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 2016
and provides guidance for 2017.
Highlights
- Full year 2016 production of 31.7
MBoe/d, at the high end of annual guidance.
- Reported 2016 net income of $20.2
million and Adjusted EBITDA of $262.3 million.
- Proved reserves at year-end 2016
totaled 63.4 MMBoe, an increase of 27% over prior year driven
largely by development activity in the East Texas
Haynesville/Bossier play, and were approximately 78% proved
developed producing.
- Fourth quarter 2016 production, net
loss, and Adjusted EBITDA of 29.8 MBoe/d, $7.3 million, and $58.3
million, respectively.
- Production for 2017 expected to average
35.0 – 37.0 MBoe/d, a 14% increase over 2016 average daily volumes
at the mid-point of guidance.
- Entered into a farmout agreement in
February 2017 that will substantially reduce Black Stone’s future
working interest capital requirements and generate additional
royalty income, while facilitating continued development of the
Partnership’s East Texas Haynesville/Bossier acreage.
Management Commentary
“Black Stone had a very solid 2016 and we are off to a strong
start in 2017,” stated Thomas L. Carter, Jr., Black Stone Minerals’
President, Chief Executive Officer, and Chairman. “We grew
production in 2016 by 11% and came in at the upper end of our
production guidance, which we had increased mid-year, and we expect
to deliver even greater growth in 2017. Our recent acquisitions
have added to our core minerals positions in the Delaware, Midland,
and Haynesville plays where we are seeing robust producer activity,
and our recently announced farmout in East Texas will meaningfully
reduce our working interest capital expenditures going forward and
generate greater free cash flow for increased distributions.”
Mr. Carter continued, “Based on our current initiatives and our
long-term outlook for our diverse mineral portfolio, we are
confident that we will be able to fully replace the declining
working interest production resulting from the farmout agreement
with increasing royalty volumes, which will allow us to deliver
long-term production and cash flow growth. We are well positioned
to continue building long-term value for our unitholders.”
Quarterly Financial and Operating Results
Production
Black Stone Minerals reported average production of 29.8 MBoe/d
for the fourth quarter of 2016, representing an increase of 10%
from the corresponding period in 2015. Mineral and royalty volumes
made up 62% of the Partnership’s total reported volumes in the
fourth quarter of 2016.
Reported volumes in the fourth quarter of 2016 were negatively
impacted by production shut-ins estimated at 1.0 MBoe/d for the
quarter related to offset completion work and processing plant
downtime in the Haynesville Shale, as well as by a number of
non-recurring items. The Partnership exited the year at a run-rate
of approximately 31.5 MBoe/d, including the impact of shut-in
wells.
Realized Prices, Revenues, and Net Loss
The Partnership’s average realized price per Boe, excluding the
effect of derivative settlements, was $27.29 for the quarter ended
December 31, 2016, an increase of 13% from $24.15 per Boe for the
corresponding quarter last year.
Black Stone Minerals reported oil and gas revenues of $74.9
million in the fourth quarter of 2016, an increase of 24% from
$60.2 million in the fourth quarter of 2015. The increase reflects
higher reported production volumes as well as modestly higher
commodity prices compared to the corresponding period in 2015.
The Partnership reported a loss on commodity derivative
instruments of $24.2 million for the fourth quarter of 2016, which
comprised a $5.6 million gain from realized settlements and a $29.8
million unrealized loss due to the change in value of Black Stone’s
derivative positions during the quarter.
Lease bonus and other income was $6.0 million for the fourth
quarter of 2016, compared to $7.0 million for the same period last
year.
The Partnership reported a net loss of $7.3 million for the
quarter ended December 31, 2016, compared to a net loss of $49.7
million in the corresponding period in 2015. Adjusted EBITDA for
the fourth quarter of 2016, which reflects the impact of the
adverse production impacts mentioned earlier, was $58.3 million, as
compared to $54.0 million for the fourth quarter of 2015.
2016 Proved Reserves
Estimated proved oil and natural gas reserves at year-end 2016
were 63.4 MMBoe, an increase of 27% from 49.8 MMBoe at year-end
2015, and were approximately 29% oil and 78% proved developed
producing. The discounted net cash flow of proved reserves
discounted at 10% (“PV-10”) was $603.0 million at the end of 2016
as compared to $555.0 million at year-end 2015.
