Haynesville and Bossier shales for the next several years.
- Reconfirmed the credit facility borrowing base at $550 million and extended the credit agreement maturity date to November 1, 2022.
Other Financial and Operational Highlights
- Achieved full year 2017 production, net income, and Adjusted EBITDA of 37.0 MBoe/d, $157.2 million, and $309.8 million, respectively.
- Reported estimated proved reserves at year-end 2017 of 67.9 MMBoe (74% natural gas and 82% proved developed producing), an increase of 7% over year-end 2016.
- Anticipate average daily production for 2018 growing approximately 14% to 41 - 43 MBoe/d, driven by expected mineral and royalty production growth of 24% year over year.
- Updated long-term forecast provides compound annual growth of approximately 16% and 7% for mineral and royalty production volumes and total production volumes, respectively, over the next five years.
- Based on the improved commodity outlook and the strength of the current forecast, management anticipates converting all the subordinated units to common units on a one-to-one basis in mid-2019 while still allowing for distribution growth and healthy distribution coverage following conversion.
Management Commentary
“2017 was a standout year for Black Stone Minerals,” stated Thomas L. Carter, Jr., Black Stone Minerals’ President, Chief Executive Officer, and Chairman. “Operationally, we posted very strong results for the year with total average daily production growing 17% year over year. Perhaps more importantly, we enhanced our growth prospects through organic initiatives and strategic acquisitions. We added an agreement with a major operator that will drive development of large portions of our Shelby Trough acreage in East Texas. We also lived up to our reputation as an active acquirer by purchasing approximately $500 million in assets during the year, bolstering both our Haynesville and Permian footprints.”
Mr. Carter continued, “Last year at this time, I outlined our goal to de-emphasize our working interest participation program and replace those volumes with mineral and royalty production in a way that would allow us to grow production and cash flow over the long-term. Today, our updated five-year production forecast delivers on that commitment and provides line of sight for the conversion of subordinated units into common units on a one-to-one basis, while growing distributions and maintaining healthy coverage ratios following conversion. This is a testament to the strength of our team and the value of actively managing our assets. I am extremely proud of what our team accomplished in 2017 and how we are positioned to continue building value for our unitholders.”
Quarterly Financial and Operating Results
Production and Realized Prices
Black Stone Minerals reported average production of 38.1 MBoe/d for the fourth quarter of 2017, representing an increase of 28% from the corresponding period in 2016. Mineral and royalty volumes made up 65% of the Partnership’s total reported volumes in the fourth quarter of 2017 and natural gas volumes represented 73%.
The Partnership’s average realized price per Boe, excluding the effect of derivative settlements, was $28.21 for the quarter ended December 31, 2017, an increase of 3% from $27.29 per Boe for the corresponding quarter last year.
Financial Results
Black Stone Minerals reported oil and gas revenues of $99.0 million in the fourth quarter of 2017, an increase of 32% from $74.9 million in the fourth quarter of 2016. The increase reflects higher reported production volumes as well as slightly higher commodity prices compared to the corresponding period in 2016.
The Partnership reported a loss on commodity derivative instruments of $8.5 million for the fourth quarter of 2017, composed of a $2.9 million gain from realized settlements and a non-cash $11.4 million unrealized loss due to the change in value of Black Stone’s derivative positions during the quarter.
Lease bonus and other income was $5.0 million for the fourth quarter of 2017, compared to $6.0 million for the same period last year.
Most expenses for the fourth quarter of 2017 were in line with or below the Partnership’s previously provided guidance, with the exception of general and administrative expense. Based on Black Stone's updated long-term forecast, the Partnership reinstated accruals for certain performance-based units granted in 2015 as part of the Partnership’s IPO which had previously been written off. These expense accruals made in the fourth quarter capture the entire amount of non-cash expense that would have been recognized from grant date through the end of 2017 for those performance-based IPO awards.
The Partnership reported net income of $19.4 million for the quarter ended December 31, 2017, compared to a net loss of $7.3 million in the corresponding period in 2016. Adjusted EBITDA for the fourth quarter of 2017 was $79.5 million, as compared to $58.3 million for the fourth quarter of 2016.
