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 2018
and provides guidance for 2019.
Fourth Quarter 2018 Highlights
- Set a new quarterly total reported
production record in the fourth quarter of 49.7 MBoe/d,
representing a 3% increase from the third quarter and a 30%
increase from the fourth quarter of 2017.
- Mineral and royalty production
increased 9% from the third quarter of 2018, marking a new record
of 35.8 MBoe/d.
- Recognized net income and Adjusted
EBITDA for the quarter of $164.1 million and $110.0 million,
respectively.
- Reported distributable cash flow of
$96.7 million, resulting in distribution coverage for all units of
1.3x based on the announced cash distribution of $0.37 per unit;
retained $20.8 million of distributable cash in the fourth
quarter.
Other Financial and Operational Highlights
- Achieved full year 2018 production, net
income, and Adjusted EBITDA of 46.3 MBoe/d, $295.6 million, and
$419.4 million, respectively.
- Mineral and royalty volumes in 2018
increased 45% over the prior year to average 32.1 MBoe/d.
- Closed on $149.9 million of
acquisitions in 2018 focused on East Texas Haynesville/Bossier and
core Midland/Delaware plays.
- Reported estimated proved reserves at
year-end 2018 of 69.9 MMBoe (75% natural gas and 86% proved
developed producing), an increase of 3% over year-end 2017.
- Expect to maintain 2018's average daily
production levels through 2019, with mineral and royalty production
anticipated to grow by approximately 12% year over year at
mid-point of guidance.
Management Commentary
Thomas L. Carter, Jr., Black Stone Minerals’ Chief Executive
Officer and Chairman commented, “We capped off a terrific year with
another strong quarter. We posted new records for both
mineral-and-royalty production and total production in the fourth
quarter and maintained our distribution with solid coverage in a
challenging commodity environment. Our core mineral and royalty
business performed extremely well, more than offsetting our planned
reduction in working interest volumes. We acquired approximately
$150 million worth of properties during the year, and the Noble
assets acquired at the end of 2017 continue to outperform our
original expectations. The Partnership grew distributions for both
common and subordinated unitholders throughout the year, while
retaining almost $100 million of our distributable cash flow that
largely funded our acquisition program for the year in a period
where access to the capital markets was challenged. Building on
these accomplishments from 2018, we expect continued growth in our
mineral and royalty business in 2019. We also expect to fully
convert the subordinated units to common units in May with the
payment of the distribution attributable to the first quarter of
2019, which will result in a simplified capital structure. We are
well positioned with a fantastic set of assets, strong financial
footing, and an experienced management team. In addition to our
organic growth driven by our strategic positions in the Permian and
Haynesville, we are excited about additional mineral consolidation
opportunities we see in the near term."
Quarterly Financial and Operating Results
Production
Black Stone Minerals reported average production of 49.7 MBoe/d
(72% mineral and royalty, 71% natural gas) for the fourth quarter
of 2018, representing a sequential increase of 3% and a year over
year increase of 30% from the corresponding period in 2017. Mineral
and royalty volumes grew by 9% from the levels reported in the
third quarter of 2018, while working interest volumes decreased by
9% over the same period. Year over year, mineral and royalty
volumes grew 45% in 2018, driven primarily by increases on existing
acreage; excluding the Noble acquisition completed in November
2017, base mineral and royalty production grew 31% from 2017 to
2018. Working interest production declined by 5% year over year as
a result of the farmouts put in place in 2017.
Realized Prices, Revenues, and Net Income
The Partnership’s average realized price per Boe, excluding the
effect of derivative settlements, was $33.97 for the quarter ended
December 31, 2018. This is an increase of 4% from $32.81 per Boe
from the third quarter of 2018 and a 20% increase compared to
$28.21 for the fourth quarter of 2017.
Black Stone reported oil and gas revenue of $155.4 million (50%
oil and condensate) for the fourth quarter of 2018, an increase of
7% from $145.8 million in the third quarter of 2018. Oil and gas
revenue in the fourth quarter of 2017 was $98.9 million.
The Partnership reported a gain on commodity derivative
instruments of $83.0 million for the fourth quarter of 2018,
composed of a $17.8 million loss from realized settlements and a
non-cash $100.8 million unrealized gain due to the change in value
of Black Stone’s derivative positions during the quarter. Black
Stone reported losses on commodity derivative instruments of $18.5
million and $8.5 million for the quarters ended September 30, 2018
and December 31, 2017, respectively.