Netherland Sewell & Associates, an independent petroleum
engineering firm, prepared the estimate of Black Stone Minerals’
proved reserves and PV-10 at December 31, 2016 using reference
prices of $42.75 per barrel of oil and $2.48 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
As of December 31, 2016, Black Stone Minerals had $316.0 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, 2016 was
$500 million. Black Stone’s regularly scheduled borrowing base
redetermination is set for April 2017. As of February 27, 2017,
$394.0 million was outstanding under the credit facility, which
includes borrowings related to the consummation of recent
acquisitions discussed below and the distribution payment related
to the fourth quarter of 2016.
Fourth Quarter 2016 Distributions
As previously announced, the Board of Directors of the general
partner approved a cash distribution of $0.2875 per common unit and
$0.18375 per subordinated unit attributable to the fourth quarter
of 2016. The quarterly distribution coverage ratio was
approximately 1.1x for all classes of units (1.8x for common
units). These distributions were paid earlier today.
Acquisition Activity
The Partnership closed several acquisitions totaling $141.1
million in 2016. These included the $87.6 million acquisition of
diverse minerals from Freeport-McMoRan, the $34.0 million
acquisition of mineral assets in the Wattenberg Field in Colorado,
and two smaller transactions in the Midland Basin. Black Stone has
completed multiple transactions to date in 2017 totaling
approximately $58 million, with approximately $43 million and $15
million focused in the Delaware Basin and Haynesville/Bossier play,
respectively. In one transaction, $11.8 million of the purchase
price was paid in Black Stone Minerals’ common units, which marked
the first time since going public the Partnership has directly used
its equity in a transaction. Since its IPO in May of 2015, Black
Stone has closed on approximately $260 million of acquisitions.
“We are off to a strong start on the acquisition front already
in 2017. We’ve added acreage in the best part of the Delaware
Basin, which we think is going to get developed very quickly. In
the Haynesville, we’re having some success adding positions around
acreage that we already control in East Texas. We think this will
allow us to influence the development of those assets in a way that
will accelerate drilling activity for the next several years,”
commented Mr. Carter. “I am particularly pleased that we were able
to use direct equity in an acquisition. Having a currency that
provides diversification and liquidity in a tax-efficient manner
for potential sellers was one of the reasons we went public, and I
think we’ll be able to do more of this in the future.”
Farmout of Working Interests
On February 21, 2017, Black Stone announced it had entered into
a farmout agreement that will reduce Black Stone’s future working
interest capital expenditures and will generate additional royalty
income through a retained overriding royalty interest. The farmout
covers the Partnership’s working interests within an approximate
34,000 gross acre block in San Augustine County, Texas that is
currently under development for the Haynesville/Bossier play. Black
Stone expects the farmout agreement to reduce its capital
obligations by approximately $30-$35 million in 2017 and by an
average of $40-$50 million annually over the initial six years
covered under the agreement.
Summary 2017 Guidance
Key assumptions in Black Stone Minerals’ 2017 program are as
follows:
FY2017 Average daily production
(MBoe/d) 35.0 – 37.0 Percentage oil ~25% Percentage royalty
interest ~60% Lease bonus and other income ($MM) $25 – $35
Lease operating expense ($MM) $18 – $22 Production costs and ad
valorem taxes (as % of total pre-derivative O&G revenue) 13% –
15% Exploration expense ($MM) $0.5 – $1.5 G&A – cash
($MM) $41.0 – $43.0 G&A – non-cash ($MM)
$25.0 –
$27.0 G&A – TOTAL ($MM) $66.0 – $70.0 DD&A
($/Boe) $8.50 – $9.50
Working Interest Participation
Black Stone Minerals expects to invest approximately $50 to $60
million in its working interest participation program in 2017, the
vast majority of which relates to opportunities in the East Texas
Haynesville/Bossier play. Approximately $40 million relates to 13
wells that were spud in 2016 but will be completed in 2017. Those
wells are not covered by the previously announced farmout
agreement, which reduces Black Stone’s working interest by 80% in
the Haynesville/Bossier play within certain areas in San Augustine
County, Texas for wells spud after January 1, 2017. As a result of
the farmout, the Partnership expects its annual capital investment
related to these assets going forward to range from $10 million to
$15 million, depending on the actual number of wells drilled and
completed each year.
The Partnership’s working interest production is anticipated to
average approximately 40% of total production in 2017, and decline
thereafter to management's long-term target of less than 20%.