Acquisitions
As previously reported, Black Stone acquired a diverse mineral and royalty package for $335 million in the fourth quarter of 2017 from subsidiaries of Noble Energy, Inc. For the full year, the Partnership acquired approximately $500 million worth of properties, which included $72 million of asset acquisitions financed through the direct placement of common units with the sellers.
2017 Proved Reserves
Estimated proved oil and natural gas reserves at year-end 2017 were 67.9 MMBoe, an increase of 7% from 63.4 MMBoe at year-end 2016, and were approximately 74% natural gas and 82% proved developed producing. The discounted net cash flow of proved reserves discounted at 10% (“PV-10”) was $864.4 million at the end of 2017 as compared to $605.1 million at year-end 2016.
Netherland, Sewell and Associates, Inc., an independent petroleum engineering firm, evaluated Black Stone Minerals’ estimate of its proved reserves and PV-10 at December 31, 2017. These estimates were prepared using reference prices of $51.34 per barrel of oil and $2.98 per MMBTU of natural gas in accordance with the applicable rules of the Securities and Exchange Commission. These prices were adjusted for quality and market differentials, transportation fees, and in the case of natural gas, the value of natural gas liquids. A rollforward of proved reserves is presented in the summary financial tables following this press release.
Financial Position and Activities
As of December 31, 2017, Black Stone Minerals had $388.0 million outstanding under its credit facility. Black Stone Minerals is in compliance with all financial covenants associated with its credit facility. The Partnership’s borrowing base at December 31, 2017 was $550 million. Black Stone’s regularly scheduled borrowing base redetermination is set for April 2018. As of February 23, 2018, $371 million was outstanding under the credit facility.
As previously disclosed, Black Stone issued $300 million of Series B Cumulative Convertible Preferred units during the fourth quarter of 2017 to an affiliate of The Carlyle Group at a price of $20.3926 per preferred unit.
The Partnership established an at-the-market (“ATM”) offering program in 2017. During the fourth quarter of 2017, no units were sold under the ATM program. Through the ATM program, Black Stone can sell common units into the open market from time to time. As of December 31, 2017, the Partnership had approximately $70 million of availability in the ATM program.
Fourth Quarter 2017 Distributions
As previously announced, the Board of Directors of the general partner approved a cash distribution of $0.3125 per common unit and $0.20875 per subordinated unit attributable to the fourth quarter of 2017. These distributions will be paid on February 27, 2018 to unitholders of record as of the close of business on February 20, 2018.
In determining the amount of distributions to common and subordinated unitholders, the Board takes into account numerous factors, including the level of distribution coverage. In addition to the industry-accepted method of calculating distribution coverage, the Partnership also evaluates distribution coverage after deducting net working interest capital expenditures with a goal over the long-term of funding recurring working interest capital expenditures with retained cash flow. The quarterly distribution coverage attributable to the fourth quarter of 2017 for all units was approximately 1.3x before net working interest capital expenditures and approximately 1.2x after net working interest capital expenditures. The Partnership expects the farmout agreements entered into during 2017 will eliminate the substantial majority of its working interest capital expenditures by mid-2018, and accordingly the Partnership does not expect to continue using distributable cash flow after net working interest capital expenditures as a supplemental non-GAAP financial measure in 2018.
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Summary 2018 Guidance |
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Key assumptions in Black Stone Minerals’ 2018 program are as follows: |
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FY 2018 |
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| Average daily production (MBoe/d) | 41 - 43 | ||
| Percentage natural gas | ~75% | ||
| Percentage royalty interest | ~65% | ||
| Lease bonus and other income ($MM) | $30 - $40 | ||
| Lease operating expense ($MM) | $15 - $19 | ||
| Production costs and ad valorem taxes (as % of total pre-derivative O&G revenue) | 12% - 14% | ||
| Exploration expense ($MM) | $1.5 - $2.5 | ||
| G&A - cash ($MM) | $45 - $47 | ||
| G&A - non-cash ($MM) | $28 - $30 | ||
| G&A - TOTAL ($MM) | $73 - $77 | ||
| DD&A ($/Boe) | $8.00 - $9.00 | ||
No acquisitions are assumed in the guidance above; however, consistent with its stated strategy, the Partnership expects to remain active in the acquisition market.
