Black Stone Minerals, L.P. (NYSE: BSM) ("Black Stone Minerals,"
"Black Stone," or "the Partnership") today announces its financial
and operating results for the second quarter of 2018 and recent
developments after quarter-end.
Highlights
- Reported total quarterly production of
44.7 Mboe/d, an increase of 5% over the first quarter of 2018.
Royalty volumes increased by 9% over first quarter while working
interest volumes declined by 2%.
- Reported oil and gas revenues of $131.1
million and lease bonus and other income of $11.6 million for the
quarter.
- Generated net income of $28.7 million
and Adjusted EBITDA of $100.3 million.
- Announced an 8% increase in
distributions per common unit for the second quarter.
- Reported distributable cash flow of
$87.2 million, resulting in distribution coverage for all units of
1.3x on increased distribution level.
- Production guidance for 2018 increased
to a range of 44.5 to 45.5 MBoe/d, a 7% increase midpoint to
midpoint from prior guidance.
- Acquired $26.5 million in mineral and
royalty assets for cash during the second quarter in Permian Basin
and East Texas, and closed on an approximately $17 million of
additional mineral and royalty assets subsequent to quarter
end.
Management Commentary
Thomas L. Carter, Jr., Black Stone Minerals’ Chief Executive
Officer and Chairman, commented, "The second quarter was another
strong quarter for Black Stone Minerals and we are performing well
on a number of fronts. We are raising our production guidance for
the full year to a midpoint of 45 MBoe/d, which implies continued
production growth in the back half of the year off a very strong
first six months. We're seeing a lot of activity on our acreage in
the first half of 2018, which puts us on pace to handily beat the
number of wells we added in 2017. I'd also add that our undeveloped
acreage continues to attract interest from industry as demonstrated
by the nearly $12 million in lease bonus we collected in the
quarter. Based on our strong operational and financial performance,
we are increasing the distribution for both common and subordinated
units to an annualized rate of $1.35 per unit while retaining a
healthy amount of cash flow to support the growth of the business.
Based on our closing price as of Friday, that equates to a current
distribution yield of 7.9%, and our distributable cash flow yield
is 10.0% which is well in excess of that of our direct peers. I
think Black Stone represents a tremendous opportunity for long-term
investors who want exposure to diverse, actively managed mineral
and royalty assets."
Quarterly Financial and Operating Results
Production
Black Stone reported average production of 44.7 MBoe/d (69%
mineral and royalty, 71% natural gas) for the second quarter of
2018. This represents an increase of 20% over average production of
37.3 MBoe/d for the corresponding period in 2017 and is 5% higher
than average daily production in the first quarter of 2018. Oil
production for the period was essentially flat with record levels
reported in the first quarter of 2018. Natural gas production
increased by 9% from the first quarter of 2018 due in large part to
a significant number of East Texas Haynesville/Bossier wells being
turned to sales in the second quarter, including the last wells not
covered by the Partnership's farmout arrangements in the Shelby
Trough.
Realized Prices, Revenues, and Net Income
The Partnership’s average realized price per Boe, excluding the
effect of derivative settlements, was $32.22 for the quarter ended
June 30, 2018. This represents a 3% decrease from the
preceding quarter and is 26% higher than the $25.67 per Boe
reported for the quarter ended June 30, 2017.
Black Stone reported oil and gas revenues of $131.1 million (59%
oil and condensate) for the second quarter of 2018, an increase of
50% from $87.2 million for the second quarter of 2017. This
increase in oil and gas revenue was driven by the aforementioned
increases in reported production volumes and realized pricing. Oil
and gas revenue in the first quarter of 2018 was $126.2
million.
The Partnership recognized a loss on commodity derivative
instruments of $33.3 million in the second quarter of 2018,
composed of a $6.3 million loss from realized settlements during
the quarter and a $27.1 million unrealized loss that reflects the
change in value of the Partnership’s derivative positions during
the quarter. In the second quarter of 2017, the Partnership
reported a gain on commodity derivative instruments of $22.0
million which reflected a significant unrealized gain in the
quarter.
