Black Stone Minerals, L.P. Reports Second Quarter Results; Raises Production Guidance for 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 thePermian Basin and inEast Texas for cash during the second quarter.
Management Commentary
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
Black Stone reported oil and gas revenues of
The Partnership recognized a gain on commodity derivative instruments of
Black Stone recognized
The Partnership reported net income of
Adjusted EBITDA and Distributable Cash Flow
Black Stone reported Adjusted EBITDA of
FinancialPosition and Activities
As of
As of
During the second quarter of 2019, the Partnership repurchased approximately 137,000 units at an average unit price of
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 Price |
Oil Costless
|
Collar Floor |
Collar Ceiling |
||||||
|
MBbl |
$/Bbl |
MBbl |
$/Bbl |
$/Bbl |
||||||
3Q19 |
855 |
|
$58.37 |
|
60 |
|
$65.00 |
|
$74.00 |
||
4Q19 |
855 |
|
$58.37 |
|
60 |
|
$65.00 |
|
$74.00 |
||
1Q20 |
510 |
|
$57.14 |
|
210 |
|
$56.43 |
|
$67.14 |
||
2Q20 |
510 |
|
$57.14 |
|
210 |
|
$56.43 |
|
$67.14 |
||
3Q20 |
510 |
|
$57.14 |
|
210 |
|
$56.43 |
|
$67.14 |
||
4Q20 |
510 |
|
$57.14 |
|
210 |
|
$56.43 |
|
$67.14 |
Natural Gas Hedge
|
|
|
||
|
Gas Swap |
Gas Swap Price |
||
|
MMcf |
$/Mcf |
||
3Q19 |
14,640 |
$2.96 |
||
4Q19 |
14,640 |
$2.96 |
||
1Q20 |
8,190 |
$2.73 |
||
2Q20 |
8,190 |
$2.73 |
||
3Q20 |
8,280 |
$2.73 |
||
4Q20 |
8,280 |
$2.73 |
More detailed information about the Partnership's existing hedging program can be found in the Quarterly Report on Form 10-Q for the second quarter of 2019, which is expected to be filed on or around
Acquisitions
Black Stone acquired
Distributions
As previously reported, the Board of Directors of the general partner (the "Board") has approved cash distributions attributable to the second quarter of 2019 of
Activity Update
Well Additions
For the quarter ended
Shelby Trough Update
Black Stone expects drilling activity to slow temporarily on its Shelby Trough acreage in
Black Stone recognizes that the natural gas market globally has current challenges that may persist for some time, but believes that growth in U.S. LNG exports, global increases in energy demand and for natural gas demand in particular, and proximity to
Revised 2019 Guidance
The following table provides the assumptions for Black Stone's original and current 2019 guidance:
|
Original Guidance |
|
Revised Guidance |
|||||
Mineral and royalty production (MBoe/d) |
|
35 - 37 |
|
|
|
36 - 38 |
|
|
Working interest production |
|
10 - 11 |
|
|
|
11.5 - 12.5 |
|
|
Total production (MBoe/d) |
|
45 - 48 |
|
|
|
47.5 - 50.5 |
|
|
Percentage natural gas |
|
~71% |
|
|
|
~73% |
|
|
Percentage royalty interest |
|
~77% |
|
|
|
~75% |
|
|
|
|
|
|
|
|
|
|
|
Lease bonus and other income ($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
Conference Call
About
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,
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
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
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 |
|
|
|
|
|
|
|
|
||||||||
Oil and condensate sales |
|
$ |
74,072 |
|
|
$ |
77,225 |
|
|
$ |
131,776 |
|
|
$ |
150,208 |
|
Natural gas and natural gas liquids sales |
|
53,642 |
|
|
53,854 |
|
|
115,282 |
|
|
107,099 |
|