Lease bonus and other income was $7.6 million for the fourth
quarter of 2018, compared to $12.4 million for the third quarter of
2018. For the quarter ended December 31, 2017, Black Stone reported
lease bonus and other income of $5.0 million.
The Partnership reported net income of $164.1 million for the
quarter ended December 31, 2018, compared to net income of $60.8
million in the preceding quarter. For the quarter ended December
31, 2017, net income was $19.4 million.
Adjusted EBITDA and Distributable Cash Flow
Adjusted EBITDA for the fourth quarter of 2018 was $110.0
million, which compares to $114.2 million in the third quarter of
2018 and $79.5 million in the fourth quarter of 2017. Distributable
cash flow for the quarter ended December 31, 2018 was $96.7
million. For the quarters ended September 30, 2018 and December 31,
2017, distributable cash flow was $100.8 million and $69.4 million,
respectively.
Acquisitions
Black Stone acquired $17.8 million of properties during the
fourth quarter of 2018, substantially all of which were purchased
using cash. The vast majority of the quarter's activity related to
the Partnership's ongoing bolt-on acquisition program in the Shelby
Trough area of East Texas. For the full year, Black Stone Minerals
completed $149.9 million in acquisitions (85% of which were
completed using cash) focused on East Texas and the Permian
Basin.
2018 Proved Reserves
Estimated proved oil and natural gas reserves at year-end 2018
were 69.9 MMBoe, an increase of 3% from 67.9 MMBoe at year-end
2017, and were approximately 75% natural gas and 86% proved
developed producing. The standardized measure of discounted future
net cash flows was $1,087.6 million at the end of 2018 as compared
to $862.6 million at year-end 2017.
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, 2018.
These estimates were prepared using reference prices of $65.56 per
barrel of oil and $3.10 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 reconciliation of proved reserves is
presented in the summary financial tables following this press
release.
Financial Position and Activities
As of December 31, 2018, Black Stone Minerals had $5.4 million
in cash and $410.0 million outstanding under its credit facility.
The Partnership’s borrowing base at December 31, 2018 was $675
million, and the Partnership's next regularly scheduled borrowing
base redetermination is set for April 2019. Black Stone is in
compliance with all financial covenants associated with its credit
facility.
As of February 22, 2019, $381.0 million was outstanding under
the credit facility and the Partnership had $12.1 million in
cash.
The Partnership established an at-the-market (“ATM”) offering
program in 2017. Early in the fourth quarter of 2018, Black Stone
sold 122,132 common units under the ATM program at an average price
of $18.36 per unit. Through the ATM program, Black Stone can sell
common units into the open market from time to time. As of December
31, 2018, the Partnership had approximately $27 million of
remaining availability in the ATM program.
During the fourth quarter of 2018, the Board of Directors
authorized a $75 million unit repurchase program. Late in the
quarter, the Partnership repurchased 128,627 common units at an
average price of $15.61 per unit.
Fourth Quarter 2018 Distributions
As previously announced, the Board of Directors of the general
partner approved a cash distribution of $0.37 for each common and
subordinated unit attributable to the fourth quarter of 2018. The
quarterly distribution coverage ratio attributable to the fourth
quarter of 2018 was approximately 1.3x for all units. These
distributions will be paid on February 26, 2019 to unitholders of
record as of the close of business on February 19, 2019.
Summary 2019 Guidance
Following are the key assumptions in Black Stone Minerals’ 2019
guidance, as well as comparable results for 2018:
FY
2018
FY 2019
Est.
Mineral and royalty production (MBoe/d) 32.1 35 - 37 Working
interest production (MBoe/d) 14.2 10 - 11 Total production
(MBoe/d) 46.3 45 - 48 Percentage natural gas 71% ~71% Percentage
royalty interest 69% ~77% Lease bonus and other income ($MM)
$36.2 $30 - $40 Lease operating expense ($MM) $18.4 $17 -
$19 Production costs and ad valorem taxes (as % of total
pre-derivative O&G revenue) 11.5% 11% - 13% Exploration expense
($MM) $7.9 $1.0 - $2.0 G&A - cash ($MM) $46.6 $45 - $47
G&A - non-cash ($MM) $30.1 $21 - $23 G&A - TOTAL
($MM) $76.7 $66 - $70 DD&A ($/Boe) $7.26 $7.00 - $8.00
No acquisitions are assumed in the guidance above; however,
consistent with its stated strategy, the Partnership expects to
remain active in the acquisition market in 2019 and beyond.
