Market Overview

Black Stone Minerals, L.P. Reports Record Quarterly Results and Declares Increased Cash Distribution on Common and Subordinated Units; Raises Production Guidance for Full Year 2018

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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.

 

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