Black Stone Minerals, L.P. Reports Second Quarter Results; Raises Production Guidance for 2019

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Black Stone Minerals, L.P. Reports Second Quarter Results; Raises Production Guidance for 2019

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 2019.
Highlights
Reported record production of 52.2 MBoe/d for the second quarter of 2019, led by a 19% quarter-over-quarter increase in royalty production.

Reported oil and natural gas revenues of $127.7 million, lease bonus and other income of $6.7 million, and net income of $95.1 million for the quarter.

Generated Adjusted EBITDA for the second quarter of $108.3 million.

Reported Distributable cash flow of $98.0 million, resulting in distribution coverage for all common units of 1.3x at the previously announced distribution attributable to the second quarter of $0.37 per unit or $1.48 annualized.

Raised production guidance for 2019 to range of 47.5 MBoe/d to 50.5 MBoe/d, a 5% increase midpoint to midpoint from prior guidance.

Acquired $20.7 million in mineral and royalty assets in the Permian Basin and in East Texas for cash during the second quarter.
Management Commentary
Thomas L. Carter, Jr., Black Stone Minerals’ Chief Executive Officer and Chairman, commented, “Despite a challenging environment for the broader energy sector, Black Stone posted a solid quarter with new records for both total and royalty volumes. We generated distribution coverage of 1.3x while maintaining the $1.48 per unit annualized distribution. Our excess coverage for the quarter funded substantially all of our acquisition and unit repurchase activity during the period. Based on the success of the first six months of the year, we are increasing our production guidance for the year.”
Quarterly Financial and Operating Results
Production
Black Stone reported average total production of 52.2 MBoe/d (76% mineral and royalty, 72% natural gas) for the second quarter of 2019. This represents a 17% increase over average total production of 44.7 MBoe/d for the corresponding period in 2018 and an increase of 12% from the first quarter of 2019.
Royalty production was 39.7 MBoe/d (66% natural gas) for the second quarter. This is a sequential increase of 19% from the 33.5 MBoe/d reported in the first quarter of 2019. Royalty production in the corresponding period of 2018 was 31.1 MBoe/d.
Consistent with the Partnership’s decision to farm out its working interest participation to third-party capital providers, working interest production continued to decline in the second quarter of 2019 to 12.4 MBoe/d (92% natural gas). This represents declines of 7% and 9%, respectively, from the first quarter of 2019 and the second quarter of 2018.
Realized Prices, Revenues, and Net Income
The Partnership’s average realized price per Boe, excluding the effect of derivative settlements, was $26.90 for the quarter ended June 30, 2019. This represents a 5% decrease from the preceding quarter and reflects lower prices and slightly wider differentials for natural gas and NGLs. Realized prices in the second quarter of 2019 were 17% lower than the $32.22 per Boe reported for the quarter ended June 30, 2018.
Black Stone reported oil and gas revenues of $127.7 million (58% oil and condensate, 42% natural gas and natural gas liquids) for the second quarter of 2019, an increase from $119.3 million in the first quarter of 2019. The increase in oil and gas revenue was driven primarily by higher reported production volumes during the quarter. This increase was partially offset by a lower realized natural gas price for the quarter. Oil and gas revenue in the second quarter of 2018 was $131.1 million.
The Partnership recognized a gain on commodity derivative instruments of $29.2 million in the second quarter of 2019, composed of a $2.9 million realized gain and a $26.3 million unrealized gain that reflects the change in value of the Partnership’s derivative positions during the quarter. Black Stone reported net losses of $41.2 million and $33.3 million on commodity derivative instruments for the quarters ended March 31, 2019 and June 30, 2018, respectively.
Black Stone recognized $6.7 million in lease bonus and other income in the second quarter of 2019, led by leasing activity focused on acreage in the Permian Basin. The Partnership reported $5.6 million and $11.6 million in lease bonus and other income for the first quarter of 2019 and second quarter of 2018, respectively.
The Partnership reported net income of $95.1 million, which includes the non-cash derivative gain described above, for the quarter ended June 30, 2019, compared to net income of $9.0 million in the preceding quarter. Net income for the second quarter of 2018 was $28.7 million.
Adjusted EBITDA and Distributable Cash Flow
Black Stone reported Adjusted EBITDA of $108.3 million for the second quarter of 2019, compared to $94.9 million in the first quarter of 2019 and $100.3 million for the corresponding quarter in 2018. Distributable cash flow for the second quarter of 2019 was $98.0 million, an increase over $81.4 million and $87.2 million in the first quarter of 2019 and second quarter of 2018, respectively.
Financial Position and Activities
As of June 30, 2019, the Partnership had $3.9 million in cash and $436.0 million outstanding under its credit facility.