Black Stone recognized $11.6 million in lease bonus and other
income in the second quarter of 2018, led by leasing activity in
the Midland and Delaware basins in West Texas with additional
leases written in the Bakken/Three Forks in North Dakota, the
Austin Chalk in East Texas, and the Louisiana portion of the
Haynesville/Bossier trend. The Partnership reported $11.4 million
in lease bonus and other income in the same period in 2017.
The Partnership reported net income of $28.7 million, which
includes the non-cash derivative loss described above, for the
quarter ended June 30, 2018, compared to net income of $54.2
million in the corresponding period in 2017.
Adjusted EBITDA and Distributable Cash Flow
Black Stone reported new quarterly records as a public company
for both Adjusted EBITDA and distributable cash flow in the second
quarter of 2018. Adjusted EBITDA was $100.3 million for the second
quarter of 2018, compared to $74.7 million for the corresponding
quarter in 2017 and $95.0 million in the first quarter of 2018.
Distributable cash flow for the second quarter of 2018 was $87.2
million, an increase of 32% from the $66.3 million reported in the
second quarter of 2017 and a 5% increase from the $83.4 million in
the first quarter of 2018. The Partnership expects to distribute
approximately $68 million to unitholders with respect to the second
quarter with the balance invested in the continued growth of the
business.
Financial Position
As of June 30, 2018, the Partnership had $7.1 million in cash
and $421.0 million outstanding under its credit facility. As of
August 3, 2018 and taking into account the acquisitions closed
subsequent to the end of the second quarter, the Partnership had
$395.0 million outstanding under the credit facility and $18.9
million in cash, providing $223.9 million in available liquidity.
Black Stone Minerals is in compliance with all financial covenants
associated with its credit facility.
Hedge Position
Black Stone has commodity derivative contracts in place covering
portions of its anticipated production for the remainder of 2018 as
well as 2019 and 2020. For the balance of 2018, approximately 72%
of expected oil volumes are hedged at prices averaging $55.23 per
barrel and approximately 73% of expected gas volumes are hedged at
prices averaging $3.01 per Mcf through the use of swaps. For 2019,
the Partnership has used swaps to hedge 645 MBbl of oil per quarter
at prices averaging $58.43 per barrel and an average of 7,250 MMcf
of natural gas per quarter at an average price of $2.86 per Mcf.
For 2020, Black Stone has entered into costless collars covering
150 MBbl per quarter at a range of $55.00 to $65.75 per barrel.
More detailed information about the Partnership's existing hedge
position can be found in the Quarterly Report on Form 10-Q for the
second quarter of 2018, which is expected to be filed on or around
August 7, 2018.
Acquisitions
Black Stone acquired $26.5 million of properties for cash in the
second quarter of 2018. Included in that amount was a $14.6 million
mineral package with assets located in the Midland and Delaware
basins. Additionally, the Partnership spent $11.9 million in cash
to further consolidate its acreage position in the Shelby Trough
area in East Texas.
Subsequent to quarter end, Black Stone closed on the acquisition
of approximately $17 million of additional mineral and royalty
assets, which included $10.8 million of assets which share common
underlying properties as those acquired in the Noble Acquisition
that was completed in late 2017. Year to date, the Partnership has
acquired over $75 million of mineral and royalty properties.
Development Capital Expenditures
The Partnership invested a net total of $4.4 million in
development capital (working interest participation and drilling
activities) during the second quarter of 2018, inclusive of $23.0
million in reimbursements from farmout partners. As a result of the
previously announced farmouts with Canaan Resource Partners and
Pivotal Petroleum Partners, substantially all capital expenditures
made by Black Stone to drill and complete Haynesville/Bossier wells
in the Shelby Trough area of East Texas are reimbursed by those
partners. The vast majority of net development capital for the
quarter relates to activity related to the delineation of the
PepperJack prospect in Hardin and Liberty counties, Texas.