Hedge Position
The Partnership has commodity derivative contracts in place
covering a substantial part of 2017’s anticipated production. Based
on the guided volumes above, approximately 65% of expected oil
volumes are hedged at prices averaging $55.18 per barrel, and
approximately 75% of expected gas volumes are hedged at prices
averaging $3.16 per Mcf. The Partnership has also added hedges
covering portions of expected 2018 oil and natural gas production.
More detailed information regarding the Partnership’s existing
hedge position can be found in the Annual Report on Form 10-K for
2016, which is expected to be filed on or around March 1, 2017.
Subordinated Unit Conversion Outlook
Black Stone’s subordinated units first become eligible for
conversion into common units on March 31, 2019. In recent
discussions regarding the subordinated unit conversion, the Board
of Directors has emphasized its belief in the critical importance
of having a strong, growing common distribution as the Partnership
exits the conversion period. Accordingly, management and the Board
recognize that the subordinated units may need to be converted at a
ratio of less than one-to-one to facilitate the continued growth of
the common distribution and have agreed that decisions pertaining
to the conversion of subordinated units will be made in the context
of positioning the common units for future distribution growth.
Mr. Carter commented, “Our primary goal at Black Stone is to
deliver long-term value to our unitholders, which we believe
requires a growing common distribution. One of the factors
affecting our ability to continue to grow common distributions, in
addition to actual distributable cash flow, is the impact of the
conversion of the subordinated units and the resulting number of
total common units outstanding after conversion. While we are
sensitive to the potential dilution of our subordinated unit
holders if conversion takes place at less than a one-to-one ratio,
we and the Board are placing a high priority on sustained common
unit distribution growth.”
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 2016 on Tuesday, February 28, 2017 at 9:00
a.m. Central Time. To join the call, participants should dial (877)
447-4732 and use conference code 58697648. 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,
2017.
Upcoming Investor Relations Events
Members of management from Black Stone Minerals will also be
participating in the following investor events:
- EnerCom Dallas Investors Conference –
March 2, 2017 in Dallas, Texas. Management will be participating in
one-on-one meetings throughout the day and is scheduled to present
at 10:05 a.m. Central time. A webcast for this presentation will be
available in the Investors section of the BSM website.
- Scotia Howard Weil 45th Annual Energy
Conference – March 28, 2017 in New Orleans, Louisiana. Management
will participate in one-on-one meetings throughout the day.
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 over 40 states and
60 onshore basins in the continental United States. The
Partnership also owns and selectively participates as a
non-operating working 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;
- 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 EndedDecember
31,
Year EndedDecember 31,
2016 2015 2016
2015 REVENUE Oil and condensate sales $ 37,801 $ 36,954 $
142,382 $ 163,538 Natural gas and natural gas liquids sales 37,130
23,219 122,836 116,018 Gain (loss) on commodity derivative
instruments (24,169 ) 32,838 (36,464 ) 90,288 Lease bonus and other
income 5,950 7,029 32,079 23,080 TOTAL
REVENUE 56,712 100,040 260,833 392,924
OPERATING (INCOME) EXPENSE Lease operating expense 4,576 5,043
18,755 21,583 Production costs and ad valorem taxes 12,163 9,517
35,464 35,767 Exploration expense 2 578 645 2,592 Depreciation,
depletion, and amortization 22,833 20,884 102,487 104,298
Impairment of oil and natural gas properties — 92,886 6,775 249,569
General and administrative 20,926 23,645 73,139 77,175 Accretion of
asset retirement obligations 212 270 892 1,075 (Gain) loss on sale