Production
Mineral and royalty production in 2019 is being driven
principally by anticipated development of the Haynesville/Bossier
play in the Shelby Trough of East Texas, and of the Midland and
Delaware basins. At this time, Black Stone does not anticipate
investing its own capital in working interest participation;
accordingly working interest production is expected to decline by
approximately 25% as a result of Black Stone's successful farmout
of Shelby Trough Haynesville working interests.
Exploration Expense
Black Stone plans to purchase seismic data in the Shelby Trough
in 2019 to help guide the Partnership's ongoing acquisition program
in the area.
General & Administrative Expense
Non-cash general & administrative expense is expected to
decline in 2019 as a result of the vesting and settlement of equity
awards granted at the time of our IPO. These awards vest over a
four-year period and will be settled in the first half of 2019.
Hedge Position
Black Stone has commodity derivative contracts in place covering
portions of its anticipated production for 2019 and 2020. The
Partnership's current hedge position for 2019 and 2020, including
hedges put in place subsequent to December 31, 2018, is summarized
in the following tables:
Oil Hedge Position
Weighted Avg Oil Costless
Weighted Avg Weighted Avg Oil Swap Oil Swap Price
Collars Collar Floor Collar Ceiling MBbl $/Bbl MBbl $/Bbl $/Bbl
1Q19 685 $58.62 60 $65.00 $74.00 2Q19 765 $58.54 60 $65.00 $74.00
3Q19 765 $58.15 60 $65.00 $74.00 4Q19 765 $58.15 60 $65.00 $74.00
1Q20 180 $57.48 210 $56.43 $67.14 2Q20 180 $57.48 210 $56.43 $67.14
3Q20 180 $57.48 210 $56.43 $67.14 4Q20 180 $57.48 210 $56.43 $67.14
Gas Hedge Position
Weighted Avg Gas Swap Gas Swap Price MMcf
$/Mcf
1Q19 14,400 $2.96 2Q19 14,520 $2.96 3Q19 14,640 $2.96 4Q19 14,640
$2.96 1Q20 6,370 $2.72 2Q20 6,370 $2.72 3Q20 6,440 $2.72 4Q20 6,440
$2.72
More detailed information about the Partnership's existing
hedging program can be found in the Annual Report on Form 10-K,
which is expected to be filed on February 26, 2019.
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 2018 on Tuesday, February 26, 2019 at 9:00
a.m. Central Time. To join the call, participants should dial (877)
447-4732 and use conference code 2697118. 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 31, 2019.
Upcoming Investor Relations Events
Members of management from Black Stone Minerals will also be
participating in the following investor events:
- Scotia Howard Weil 47th Annual Energy
Conference - March 25 & 26, 2019 in New Orleans, Louisiana.
Management will present on Monday, March 25th and will also
participate in one-on-one meetings.
- IPAA OGIS - April 9, 2019 in New York
City. Management will present and participate in one-on-one
meetings.
- NYSE Investor Access Day - April 10,
2019 in New York City. Management will conduct meetings with
investors throughout the day.
- World Oilman's Mineral & Royalty
Conference - April 22 & 23, 2019 in Houston, Texas. Management
will participate on an industry panel.
Updated presentation materials and webcast information, 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. Black Stone
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 distributions
to its unitholders, over time.
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.