2018 Capital Expenditures
Black Stone Minerals expects to invest between $15 million and $25 million in working interest participation capital in 2018 related primarily to Haynesville and Bossier Shale wells in East Texas that pre-date the Partnership’s working interest farmouts in the Shelby Trough. Substantially all of this capital is expected to be spent in the first quarter of 2018 as these wells are completed and brought online. As a result of the aforementioned farmout arrangements, Black Stone expects working interest participation capital to be negligible following the first quarter of 2018.
In addition, Black Stone expects to invest approximately $10 million to $12 million in the evaluation of its PepperJack prospect in Hardin and Liberty counties, Texas. The previously disclosed PepperJack A#1 well targeting the Lower Wilcox formation has been drilled and was logged in mid-February of 2018. Based on the encouraging results from that well, Black Stone plans to drill a step-out well to further delineate the prospect. The Partnership believes these wells substantially improve its ability to structure a deal with an operating partner to aggressively develop the field to the benefit of Black Stone’s retained mineral and royalty position.
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Five Year Outlook |
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The following projections are based on existing assets and do not contemplate additional acquisitions. |
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| 2018 | 2019 | 2020 | 2021 | 2022 | |||||||
| Total production (MBOE/d) |
41 - 43 |
44 - 46 | 45 - 47 | 47 - 49 | 50 - 52 | ||||||
| Percentage natural gas | ~75% | ~76% | ~75% | ~76% | ~77% | ||||||
| Percentage royalty | ~65% | ~77% | ~87% | ~90% | ~90% | ||||||
| Implied royalty production (MBOE/d) |
26 - 28 |
34 - 36 | 41 - 43 | 42 - 44 | 45 - 47 | ||||||
| Percentage growth | ~24% | ~27% | ~15% | ~8% | ~6% | ||||||
| 5 year CAGR (2017 to 2022) | ~16% | ||||||||||
Black Stone Minerals has a long history of being an active acquirer of mineral and royalty assets and contemplates making acquisitions over the outlook period in the amount of $150 million per year. Including production from modeled acquisitions, the five-year production forecast would increase as follows:
| 2018 | 2019 | 2020 | 2021 | 2022 | |||||||
| Total production, incl. acquisitions (MBOE/d) | 42 - 44 | 46 - 48 | 49 - 51 | 52 - 54 | 57 - 59 | ||||||
Black Stone’s subordinated units first become eligible for conversion into common units following the payment of the distribution with respect to the quarter ending March 31, 2019. Based on the updated pre-acquisition production forecast above and the improved commodity price environment, Black Stone's management and Board of Directors now expect that the Partnership will be in a position to convert the subordinated units on a one-to-one basis while achieving the overarching goal of continued growth in the common distributions with healthy levels of distribution coverage. As a result, management intends to recommend increasing the subordinated unit distribution attributable to the second quarter of 2018 to parity with the common unit distribution. Black Stone will continue to monitor both market conditions and business performance over the conversion period when determining the level of subordinated distributions.
Hedge Position
The Partnership has commodity derivative contracts in place covering portions of anticipated production for 2018 and 2019. For 2018, approximately 74% of expected oil volumes are hedged at prices averaging $54.32 per barrel and approximately 80% of expected gas volumes are hedged at prices averaging $3.02 per Mcf. For 2019, approximately 17% of expected oil volumes are hedged at prices averaging $53.58 per barrel and approximately 19% of expected gas volumes are hedged at prices averaging $2.91 per Mcf. More detailed information regarding the Partnership’s existing hedge position can be found in the Annual Report on Form 10-K for 2017, which is expected to be filed on or around February 27, 2018.
Conference Call
Black Stone Minerals will host a conference call and webcast for investors and analysts to discuss its results for the fourth quarter and full year of 2017 on Tuesday, February 27, 2018 at 9:00 a.m. Central Time. To join the call, participants should dial (877) 447-4732 and use conference code 7447648. A live broadcast of the call will also be available at http://investor.blackstoneminerals.com. A recording of the conference call will be available at that site through March 7, 2018.