As of August 2, 2019, the Partnership had $391.0 million outstanding under the credit facility and $6.3 million in cash, providing over $290 million in available liquidity. Black Stone Minerals is in compliance with all financial covenants associated with its credit facility.
During the second quarter of 2019, the Partnership repurchased approximately 137,000 units at an average unit price of $15.90 per unit under the Board-approved $75 million unit repurchase program. This program authorizes Black Stone to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which would permit common units to be repurchased when the Partnership might otherwise be precluded from doing so under applicable laws. Any repurchased units will be canceled.
Hedge Position
Black Stone has commodity derivative contracts in place covering portions of its anticipated production for the remainder of 2019 and 2020. The Partnership’s current hedge position is summarized in the following tables:
Oil Hedge Position
——————– ——————– ——————– ——————– ——————– ——————– ——————– ——————– ——————– ——————– ——————– ——————–
Oil Swap Oil Swap Oil Swap Price Oil Swap Price Oil Costless Oil Costless Oil Costless Collar Floor Collar Floor Collar Ceiling Collar Ceiling
Collars Collars Collars
MBbl MBbl $/Bbl $/Bbl MBbl MBbl MBbl $/Bbl $/Bbl $/Bbl $/Bbl
3Q19 855 855 $58.37 60 $65.00 $74.00
4Q19 855 855 $58.37 60 $65.00 $74.00
1Q20 510 510 $57.14 210 $56.43 $67.14
2Q20 510 510 $57.14 210 $56.43 $67.14
3Q20 510 510 $57.14 210 $56.43 $67.14
4Q20 510 510 $57.14 210 $56.43 $67.14
Natural Gas Hedge
Position
——————– ——————– ——————– ——————– ——————–
Gas Swap Gas Swap Gas Swap Price Gas Swap Price
MMcf MMcf $/Mcf $/Mcf
3Q19 14,640 14,640 $2.96 $2.96
4Q19 14,640 14,640 $2.96 $2.96
1Q20 8,190 8,190 $2.73 $2.73
2Q20 8,190 8,190 $2.73 $2.73
3Q20 8,280 8,280 $2.73 $2.73
4Q20 8,280 8,280 $2.73 $2.73
More detailed information about the Partnership’s existing hedging program can be found in the Quarterly Report on Form 10-Q for the second quarter of 2019, which is expected to be filed on or around August 6, 2019.
Acquisitions
Black Stone acquired $20.7 million of properties in the second quarter of 2019, all of which were purchased with cash. Approximately two-thirds of the acquisitions made during the quarter related to additions in the Permian Basin, with additions in East Texas making up the remainder of the acquisition program for the quarter. Through June 30, 2019, the Partnership has completed $41.6 million in acquisitions in 2019.
Distributions
As previously reported, the Board of Directors of the general partner (the “Board”) has approved cash distributions attributable to the second quarter of 2019 of $0.37 per unit for common units. This represents a quarterly distribution coverage ratio of approximately 1.3x. Distributions will be payable on August 22, 2019 to unitholders of record on August 15, 2019.
Activity Update
Well Additions
For the quarter ended June 30, 2019, Black Stone added 382 gross wells (5.25 net). The Partnership is on track to meet or exceed its 2018 additions of approximately 1,465 gross wells and approximately 21 net wells.
Shelby Trough Update
Black Stone expects drilling activity to slow temporarily on its Shelby Trough acreage in East Texas, in part due to the current natural gas price environment. XTO Energy has informed Black Stone that it intends to complete previously drilled wells and, due to constraints in gathering and treating capacity, will pause new drilling activity in the area until the third quarter of 2020. In addition, BPX Energy (“BPX”) recently decided to limit its Shelby Trough drilling activity to a specific area encompassing approximately 17,000 gross acres. Under the terms of the Partnership’s development agreement with BPX, which requires continuous drilling activity to hold acreage, BPX has released over 100,000 gross acres containing an estimated 6 Tcf of potential recoverable resource. Much of this area has been delineated through BPX’s drilling to date with successful wells in both the Haynesville and Bossier shales, and Black Stone intends to place it with another operator or operators. The Partnership estimates this temporary reduction in drilling activity to have a limited impact to its 2019 outlook.
Black Stone recognizes that the natural gas market globally has current challenges that may persist for some time, but believes that growth in U.S. LNG exports, global increases in energy demand and for natural gas demand in particular, and proximity to Gulf Coast markets bode well for its Shelby Trough acreage. “We own this mineral position in perpetuity and have confidence in the long-term potential of this tremendous resource,” said Mr. Carter. “We are very appreciative of the significant de-risking of this asset base done by BPX and look forward to continue working with them on a smaller scale. Our job now is to attract additional capital to our resources here and rationally exploit decades’ worth of locations on our Shelby Trough acreage.”
Revised 2019 Guidance
The following table provides the assumptions for Black Stone’s original and current 2019 guidance:
Original Guidance Original Guidance Revised Guidance
——————– ———————————————————— ————————————————————
Mineral and royalty production (MBoe/d) 35 – 37 36 – 38
Working interest production 10 – 11 11.5 – 12.5
——————– ——————–
Total production (MBoe/d) 45 – 48 47.5 – 50.5
Percentage natural gas 71% 73%
Percentage royalty interest 77% 75%