of assets, net (21 ) (4,853 ) (4,793 ) (4,873 ) Other expense —
1,593 — 1,593
TOTAL OPERATING EXPENSE 60,691 149,563
233,364 488,779 INCOME (LOSS) FROM OPERATIONS
(3,979 ) (49,523 ) 27,469 (95,855 ) OTHER INCOME (EXPENSE) Interest
and investment income 5 12 656 58 Interest expense (2,774 ) (888 )
(7,547 ) (6,418 ) Other income (538 ) 669 (390 ) 910
TOTAL OTHER EXPENSE (3,307 ) (207 ) (7,281 ) (5,450 ) NET INCOME
(LOSS) (7,286 ) (49,730 ) 20,188 (101,305 ) NET (INCOME) LOSS
ATTRIBUTABLE TO PREDECESSOR — — (450 ) NET (INCOME) LOSS
ATTRIBUTABLE TO NONCONTROLLING INTERESTS SUBSEQUENT TO INITIAL
PUBLIC OFFERING (3 ) 1,123 12 1,260 DISTRIBUTIONS ON REDEEMABLE
PREFERRED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING (1,324 )
(2,739 ) (5,763 ) (7,522 ) NET INCOME (LOSS) ATTRIBUTABLE TO THE
GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO
INITIAL PUBLIC OFFERING $ (8,613 ) $ (51,346 ) $ 14,437 $
(108,017 ) ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL
PUBLIC OFFERING ATTRIBUTABLE TO: General partner interest $ — $ — $
— $ — Common units 326 (25,824 ) 24,669 (54,326 ) Subordinated
units (8,939 ) (25,522 ) (10,232 ) (53,691 ) $ (8,613 ) $ (51,346 )
$ 14,437 $ (108,017 ) NET INCOME (LOSS) ATTRIBUTABLE TO
LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit
(basic) $ 0.01 $ (0.27 ) $ 0.26 $ (0.56 ) Weighted
average common units outstanding (basic) 95,725 96,182
96,073 96,182 Per subordinated unit (basic) $
(0.10 ) $ (0.27 ) $ (0.11 ) $ (0.56 ) Weighted average subordinated
units outstanding (basic) 95,180 95,057 95,138
95,057 Per common unit (diluted) $ 0.01 $ 0.27
$ 0.26 $ (0.56 ) Weighted average common units outstanding
(diluted) 95,895 96,182 96,439 96,182
Per subordinated unit (diluted) $ (0.10 ) $ 0.27 $ (0.11 ) $
(0.56 ) Weighted average subordinated units outstanding (diluted)
95,180 95,057 95,394 95,057
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC
OFFERING: Per common unit $ 0.2875 $ 0.2625 $ 1.1000
$ 0.4240 Per subordinated unit $ 0.1838 $
0.2625 $ 0.7350 $ 0.4240
The following table shows the Partnership’s production,
revenues, realized prices, and expenses for the periods
presented.
Three Months EndedDecember
31,
Year EndedDecember 31,
2016 2015 2016
2015
(Unaudited)(Dollars in
thousands, except for realized prices)
Production: Oil and condensate (MBbls)1 832 897 3,680 3,565
Natural gas (MMcf)1 11,484 9,572 47,498 41,389
Equivalents (MBoe) 2,746 2,492 11,596 10,463
Revenue: Oil
and condensate sales $ 37,801 $ 36,954 $ 142,382 $ 163,538 Natural
gas and natural gas liquids sales 37,130 23,219 122,836 116,018
Gain (loss) on commodity derivative instruments (24,169 ) 32,838
(36,464 ) 90,288 Lease bonus and other income 5,950 7,029
32,079 23,080 Total revenue $ 56,712 $ 100,040 $
260,833 $ 392,924
Realized prices: Oil and condensate
($/Bbl) $ 45.43 $ 41.20 $ 38.69 $ 45.87 Natural gas ($/Mcf)1 $ 3.23
$ 2.43 $ 2.59 $ 2.80 Equivalents ($/Boe) $
27.29 $ 24.15 $ 22.87 $ 26.72
Operating expenses: Lease
operating expense $ 4,576 $ 5,043 $ 18,755 $ 21,583 Production
costs and ad valorem taxes 12,163 9,517 35,464 35,767 Exploration
expense 2 578 645 2,592 Depreciation, depletion, and amortization
22,833 20,884 102,487 104,298 Impairment of oil and natural gas
properties — 92,886 6,775 249,569 General and administrative 20,926
23,645 73,139 77,175
Other expense: Interest expense 2,774
888 7,547 6,418
Per Boe: Lease operating expense (per
working interest Boe) 4.35 7.11 4.62 4.32 Production costs and ad
valorem taxes 4.43 3.82 3.06 3.42 Depreciation, depletion, and
amortization 8.32 8.38 8.84 9.97 General and administrative 7.62
9.49 6.31 7.38
____________
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
EBITDA, Adjusted EBITDA, and cash available for distribution are
non-GAAP supplemental financial measures used by Black Stone
Minerals’ management and external users of the Partnership’s
financial statements such as investors, research analysts, and
others, to assess the financial performance of its assets and its
ability to sustain distributions over the long term without regard
to financing methods, capital structure, or historical cost
basis.