Upcoming Investor Relations Events
Members of management from Black Stone Minerals will also be participating in the following investor events:
- 2018 Bernstein Energy & MLP Conference - March 13, 2018 in Boston, Massachusetts. Management will be participating in one-on-one meetings throughout the day, in addition to participating in a panel discussion.
- Scotia Howard Weil 46th Annual Energy Conference - March 27 & 28, 2018 in New Orleans, Louisiana. Management will present on Wednesday, March 28 and will also participate in one-on-one meetings.
Updated presentation materials, if any, for the aforementioned events will be made available on the Black Stone Minerals website the day of the respective event.
About Black Stone Minerals, L.P.
Black Stone Minerals is one of the largest owners of oil and natural gas mineral interests in the United States. The Partnership owns mineral interests and royalty interests in 41 states and 64 onshore basins in the continental United States. The Partnership also owns and selectively participates as a non-operating working interest partner in established development programs, primarily on its mineral and royalty holdings. The Partnership expects that its large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests will result in production and reserve growth, as well as increasing quarterly distributions to its unitholders.
Forward-Looking Statements
This news release includes forward-looking statements. All statements, other than statements of historical facts, included in this news release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements. Terminology such as “will,” “may,” “should,” “expect,” “anticipate,” “plan,” “project,” “intend,” “estimate,” “believe,” “target,” “continue,” “potential,” the negative of such terms or other comparable terminology often identify forward-looking statements. Except as required by law, Black Stone Minerals undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after this news release. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this news release. All forward-looking statements are qualified in their entirety by these cautionary statements. These forward-looking statements involve risks and uncertainties, many of which are beyond the control of Black Stone Minerals, which may cause the Partnership’s actual results to differ materially from those implied or expressed by the forward-looking statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
- the Partnership’s ability to execute its business strategies;
- the volatility of realized oil and natural gas prices;
- the level of production on the Partnership’s properties;
- overall supply and demand for oil and natural gas, as well as regional supply and demand factors, delays, or interruptions of production;
- the Partnership’s ability to replace its oil and natural gas reserves; and
- the Partnership’s ability to identify, complete, and integrate acquisitions.
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BLACK STONE MINERALS, L.P. |
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Three Months Ended |
Year Ended |
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| 2017 | 2016 | 2017 | 2016 | |||||||||||||||
| REVENUE | ||||||||||||||||||
| Oil and condensate sales | $ | 50,631 | $ | 37,801 | $ | 169,728 | $ | 142,382 | ||||||||||
| Natural gas and natural gas liquids sales | 48,316 | 37,130 | 190,967 | 122,836 | ||||||||||||||
| Gain (loss) on commodity derivative instruments | (8,485 | ) | (24,169 | ) | 26,902 | (36,464 | ) | |||||||||||
| Lease bonus and other income | 4,980 | 5,950 | 42,062 | 32,079 | ||||||||||||||