Through the first six months of 2018, the Partnership invested a
total of $32.6 million in net development capital expenditures.
Black Stone spent $20.7 million in the first half of 2018 on
working interest participation capital related primarily to
Haynesville/Bossier development in the Shelby Trough, net of
farmout reimbursements. Black Stone also spent $11.9 million in the
first half of 2018 delineating its PepperJack prospect targeting
the Lower Wilcox formation. The PepperJack A#1 well was drilled and
logged during the fourth quarter of 2017 and the first quarter of
2018. The Partnership believes the well is highly prospective and
will be completed as a commercially productive well. The PepperJack
B#1 well was a significant step-out from the PepperJack A#1 well,
and was drilled and logged during the second quarter of 2018. Black
Stone does not believe this well will be completed in the near term
and accordingly recognized $6.7 million of exploration expense in
the second quarter of 2018 for the costs associated with the
PepperJack B#1. The Partnership is in active negotiations with
industry operating partners for third-party development of the
PepperJack prospect.
Given the current farmout agreements in place, the Partnership
expects negligible development capital expenditures related to
working interest participation for the remainder of 2018.
Distributions
The Board of Directors of the general partner (the "Board") has
approved cash distributions attributable to the second quarter of
2018 of $0.3375 per unit for both common and subordinated units.
This represents an approximate 8% increase to the distribution for
common unitholders from the previous quarter. The quarterly
distribution coverage ratio attributable to the second quarter of
2018 was approximately 1.3x for all units. Distributions will be
payable on August 23, 2018 to unitholders of record on August 16,
2018.
Revised 2018 Guidance
The following table provides the assumptions for Black Stone's
original and current 2018 guidance:
Original Guidance
Revised Guidance
Average daily production (MBoe/d) 41 - 43 44.5 - 45.5 Percentage
natural gas ~75% ~71% Percentage royalty interest ~65% ~68%
Lease bonus and other income ($MM) $30 - $40 $30 - $40 Lease
operating expense ($MM) $15 - $19 $16 - $18 Production costs and ad
valorem taxes (as % of total pre-derivative O&G revenue) 12% -
14% 11% - 13% Exploration expense ($MM) $1.5 - $2.5 $7.5 - $8.5
G&A - cash ($MM) $45 - $47 $45 - $47 G&A - non-cash
($MM)
$28 - $30 $30 - $32
G&A - total ($MM)
$73 - $77 $75 - $79 DD&A ($/Boe) $8.00 - $9.00 $7.00 -
$8.00
Conference Call
Black Stone Minerals will host a conference call and webcast for
investors and analysts to discuss its results for the second
quarter of 2018 on Tuesday, August 7, 2018 at 9:00 a.m. Central
Time. To join the call, participants should dial (877) 447-4732 and
use conference code 3916319. 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 September 7, 2018.
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;
- 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.
For an important discussion of risks and uncertainties that may
impact our operations, see our annual and quarterly filings with
the Securities and Exchange Commission, which are available on our
website.
Information for Non-U.S. Investors
This press release is intended to be a qualified notice under
Treasury Regulation Section 1.1446-4(b). Although a portion of
Black Stone Minerals’ income may not be effectively connected
income and may be subject to alternative withholding procedures,
brokers and nominees should treat 100% of Black Stone Minerals’
distributions to non-U.S. investors as being attributable to income
that is effectively connected with a United States trade or
business. Accordingly, Black Stone Minerals’ distributions to
non-U.S. investors are subject to federal income tax withholding at
the highest marginal rate, currently 37.0% for individuals.
BLACK STONE MINERALS, L.P.