Black Stone Minerals defines EBITDA as net income (loss) before
interest expense, income taxes and depreciation, depletion, and
amortization. Black Stone Minerals defines Adjusted EBITDA as
EBITDA adjusted for impairment of oil and natural gas properties,
accretion of asset retirement obligations, unrealized gains/losses
on commodity derivative instruments, and non-cash equity-based
compensation. Black Stone Minerals defines cash available for
distribution as Adjusted EBITDA plus or minus amounts for certain
non-cash operating activities, estimated replacement capital
expenditures, capital expenditures, cash interest expense, and
distributions to noncontrolling interests and preferred
unitholders.
EBITDA, Adjusted EBITDA, and cash available for distribution
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 as measures of the
Partnership’s financial performance. EBITDA, Adjusted EBITDA, and
cash available for distribution 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 EBITDA,
Adjusted EBITDA, and cash available for distribution may differ
from computations of similarly titled measures of other
companies.
The following table presents a reconciliation of EBITDA,
Adjusted EBITDA, and cash available for distribution to net income,
the most directly comparable GAAP financial measure, for the
periods indicated.
Three Months EndedDecember
31,
Year EndedDecember 31,
2016 2015 2016
2015
(Unaudited)(In
thousands)
(Unaudited)(In
thousands)
Net income (loss) $ (7,286 ) $ (49,730 ) $ 20,188 $ (101,305 )
Adjustments to reconcile to Adjusted EBITDA: Add: Depreciation,
depletion and amortization 22,833 20,884 102,487 104,298 Interest
expense 2,774 888 7,547 6,418 EBITDA
18,321 (27,958 ) 130,222 9,411 Add: Impairment of oil and natural
gas properties — 92,886 6,775 249,569 Accretion of asset retirement
obligations 212 270 892 1,075 Equity-based compensation1 10,018
4,948 43,138 18,000 Unrealized loss on commodity derivative
instruments 29,738 — 81,253 — Less: Unrealized gain on commodity
derivative instruments — (16,145 ) — (27,063 )
Adjusted EBITDA 58,289 54,001 262,280 250,992 Adjustments to
reconcile to cash generated from operations: Add: Restructuring
charges — 4,208 — 4,208 Incremental general and administrative
related to initial public offering — 353 — 1,303 Loss on sales of
assets, net
—
—
— — Less: Change in deferred revenue (695 ) (76 ) (870 ) (660 )
Cash interest expense
(2,497
) (677 )
(6,676
) (5,483 ) Gain on sales of assets, net (21 ) (4,853 ) (4,793 )
(4,873 ) Estimated replacement capital expenditures2 (3,750 ) —
(11,250 ) — Cash generated from operations
51,326
52,956
238,691
245,487 Less: Cash paid to noncontrolling interests (28 ) (41 )
(111 ) (208 ) Redeemable preferred unit distributions
(1,324
) (2,739 )
(5,763
) (11,562 ) Cash generated from operations available for
distribution on common and subordinated units and reinvestment in
our business $
49,974
$ 50,176 $
232,817
$ 233,717
____________
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 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.
Proved Oil & Gas Reserve Quantities
A rollforward of proved reserves is presented in the following
table:
Crude Oil
(MBbl)
Natural Gas
(MMcf)
Total
(MBoe)
Net proved reserves at December 31, 2015 15,842 203,675 49,788
Revisions of previous estimates 3,007 29,024 7,844 Purchases of
minerals in place 1,322 5,683 2,269 Extensions, discoveries, and
other additions 1,877 79,455 15,120 Production (3,680 ) (47,498 )
(11,596 ) Net proved reserves at December 31, 2016 18,368
270,339 63,425 Net Proved Developed Reserves December
31, 2015 15,497 174,555 44,590 December 31, 2016 18,150 223,057
55,327 Net Proved Undeveloped Reserves December 31, 2015 345 29,120
5,198 December 31, 2016 218 47,282 8,098
View source
version on businesswire.com: http://www.businesswire.com/news/home/20170227006590/en/
Black Stone Minerals, L.P.Brent Collins, 713-445-3200Vice
President, Investor
Relationsinvestorrelations@blackstoneminerals.com
Black Stone Minerals (NYSE:BSM)
Historical Stock Chart
From Jun 2024 to Jul 2024
Black Stone Minerals (NYSE:BSM)
Historical Stock Chart
From Jul 2023 to Jul 2024