BLACK STONE MINERALS, L.P. CONSOLIDATED STATEMENTS
OF OPERATIONS (Unaudited) (In thousands, except per
unit amounts) Three Months Ended
Year Ended December 31, December 31,
2018 2017 2018 2017
REVENUE Oil and condensate sales $ 77,358 $ 50,631 $ 310,278 $
169,728 Natural gas and natural gas liquids sales 78,064 48,316
248,243 190,967 Lease bonus and other income 7,600 4,980
36,216 42,062 Revenue from contracts with
customers 163,022 103,927 594,737 402,757 Gain (loss) on commodity
derivative instruments 83,025 (8,485 ) 14,831 26,902
TOTAL REVENUE 246,047 95,442 609,568
429,659 OPERATING (INCOME) EXPENSE Lease operating expense
5,648 4,374 18,415 17,280 Production costs and ad valorem taxes
17,425 12,160 64,364 47,474 Exploration expense 1,161 2 7,943 618
Depreciation, depletion and amortization 34,518 30,051 122,653
114,534 General and administrative 16,296 25,576 76,712 77,574
Accretion of asset retirement obligations 283 266 1,103 1,026
(Gain) loss on sale of assets, net (1 ) — (3 ) (931 ) TOTAL
OPERATING EXPENSE 75,330 72,429 291,187
257,575 INCOME (LOSS) FROM OPERATIONS 170,717 23,013 318,381
172,084 OTHER INCOME (EXPENSE) Interest and investment income 60 19
183 49 Interest expense (5,437 ) (4,034 ) (20,756 ) (15,694 ) Other
income (expense) (1,202 ) 362 (2,248 ) 714 TOTAL
OTHER EXPENSE (6,579 ) (3,653 ) (22,821 ) (14,931 ) NET INCOME
(LOSS) 164,138 19,360 295,560 157,153 Net (income) loss
attributable to noncontrolling interests (23 ) 7 (24 ) 34
Distributions on Series A redeemable preferred units — (665 ) (25 )
(3,117 ) Distributions on Series B cumulative convertible preferred
units (5,250 ) (1,925 ) (21,000 ) (1,925 ) NET INCOME (LOSS)
ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED
UNITS $ 158,865 $ 16,777 $ 274,511 $ 152,145
ALLOCATION OF NET INCOME (LOSS): General partner interest $
— $ — $ — $ — Common units 83,625 14,400 154,662 98,389
Subordinated units 75,240 2,377 119,849 53,756
$ 158,865 $ 16,777 $ 274,511 $ 152,145
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER
COMMON AND SUBORDINATED UNIT: Per common unit (basic) $ 0.78
$ 0.15 $ 1.46 $ 1.01 Weighted average common
units outstanding (basic) 108,465 103,415 106,064
97,400 Per subordinated unit (basic) $ 0.78 $
0.02 $ 1.25 $ 0.56 Weighted average
subordinated units outstanding (basic) 96,329 95,388
96,099 95,149 Per common unit (diluted) $ 0.72
$ 0.15 $ 1.45 $ 1.01 Weighted average common
units outstanding (diluted) 124,354 103,415 121,264
97,400 Per subordinated unit (diluted) $ 0.78
$ 0.02 $ 1.25 $ 0.56 Weighted average
subordinated units outstanding (diluted) 96,329 95,388
96,346 95,149
The following table shows the Partnership’s production,
revenues, realized prices, and expenses for the periods
presented.
Three Months Ended Year Ended
December 31, December 31, 2018
2017 2018 2017 (Unaudited)
(Dollars in thousands, except for realized prices)
Production: Oil and condensate (MBbls) 1,339 955 4,962 3,552
Natural gas (MMcf)1 19,417 15,320 71,622
59,779 Equivalents (MBoe) 4,575 3,508 16,899 13,515 Equivalents/day
(MBoe) 49.7 38.1 46.3 37.0
Revenue: Oil and condensate sales
$ 77,358 $ 50,631 $ 310,278 $ 169,728 Natural gas and natural gas
liquids sales1 78,064 48,316 248,243 190,967 Lease bonus and other
income 7,600 4,980 36,216 42,062 Revenue from
contracts with customers 163,022 103,927 594,737 402,757 Gain
(loss) on commodity derivative instruments 83,025 (8,485 )
14,831 26,902 Total revenue $ 246,047 $ 95,442 $ 609,568 $
429,659
Realized prices, without derivatives: Oil and
condensate ($/Bbl) $ 57.77 $ 53.02 $ 62.53 $ 47.78 Natural gas
($/Mcf)1 $ 4.02 $ 3.15 $ 3.47 $ 3.19
Equivalents ($/Boe) $ 33.97 $ 28.21 $ 33.05 $ 26.69
Operating
expenses: Lease operating expense $ 5,648 $ 4,374 $ 18,415 $
17,280 Production costs and ad valorem taxes 17,425 12,160 64,364
47,474 Exploration expense 1,161 2 7,943 618 Depreciation,
depletion, and amortization 34,518 30,051 122,653 114,534 General
and administrative 16,296 25,576 76,712 77,574
Per Boe:
Lease operating expense (per working interest Boe) 4.41 3.53 3.55
3.17 Production costs and ad valorem taxes 3.81 3.47 3.81 3.51
Depreciation, depletion, and amortization 7.54 8.57 7.26 8.47
General and administrative 3.56 7.29 4.54 5.74 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 and distributable cash flow are supplemental
non-GAAP financial measures used by our management and external
users of our financial statements such as investors, research
analysts, and others, to assess the financial performance of our
assets and our ability to sustain distributions over the long term
without regard to financing methods, capital structure, or
historical cost basis.