CONSOLIDATED STATEMENTS OF
OPERATIONS
(Unaudited)
(In thousands, except per unit
amounts)
Three Months Ended
Six Months Ended June 30, June 30,
2018 2017 2018
2017 REVENUE Oil and condensate sales $ 77,225 $ 37,262 $
150,208 $ 77,736 Natural gas and natural gas liquids sales 53,854
49,903
107,099
97,604 Lease bonus and other income 11,577 11,356
16,176 25,038 Revenue from contracts with customers
142,656 98,521 273,483 200,378 Gain (loss) on commodity derivative
instruments (33,347 ) 22,003
(49,680 ) 44,728 TOTAL REVENUE 109,309 120,524
223,803 245,106 OPERATING (INCOME) EXPENSE Lease
operating expense 4,290 4,148 8,538 8,337 Production costs and ad
valorem taxes 14,373 11,863 29,298 23,765 Exploration expense 6,745
46 6,748 608 Depreciation, depletion, and amortization 30,292
28,900 58,862 55,279 General and administrative 19,812 17,481
38,333 34,693 Accretion of asset retirement obligations 273 253 542
500 (Gain) loss on sale of assets, net — (7 ) (2 ) (931 )
TOTAL OPERATING EXPENSE 75,785 62,684 142,319
122,251 INCOME (LOSS) FROM OPERATIONS 33,524 57,840 81,484
122,855 OTHER INCOME (EXPENSE) Interest and investment income 37 33
70 39 Interest expense (5,280 ) (3,981 ) (9,801 ) (7,488 ) Other
income (expense) 409 282 (1,106 ) 351 TOTAL
OTHER EXPENSE (4,834 ) (3,666 ) (10,837 ) (7,098 ) NET INCOME
(LOSS) 28,690 54,174 70,647 115,757 Net (income) loss attributable
to noncontrolling interests 48 16 22 7 Distributions on Series A
redeemable preferred units — (672 ) (25 ) (1,786 ) Distributions on
Series B cumulative convertible preferred units (5,250 ) —
(10,500 ) — NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL
PARTNER AND COMMON AND SUBORDINATED UNITS $ 23,488 $ 53,518
$ 60,144 $ 113,978 ALLOCATION OF NET INCOME
(LOSS): General partner interest $ — $ — $ — $ — Common units
17,540 32,100 41,884 67,617 Subordinated units 5,948 21,418
18,260 46,361 $ 23,488 $ 53,518
$ 60,144 $ 113,978 NET INCOME (LOSS) ATTRIBUTABLE TO
LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit
(basic) $ 0.17 $ 0.33 $ 0.40 $ 0.69
Weighted average common units outstanding (basic) 105,250
97,990
103,937 97,448 Per subordinated unit (basic) $ 0.06
$ 0.22 $ 0.19 $ 0.49 Weighted average
subordinated units outstanding (basic) 96,329 95,388
95,395 95,269 Per common unit (diluted) $ 0.17
$ 0.33 $ 0.40 $ 0.69 Weighted average common
units outstanding (diluted) 105,250 97,990
103,937 97,448 Per subordinated unit (diluted) $ 0.06
$ 0.22 $ 0.19 $ 0.49 Weighted average
subordinated units outstanding (diluted) 96,329 95,388
95,395 95,269 DISTRIBUTIONS DECLARED AND PAID: Per
common unit $ 0.3125 $ 0.2875 $ 0.6250 $
0.5750 Per subordinated unit $ 0.2087 $ 0.1838
$ 0.4175 $ 0.3675
The following table shows the Partnership’s production,
revenues, realized prices, and expenses for the periods
presented.