| TOTAL REVENUE | 95,442 | 56,712 | 429,659 | 260,833 | ||||||||||||||
| OPERATING (INCOME) EXPENSE | ||||||||||||||||||
| Lease operating expense | 4,374 | 4,576 | 17,280 | 18,755 | ||||||||||||||
| Production costs and ad valorem taxes | 12,160 | 12,163 | 47,474 | 35,464 | ||||||||||||||
| Exploration expense | 2 | 2 | 618 | 645 | ||||||||||||||
| Depreciation, depletion and amortization | 30,051 | 22,833 | 114,534 | 102,487 | ||||||||||||||
| Impairment of oil and natural gas properties | — | — | — | 6,775 | ||||||||||||||
| General and administrative | 25,576 | 20,926 | 77,574 | 73,139 | ||||||||||||||
| Accretion of asset retirement obligations | 266 | 212 | 1,026 | 892 | ||||||||||||||
| (Gain) loss on sale of assets, net | — | (21 | ) | (931 | ) | (4,793 | ) | |||||||||||
| Other expense | — | — | — | — | ||||||||||||||
| TOTAL OPERATING EXPENSE | 72,429 | 60,691 | 257,575 | 233,364 | ||||||||||||||
| INCOME (LOSS) FROM OPERATIONS | 23,013 | (3,979 | ) | 172,084 | 27,469 | |||||||||||||
| OTHER INCOME (EXPENSE) | ||||||||||||||||||
| Interest and investment income | 19 | 5 | 49 | 656 | ||||||||||||||
| Interest expense | (4,034 | ) | (2,774 | ) | (15,694 | ) | (7,547 | ) | ||||||||||
| Other income (expense) | 362 | (538 | ) | 714 | (390 | ) | ||||||||||||
| TOTAL OTHER EXPENSE | (3,653 | ) | (3,307 | ) | (14,931 | ) | (7,281 | ) | ||||||||||
| NET INCOME (LOSS) | 19,360 | (7,286 | ) | 157,153 | 20,188 | |||||||||||||
| Net income (loss) attributable to noncontrolling interests subsequent to initial public offering | 7 | (3 | ) | 34 | 12 | |||||||||||||
| Distributions on Series A redeemable preferred units subsequent to initial public offering | (665 | ) | (1,324 | ) | (3,117 | ) | (5,763 | ) | ||||||||||
| Distributions on Series B cumulative convertible preferred units | (1,925 | ) | — | (1,925 | ) | — | ||||||||||||
| NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING | $ | 16,777 | $ | (8,613 | ) | $ | 152,145 | $ | 14,437 | |||||||||
| ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO: | ||||||||||||||||||
| General partner interest | $ | — | $ | — | $ | — | $ | — | ||||||||||
| Common units | 14,400 | 326 | 98,389 | 24,669 | ||||||||||||||
| Subordinated units | 2,377 | (8,939 | ) | 53,756 | (10,232 | ) | ||||||||||||
| $ | 16,777 | $ | (8,613 | ) | $ | 152,145 | $ | 14,437 | ||||||||||
| NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: | ||||||||||||||||||
| Per common unit (basic) | $ | 0.15 | $ | 0.01 | $ | 1.01 | $ | 0.26 | ||||||||||
| Weighted average common units outstanding (basic) | 103,415 | 95,725 | 97,400 | 96,073 | ||||||||||||||
| Per subordinated unit (basic) | $ | 0.02 | $ | (0.10 | ) | $ | 0.56 | $ | (0.11 | ) | ||||||||
| Weighted average subordinated units outstanding (basic) | 95,388 | 95,180 | 95,149 | 95,138 | ||||||||||||||
| Per common unit (diluted) | $ | 0.15 | $ | 0.01 | $ | 1.01 | $ | 0.26 | ||||||||||
| Weighted average common units outstanding (diluted) | 103,415 | 95,895 | 97,400 | 96,243 | ||||||||||||||
| Per subordinated unit (diluted) | $ | 0.02 | $ | (0.10 | ) | $ | 0.56 | $ | (0.11 | ) | ||||||||
| Weighted average subordinated units outstanding (diluted) | 95,388 | 95,180 | 95,149 | 95,138 | ||||||||||||||
| DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING: | ||||||||||||||||||
| Per common unit | $ | 0.31 | $ | 0.29 | $ | 1.20 | $ | 1.10 | ||||||||||
| Per subordinated unit | $ | 0.21 | $ | 0.18 | $ | 0.79 | $ | 0.74 | ||||||||||
The following table shows the Partnership’s production, revenues, realized prices, and expenses for the periods presented.