Lease bonus and other income ($MM) $30 – $40 $20 – $30

Lease operating expense ($MM) $17 – $19 $17 – $19
Production costs and ad valorem taxes (as % of total pre-derivative O&G revenue) 11% – 13% 11% – 13%
Exploration expense ($MM) $1.0 – $2.0 $0.5 – $1.5

G&A — cash ($MM) $45 – $47 $44 – $46
G&A — non-cash ($MM) $21 – $23 $21 – $23
——————– ——————–
G&A — total ($MM) $66 – $70 $65 – $69

DD&A ($/Boe) $7.00 – $8.00 $6.50 – $7.50
Elimination of Replacement Capital Expenditures
Prior to the conversion of the subordinated units, Black Stone was required under the terms of its partnership agreement to include an estimate of replacement capital expenditures in its calculation of distributable cash flow. With the conversion of the subordinated units being completed in May 2019, the Partnership will no longer make this estimate.
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 2019 on Tuesday, August 6, 2019 at 9:00 a.m. Central Time. To listen to the call by phone, participants should dial (877) 447-4732 and use conference code 5659678; callers are advised to dial into the call 10 minutes in advance of the call start time. 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 5, 2019.
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 in the continental United States. 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. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per unit amounts)

Three Months Ended June 30, Six Months Ended June 30,
——————————————————————————————————————————————– ——————————————————————————————————————————————–
2019 2018 2019 2018
———————————————————— ———————————————————— ———————————————————— ————————————————————