We define 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. We define 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.
Adjusted EBITDA and distributable cash flow 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 generally accepted accounting principles in the
United States ("U.S. GAAP") as measures of our financial
performance.
Adjusted EBITDA and distributable cash flow have important
limitations as analytical tools because they exclude some but not
all items that affect net income (loss), the most directly
comparable U.S. GAAP financial measure. Our computation of Adjusted
EBITDA and distributable cash flow may differ from computations of
similarly titled measures of other companies.
The following table presents a reconciliation of net income
(loss), the most directly comparable U.S. GAAP financial measure,
to Adjusted EBITDA and distributable cash flow for the periods
indicated:
Three Months Ended Year Ended
December 31, December 31, 2018
2017 2018 2017 (Unaudited)
(In thousands, except per unit amounts) Net income (loss) $
164,138 $ 19,360 $ 295,560 $ 157,153 Adjustments to reconcile to
Adjusted EBITDA: Depreciation, depletion and amortization 34,518
30,051 122,653 114,534 Interest expense 5,437 4,034 20,756 15,694
Income tax expense 1,250 — 2,309 — Accretion of asset retirement
obligations 283 266 1,103 1,026 Equity-based compensation 5,187
14,431 30,134 33,045 Unrealized (gain) loss on commodity derivative
instruments (100,799 ) 11,357 (53,066 ) (11,691 ) Adjusted
EBITDA 110,014 79,499 419,449 309,761 Adjustments to distributable
cash flow: Change in deferred revenue (40 ) (416 ) 1,260 (2,086 )
Cash interest expense (5,186 ) (3,818 ) (19,757 ) (14,817 ) (Gain)
loss on sales of assets, net (1 ) — (3 ) (931 ) Estimated
replacement capital expenditures1 (2,750 ) (3,250 ) (11,500 )
(13,500 ) Cash paid to noncontrolling interests (50 ) (30 ) (211 )
(120 ) Preferred unit distributions (5,250 ) (2,590 ) (21,025 )
(5,042 ) Distributable cash flow 96,737 69,395
368,213 273,265 Total units outstanding2
205,180 199,647 Distributable cash flow per unit 0.471 0.348 Common
unit price as of February 22, 2019 $ 18.15 Implied distributable
cash flow yield 10.4 %
1 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. On
June 8, 2017, the Board approved a replacement capital expenditure
estimate of $13.0 million for the period of April 1, 2017 to March
31, 2018. On April 27, 2018, the Board approved a replacement
capital expenditure estimate of $11.0 million for the period of
April 1, 2018 to March 31, 2019.
2 The distribution attributable to the quarter ended
December 31, 2018 is calculated using 108,851,353 common units
and 96,328,836 subordinated units as of February 19, 2019.
Distributions attributable to the quarter ended December 31,
2017 were calculated using 104,258,290 common units and 95,388,424
subordinated units as of the record date of February 20, 2018.
Proved Oil & Gas Reserve Quantities
A reconciliation of proved reserves is presented in the
following table:
Crude Oil Natural Gas
Total (MBbl) (MMcf)
(MBoe) Net proved reserves at December 31, 2017 17,899
300,274 67,945 Revisions of previous estimates (35 ) (11,027 )
(1,873 ) Purchases of minerals in place 227 419 297 Extensions,
discoveries, and other additions 4,438 95,976 20,434 Production
(4,962 ) (71,622 ) (16,899 ) Net proved
reserves at December 31, 2018 17,567 314,020
69,904 Net Proved Developed Reserves December
31, 2017 17,891 233,017 56,727 December 31, 2018 17,567 278,233
63,939 Net Proved Undeveloped Reserves December 31, 2017 8 67,257
11,218 December 31, 2018 — 35,787 5,965
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version on businesswire.com: https://www.businesswire.com/news/home/20190225006052/en/
Black Stone Minerals, L.P. ContactBrent CollinsVice
President, Investor RelationsTelephone: (713) 445-3200investorrelations@blackstoneminerals.com
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