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Three Months Ended |
Year Ended |
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| 2017 | 2016 | 2017 | 2016 | |||||||||||||||
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(Unaudited)
(Dollars in thousands, except for realized prices) |
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| Production: | ||||||||||||||||||
| Oil and condensate (MBbls) | 955 | 832 | 3,552 | 3,680 | ||||||||||||||
| Natural gas (MMcf)1 | 15,320 | 11,484 | 59,779 | 47,498 | ||||||||||||||
| Equivalents (MBoe) | 3,508 | 2,746 | 13,515 | 11,596 | ||||||||||||||
| Revenue: | ||||||||||||||||||
| Oil and condensate sales | $ | 50,631 | $ | 37,801 | $ | 169,728 | $ | 142,382 | ||||||||||
| Natural gas and natural gas liquids sales1 | 48,316 | 37,130 | 190,967 | 122,836 | ||||||||||||||
| Gain (loss) on commodity derivative instruments | (8,485 | ) | (24,169 | ) | 26,902 | (36,464 | ) | |||||||||||
| Lease bonus and other income | 4,980 | 5,950 | 42,062 | 32,079 | ||||||||||||||
| Total revenue | $ | 95,442 | $ | 56,712 | $ | 429,659 | $ | 260,833 | ||||||||||
| Realized prices, without derivatives: | ||||||||||||||||||
| Oil and condensate ($/Bbl) | $ | 53.02 | $ | 45.43 | $ | 47.78 | $ | 38.69 | ||||||||||
| Natural gas ($/Mcf)1 | $ | 3.15 | $ | 3.23 | $ | 3.19 | $ | 2.59 | ||||||||||
| Equivalents ($/Boe) | $ | 28.21 | $ | 27.29 | $ | 26.69 | $ | 22.87 | ||||||||||
| Operating expenses: | ||||||||||||||||||
| Lease operating expense | $ | 4,374 | $ | 4,576 | $ | 17,280 | $ | 18,755 | ||||||||||
| Production costs and ad valorem taxes | 12,160 | 12,163 | 47,474 | 35,464 | ||||||||||||||
| Exploration expense | 2 | 2 | 618 | 645 | ||||||||||||||
| Depreciation, depletion, and amortization | 30,051 | 22,833 | 114,534 | 102,487 | ||||||||||||||
| Impairment of oil and natural gas properties | — | — | — | 6,775 | ||||||||||||||
| General and administrative | 25,576 | 20,926 | 77,574 | 73,139 | ||||||||||||||
| Other expense: | ||||||||||||||||||
| Interest expense | 4,034 | 2,774 | 15,694 | 7,547 | ||||||||||||||
| Per Boe: | ||||||||||||||||||
| Lease operating expense (per working interest Boe) | 3.53 | 4.35 | 3.17 | 4.62 | ||||||||||||||
| Production costs and ad valorem taxes | 3.47 | 4.43 | 3.51 | 3.06 | ||||||||||||||
| Depreciation, depletion, and amortization | 8.57 | 8.32 | 8.47 | 8.84 | ||||||||||||||
| General and administrative | 7.29 | 7.62 | 5.74 | 6.31 | ||||||||||||||
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| 1 | As a mineral-and-royalty-interest owner, Black Stone Minerals is often provided insufficient and inconsistent data on natural gas liquid ("NGL") volumes by its operators. As a result, the Partnership is unable to reliably determine the total volumes of NGLs associated with the production of natural gas on its acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in natural gas revenue and the calculation of realized prices for natural gas. | |
Non-GAAP Financial Measures
Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures are supplemental non-GAAP ("GAAP" is defined as generally accepted accounting principles) financial measures used by management and external users of the financial statements such as investors, research analysts, and others, to assess the financial performance of the Partnership's assets and its ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.
Black Stone defines Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, and non-cash equity-based compensation. The Partnership defines distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, estimated replacement capital expenditures, cash interest expense, and distributions to noncontrolling interests and preferred unitholders. Distributable cash flow after net working interest capital expenditures is defined as distributable cash flow less net working interest capital expenditures. Net working interest capital expenditures consists of all capital expenditures related to working interest wells less the recoupment of working interest expenditures under farmout agreements. Black Stone expects the farmout agreements entered into during 2017 will eliminate the substantial majority of its working interest capital expenditures by mid-2018.
Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with GAAP in the United States as measures of Black Stone's financial performance.
Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. The Partnership's computation of Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures may differ from computations of similarly titled measures of other companies.
The following table presents a reconciliation of Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures to net income (loss), the most directly comparable GAAP financial measure, for the periods indicated.
