Black Stone Minerals, L.P. Announces Fourth Quarter and Full Year 2017 Results; Provides Guidance for 2018 and Updated Long-Term Production Outlook
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 toNovember 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
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
The Partnership’s average realized price per Boe, excluding the effect
of derivative settlements, was
Financial Results
The Partnership reported a loss on commodity derivative instruments of
Lease bonus and other income was
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
Acquisitions
As previously reported, Black Stone acquired a diverse mineral and
royalty package for
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
Financial Position and Activities
As of
As previously disclosed, Black Stone issued
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
Fourth Quarter 2017 Distributions
As previously announced, the Board of Directors of the general partner
approved a cash distribution of
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.
Summary 2018 Guidance |
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Key assumptions in Black Stone Minerals’ 2018 program are as follows: |
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FY 2018 |
|||
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
In addition, Black Stone expects to invest approximately
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% | ||||||||||
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
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
Conference Call
Upcoming Investor Relations Events
Members of management from
-
2018
Bernstein Energy & MLP Conference -March 13, 2018 inBoston, 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 AnnualEnergy Conference -March 27 & 28, 2018 inNew Orleans, Louisiana . Management will present onWednesday, 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
About
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,
- 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.
BLACK STONE MINERALS, L.P. |
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Three Months Ended |
Year Ended |
|||||||||||||||||
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.
Three Months Ended |
Year Ended |
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2017 | 2016 | 2017 | 2016 | |||||||||||||||
(Unaudited)
(Dollars in thousands, except for realized prices) |
||||||||||||||||||
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
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.
Three Months Ended |
Year Ended |
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2017 | 2016 | 2017 | 2016 | |||||||||||||||
(Unaudited)
(In thousands) |
(Unaudited)
(In thousands) |
|||||||||||||||||
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 |
||||||||
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 | |||||||
View source version on businesswire.com: http://www.businesswire.com/news/home/20180226006602/en/
Source:
Black Stone Minerals, L.P. Contact
Brent Collins,
713-445-3200
Vice President, Investor Relations
investorrelations@blackstoneminerals.com