REVENUE
$ 74,072 $ 77,225 $ 131,776 $ 150,208
Oil and condensate sales
53,642 53,854 115,282 107,099
Natural gas and natural gas liquids sales
6,717 11,577 12,362 16,176
Lease bonus and other income
—————————————- ——————– —————————————- ——————– —————————————- ——————– —————————————- ——————–
134,431 142,656 259,420 273,483
Revenue from contracts with customers
29,187 (33,347 ) (11,996 ) (49,680 )
Gain (loss) on commodity derivative instruments
—————————————- ——————– —————————————- ——————– —————————————- ——————– —————————————- ——————–
163,618 109,309 247,424 223,803
TOTAL REVENUE
—————————————- ——————– —————————————- ——————– —————————————- ——————– —————————————- ——————–
OPERATING (INCOME) EXPENSE
3,849 4,290 9,141 8,538
Lease operating expense
14,450 14,373 29,042 29,298
Production costs and ad valorem taxes
304 6,745 308 6,748
Exploration expense
29,725 30,292 57,558 58,862
Depreciation, depletion, and amortization
14,347 19,812 35,561 38,333
General and administrative
277 273 554 542
Accretion of asset retirement obligations
— — — (2 )
(Gain) loss on sale of assets, net
—————————————- ——————– —————————————- ——————– —————————————- ——————– —————————————- ——————–
62,952 75,785 132,164 142,319
TOTAL OPERATING EXPENSE
—————————————- ——————– —————————————- ——————– —————————————- ——————– —————————————- ——————–
INCOME (LOSS) FROM OPERATIONS 100,666 33,524 115,260 81,484
OTHER INCOME (EXPENSE)
47 37 93 70
Interest and investment income
(5,652 ) (5,280 ) (11,177 ) (9,801 )
Interest expense
26 409 (72 ) (1,106 )
Other income (expense)
—————————————- ——————– —————————————- ——————– —————————————- ——————– —————————————- ——————–
(5,579 ) (4,834 ) (11,156 ) (10,837 )
TOTAL OTHER EXPENSE
—————————————- ——————– —————————————- ——————– —————————————- ——————– —————————————- ——————–
NET INCOME (LOSS) 95,087 28,690 104,104 70,647
— 48 — 22
Net (income) loss attributable to noncontrolling interests
— — — (25 )
Distributions on Series A redeemable preferred units
(5,250 ) (5,250 ) (10,500 ) (10,500 )
Distributions on Series B cumulative convertible preferred units
—————————————- ——————– —————————————- ——————– —————————————- ——————– —————————————- ——————–
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS $ 89,837 $ 23,488 $ 93,604 $ 60,144
==================== ==================== ==================== ==================== ==================== ==================== ==================== ==================== ==================== ==================== ==================== ====================
ALLOCATION OF NET INCOME (LOSS):
$ — $ — — —
General partner interest
67,718 17,540 69,611 41,877
Common units
22,119 5,948 23,993 18,267
Subordinated units
—————————————- ——————– —————————————- ——————– —————————————- ——————– —————————————- ——————–
$ 89,837 $ 23,488 $ 93,604 $ 60,144
==================== ==================== ==================== ==================== ==================== ==================== ==================== ==================== ==================== ==================== ==================== ====================
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
$ 0.45 $ 0.17 0.54 0.40
Per common unit (basic)
==================== ==================== ==================== ==================== ==================== ==================== ======================================== ==================== ======================================== ====================
150,101 105,250 129,873 104,516
Weighted average common units outstanding (basic)
======================================== ==================== ======================================== ==================== ======================================== ==================== ======================================== ====================
$ 0.39 $ 0.06 0.32 0.19
Per subordinated unit (basic)
==================== ==================== ==================== ==================== ==================== ==================== ======================================== ==================== ======================================== ====================
56,104 96,329 76,105 95,864
Weighted average subordinated units outstanding (basic)
======================================== ==================== ======================================== ==================== ======================================== ==================== ======================================== ====================
$ 0.44 $ 0.17 0.54 0.40
Per common unit (diluted)
==================== ==================== ==================== ==================== ==================== ==================== ======================================== ==================== ======================================== ====================
165,070 105,250 129,873 104,516
Weighted average common units outstanding (diluted)
======================================== ==================== ======================================== ==================== ======================================== ==================== ======================================== ====================
$ 0.39 $ 0.06 0.32 0.19
Per subordinated unit (diluted)
==================== ==================== ==================== ==================== ==================== ==================== ======================================== ==================== ======================================== ====================
56,104 96,329 76,105 95,864
Weighted average subordinated units outstanding (diluted)
======================================== ==================== ======================================== ==================== ======================================== ==================== ======================================== ====================
The following table shows the Partnership’s production, revenues, pricing, and expenses for the periods presented:
Three Months Ended June 30, Six Months Ended June 30,
————————————————————————————– ————————————————————————————–
2019 2018 2019 2018
——————————— ——————————— ——————————— ———————————