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Three Months Ended |
Year Ended |
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| 2017 | 2016 | 2017 | 2016 | |||||||||||||||
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(Unaudited)
(In thousands) |
(Unaudited)
(In thousands) |
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| Net income (loss) | $ | 19,360 | $ | (7,286 | ) | $ | 157,153 | $ | 20,188 | |||||||||
| Adjustments to reconcile to Adjusted EBITDA: | ||||||||||||||||||
| Depreciation, depletion and amortization | 30,051 | 22,833 | 114,534 | 102,487 | ||||||||||||||
| Interest expense | 4,034 | 2,774 | 15,694 | 7,547 | ||||||||||||||
| Impairment of oil and natural gas properties | — | — | — | 6,775 | ||||||||||||||
| Accretion of asset retirement obligations | 266 | 212 | 1,026 | 892 | ||||||||||||||
| Equity-based compensation1 | 14,431 | 10,018 | 33,045 | 43,138 | ||||||||||||||
| Unrealized (gain) loss on commodity derivative instruments | 11,357 | 29,738 | (11,691 | ) | 81,253 | |||||||||||||
| Adjusted EBITDA | 79,499 | 58,289 | 309,761 | 262,280 | ||||||||||||||
| Adjustments to distributable cash flow: | ||||||||||||||||||
| Deferred revenue | (416 | ) | (695 | ) | (2,086 | ) | (870 | ) | ||||||||||
| Cash interest expense | (3,818 | ) | (2,497 | ) | (14,817 | ) | (6,676 | ) | ||||||||||
| (Gain) loss on sales of assets, net | — | (21 | ) | (931 | ) | (4,793 | ) | |||||||||||
| Estimated replacement capital expenditures2 | (3,250 | ) | (3,750 | ) | (13,500 | ) | (11,250 | ) | ||||||||||
| Cash paid to noncontrolling interests | (30 | ) | (28 | ) | (120 | ) | (111 | ) | ||||||||||
| Preferred unit distributions | (2,590 | ) | (1,324 | ) | (5,042 | ) | (5,763 | ) | ||||||||||
| Distributable cash flow | 69,395 | 49,974 | 273,265 | 232,817 | ||||||||||||||
| Net working interest capital expenditures | (5,389 | ) | (17,140 | ) | (39,477 | ) | (80,179 | ) | ||||||||||
| Distributable cash flow after net working interest capital expenditures | $ | 64,006 | $ | 32,834 | $ | 233,788 | $ | 152,638 | ||||||||||
| 1 | On April 25, 2016, the Compensation Committee of the Board approved a resolution to change the settlement feature of certain employee long-term incentive compensation plans from cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities were reclassified to equity-settled liabilities during the second quarter of 2016. | |
| 2 | On August 3, 2016, the board of directors of our general partner established a replacement capital expenditures estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017; there was no established estimate of replacement capital expenditures prior to this period. On June 8, 2017, the board of directors of our general partner established a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018. | |
|
Proved Oil & Gas Reserve Quantities |
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A reconciliation of proved reserves is presented in the following table: |
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|
Crude Oil |
Natural Gas |
Total |
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| Net proved reserves at December 31, 2016 | 18,368 | 270,339 | 63,425 | |||||||
| Revisions of previous estimates | (1,234 | ) | 21,067 | 2,277 | ||||||
| Purchases of minerals in place | 2,267 | 30,250 | 7,309 | |||||||
| Extensions, discoveries, and other additions | 2,050 | 38,397 | 8,449 | |||||||
| Production | (3,552 | ) | (59,779 | ) | (13,515 | ) | ||||
| Net proved reserves at December 31, 2017 | 17,899 | 300,274 | 67,945 | |||||||
| Net Proved Developed Reserves | ||||||||||
| December 31, 2016 | 18,150 | 223,057 | 55,327 | |||||||
| December 31, 2017 | 17,891 | 233,017 | 56,727 | |||||||
| Net Proved Undeveloped Reserves | ||||||||||
| December 31, 2016 | 218 | 47,282 | 8,098 | |||||||
| December 31, 2017 | 8 | 67,257 | 11,218 | |||||||