Three Months Ended June
30, Six Months Ended June 30,
2018 2017 2018
2017 (Unaudited)
(Dollars in thousands, except for
realized prices and per Boe data)
Production:
Oil and condensate (MBbls) 1,183 824 2,372 1,685 Natural gas
(MMcf)1 17,311 15,425 33,052 29,485
Equivalents (MBoe)
4,068 3,395 7,881 6,599
Equivalents/day (MBoe)
44.7
37.3
43.5
36.5
Revenue: Oil and condensate sales $ 77,225 $ 37,262 $
150,208 $ 77,736 Natural gas and natural gas liquids sales1 53,854
49,903 107,099 97,604 Lease bonus and other income 11,577
11,356 16,176 25,038 Revenue from contracts
with customers 142,656 98,521 273,483 200,378 Gain (loss) on
commodity derivative instruments (33,347 ) 22,003 (49,680 )
44,728 Total revenue $ 109,309 $ 120,524 $ 223,803
$
245,106
Realized prices: Oil and condensate ($/Bbl) $ 65.28 $ 45.22
$ 63.33 $ 46.13 Natural gas ($/Mcf)1 3.11 3.24 3.24
3.31 Equivalents ($/Boe) $ 32.22 $ 25.67 $ 32.65 $
26.57
Operating expenses: Lease operating expense $ 4,290 $
4,148 $ 8,538 $ 8,337 Production costs and ad valorem taxes 14,373
11,863 29,298 23,765 Exploration expense 6,745 46 6,748 608
Depreciation, depletion, and amortization 30,292 28,900 58,862
55,279 General and administrative 19,812 17,481 38,333 34,693
Per Boe: Lease operating expense (per working interest Boe)
$ 3.45 $ 2.83 $ 3.42 $ 3.00 Production costs and ad valorem taxes
3.53 3.49 3.72 3.60 Depreciation, depletion, and amortization 7.45
8.51 7.47 8.38 General and administrative 4.87 5.15 4.86 5.26
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
(“GAAP”) in the United States 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 GAAP financial measure. Our computation of Adjusted
EBITDA and distributable cash flow may differ from computations of
similarly titled measures of other companies.
Three Months Ended June
30, Six Months Ended June 30,
2018 2017 2018
2017 (Unaudited)
(In thousands, except per unit
amounts)
Net income $ 28,690 $ 54,174 $ 70,647 $ 115,757 Adjustments to
reconcile to Adjusted EBITDA: Depreciation, depletion, and
amortization 30,292 28,900 58,862 55,279 Interest expense 5,280
3,981 9,801 7,488 Income tax expense (446 ) — 1,061 — Accretion of
asset retirement obligations 273 253 542 500 Equity–based
compensation 9,124 6,278 15,350 10,939 Unrealized (gain) loss on
commodity derivative instruments 27,057 (18,921 )
39,015 (37,368 ) Adjusted EBITDA 100,270 74,665 195,278
152,595 Adjustments to reconcile to distributable cash flow:
Deferred revenue (1 ) (643 ) 1,302 (969 ) Cash interest expense
(4,969 ) (3,760 ) (9,285 ) (7,053 ) (Gain) loss on sale of assets,
net — (7 ) (2 ) (931 ) Estimated replacement capital expenditures1
(2,750 ) (3,250 ) (6,000 ) (7,000 ) Cash paid to noncontrolling
interests (62 ) (41 ) (114 ) (66 ) Preferred unit distributions
(5,250 ) (672 ) (10,525 ) (1,786 ) Distributable cash flow $ 87,238
$ 66,292 $ 170,654 $ 134,790
Total units outstanding2
202,364
196,648 Distributable cash flow per unit $ 0.431 $ 0.337 Common
unit price as of August 3, 2018 $ 17.17 Implied distributable cash
flow yield 10.0 %
1
On August 3, 2016, the Board approved a
replacement capital expenditure 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.
2
The distribution attributable to the three
months ended June 30, 2018 is estimated using 106,035 common units
and 96,329 subordinated units as of August 1, 2018; the exact
amount of the distribution attributable to the three months ended
June 30, 2018 will be determined based on units outstanding as of
the record date of August 16, 2018. Distributions attributable
to the three months ended June 30, 2017 were calculated using
101,260 common units and 95,388 subordinated units as of the record
date of August 17, 2017.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20180806005641/en/
Black Stone Minerals, L.P.Brent Collins, 713-445-3200Vice
President, Investor Relationsinvestorrelations@blackstoneminerals.com
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