(Unaudited)
(Dollars in thousands, except for realized prices and per Boe data)
Production:
1,316 1,183 2,424 2,372
Oil and condensate (MBbls)
20,594 17,311 39,209 33,052
Natural gas (MMcf)(1)
————- ——————– ————- ——————– ————- ——————– ————- ——————–
4,748 4,068 8,959 7,881
Equivalents (MBoe)
52.2 44.7 49.5 43.5
Equivalents/day (MBoe)
Revenue:
$ 74,072 $ 77,225 $ 131,776 $ 150,208
Oil and condensate sales
53,642 53,854 115,282 107,099
Natural gas and natural gas liquids sales(1)
6,717 11,577 12,362 16,176
Lease bonus and other income
————- ——————– ————- ——————– ————- ——————– ————- ——————–
134,431 142,656 259,420 273,483
Revenue from contracts with customers
29,187 (33,347 ) (11,996 ) (49,680 )
Gain (loss) on commodity derivative instruments
————- ——————– ————- ——————– ————- ——————– ————- ——————–
$ 163,618 $ 109,309 $ 247,424 $ 223,803
Total revenue
Realized prices, without derivatives:
$ 56.30 $ 65.28 $ 54.37 $ 63.33
Oil and condensate ($/Bbl)
2.60 3.11 2.94 3.24
Natural gas ($/Mcf)(1)
————- ——————– ————- ——————– ————- ——————– ————- ——————–
$ 26.90 $ 32.22 $ 27.58 $ 32.65
Equivalents ($/Boe)
Operating expenses:
$ 3,849 $ 4,290 $ 9,141 $ 8,538
Lease operating expense
14,450 14,373 29,042 29,298
Production costs and ad valorem taxes
304 6,745 308 6,748
Exploration expense
29,725 30,292 57,558 58,862
Depreciation, depletion, and amortization
14,347 19,812 35,561 38,333
General and administrative
Per Boe:
$ 3.40 $ 3.45 $ 3.92 $ 3.42
Lease operating expense (per working interest Boe)
3.04 3.53 3.24 3.72
Production costs and ad valorem taxes
6.26 7.45 6.42 7.47
Depreciation, depletion, and amortization
3.02 4.87 3.97 4.86
General and administrative
(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. 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 during the subordination period, 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,
—————————————————————————————- —————————————————————————————
2019 2018 2019 2018
———————————- ———————————- ———————————- ———————————

(Unaudited)
(In thousands, except per unit amounts)
Net income (loss) $ 95,087 $ 28,690 $ 104,104 $ 70,647
Adjustments to reconcile to Adjusted EBITDA:
29,725 30,292 57,558 58,862
Depreciation, depletion, and amortization
5,652 5,280 11,177 9,801
Interest expense
35 (446 ) 166 1,061
Income tax expense (benefit)
277 273 554 542
Accretion of asset retirement obligations
3,816 9,124 13,039 15,350
Equity-based compensation
(26,256 ) 27,057 16,670 39,015
Unrealized (gain) loss on commodity derivative instruments
————– ——————– ————– ——————– ————– ——————– ————- ——————–
Adjusted EBITDA 108,336 100,270 203,268 195,278
Adjustments to reconcile to Distributable cash flow:
294 (1 ) (10 ) 1,302
Change in deferred revenue
(5,392 ) (4,969 ) (10,661 ) (9,285 )
Cash interest expense
— — — (2 )
(Gain) loss on sale of assets, net
— (2,750 ) (2,750 ) (6,000 )
Estimated replacement capital expenditures(1)
— (62 ) — (114 )
Cash paid to noncontrolling interests
(5,250 ) (5,250 ) (10,500 ) (10,525 )
Preferred unit distributions
————– ——————– ————– ——————– ————– ——————– ————- ——————–
Distributable cash flow $ 97,988 $ 87,238 $ 179,347 $ 170,654
======= ======= ==================== ======= ======= ==================== ======= ======= ==================== ====== ======= ====================

Total units outstanding(2) 205,962 203,148
Distributable cash flow per unit $ 0.476 $ 0.429
Common unit price as of August 2, 2019 and August 3, 2018, respectively $ 14.97 $ 17.17
Implied Distributable cash flow yield 12.7 % 10.0 %
(1) 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. No replacement capital expenditure estimate will be established for periods subsequent to March 31, 2019. 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. No replacement capital expenditure estimate will be established for periods subsequent to March 31, 2019.
(2) The distribution attributable to the three months ended June 30, 2019 is estimated using 205,961,594 common units as of July 30, 2019; the exact amount of the distribution attributable to the three months ended June 30, 2019 will be determined based on units outstanding as of the record date of August 15, 2019. Distributions attributable to the three months ended June 30, 2018 were calculated using 106,819,353 common units and 96,328,836 subordinated units as of the record date of August 16, 2018. The distribution attributable to the three months ended June 30, 2019 is estimated using 205,961,594 common units as of July 30, 2019; the exact amount of the distribution attributable to the three months ended June 30, 2019 will be determined based on units outstanding as of the record date of August 15, 2019. Distributions attributable to the three months ended June 30, 2018 were calculated using 106,819,353 common units and 96,328,836 subordinated units as of the record date of August 16, 2018.
View source version on businesswire.com: https://www.businesswire.com/news/home/20190805005627/en/
SOURCE: Black Stone Minerals, L.P.

Black Stone Minerals, L.P. Contact
Brent Collins
Vice President, Investor Relations
Telephone: (713) 445-3200
investorrelations@blackstoneminerals.com

Copyright Business Wire 2019

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