||||
Lease bonus and other income |
|
6,717 |
|
|
11,577 |
|
|
12,362 |
|
|
16,176 |
|
||||
Revenue from contracts with customers |
|
134,431 |
|
|
142,656 |
|
|
259,420 |
|
|
273,483 |
|
||||
Gain (loss) on commodity derivative instruments |
|
29,187 |
|
|
(33,347 |
) |
|
(11,996 |
) |
|
(49,680 |
) |
||||
TOTAL REVENUE |
|
163,618 |
|
|
109,309 |
|
|
247,424 |
|
|
223,803 |
|
||||
OPERATING (INCOME) EXPENSE |
|
|
|
|
|
|
|
|
||||||||
Lease operating expense |
|
3,849 |
|
|
4,290 |
|
|
9,141 |
|
|
8,538 |
|
||||
Production costs and ad valorem taxes |
|
14,450 |
|
|
14,373 |
|
|
29,042 |
|
|
29,298 |
|
||||
Exploration expense |
|
304 |
|
|
6,745 |
|
|
308 |
|
|
6,748 |
|
||||
Depreciation, depletion, and amortization |
|
29,725 |
|
|
30,292 |
|
|
57,558 |
|
|
58,862 |
|
||||
General and administrative |
|
14,347 |
|
|
19,812 |
|
|
35,561 |
|
|
38,333 |
|
||||
Accretion of asset retirement obligations |
|
277 |
|
|
273 |
|
|
554 |
|
|
542 |
|
||||
(Gain) loss on sale of assets, net |
|
— |
|
|
— |
|
|
— |
|
|
(2 |
) |
||||
TOTAL OPERATING EXPENSE |
|
62,952 |
|
|
75,785 |
|
|
132,164 |
|
|
142,319 |
|
||||
INCOME (LOSS) FROM OPERATIONS |
|
100,666 |
|
|
33,524 |
|
|
115,260 |
|
|
81,484 |
|
||||
OTHER INCOME (EXPENSE) |
|
|
|
|
|
|
|
|
||||||||
Interest and investment income |
|
47 |
|
|
37 |
|
|
93 |
|
|
70 |
|
||||
Interest expense |
|
(5,652 |
) |
|
(5,280 |
) |
|
(11,177 |
) |
|
(9,801 |
) |
||||
Other income (expense) |
|
26 |
|
|
409 |
|
|
(72 |
) |
|
(1,106 |
) |
||||
TOTAL OTHER EXPENSE |
|
(5,579 |
) |
|
(4,834 |
) |
|
(11,156 |
) |
|
(10,837 |
) |
||||
NET INCOME (LOSS) |
|
95,087 |
|
|
28,690 |
|
|
104,104 |
|
|
70,647 |
|
||||
Net (income) loss attributable to noncontrolling interests |
|
— |
|
|
48 |
|
|
— |
|
|
22 |
|
||||
Distributions on Series A redeemable preferred units |
|
— |
|
|
— |
|
|
— |
|
|
(25 |
) |
||||
Distributions on Series B cumulative convertible preferred units |
|
(5,250 |
) |
|
(5,250 |
) |
|
(10,500 |
) |
|
(10,500 |
) |
||||
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 |
|
$ |
— |
|
|
$ |
— |
|
|
— |
|
|
— |
|
||
Common units |
|
67,718 |
|
|
17,540 |
|
|
69,611 |
|
|
41,877 |
|
||||
Subordinated units |
|
22,119 |
|
|
5,948 |
|
|
23,993 |
|
|
18,267 |
|
||||
|
|
$ |
89,837 |
|
|
$ |
23,488 |
|
|
$ |
93,604 |
|
|
$ |
60,144 |
|
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: |
|
|
|
|
|
|
|
|
||||||||
Per common unit (basic) |
|
$ |
0.45 |
|
|
$ |
0.17 |
|
|
0.54 |
|
|
0.40 |
|
||
Weighted average common units outstanding (basic) |
|
150,101 |
|
|
105,250 |
|
|
129,873 |
|
|
104,516 |
|
||||
Per subordinated unit (basic) |
|
$ |
0.39 |
|
|
$ |
0.06 |
|
|
0.32 |
|
|
0.19 |
|
||
Weighted average subordinated units outstanding (basic) |
|
56,104 |
|
|
96,329 |
|
|
76,105 |
|
|
95,864 |
|
||||
Per common unit (diluted) |
|
$ |
0.44 |
|
|
$ |
0.17 |
|
|
0.54 |
|
|
0.40 |
|
||
Weighted average common units outstanding (diluted) |
|
165,070 |
|
|
105,250 |
|
|
129,873 |
|
|
104,516 |
|
||||
Per subordinated unit (diluted) |
|
$ |
0.39 |
|
|
$ |
0.06 |
|
|
0.32 |
|
|
0.19 |
|
||
Weighted average subordinated units outstanding (diluted) |
|
56,104 |
|
|
96,329 |
|
|
76,105 |
|
|
95,864 |
|
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)
|
||||||||||||||
Production: |
|
|
|
|
|
|
|
|
||||||||
Oil and condensate (MBbls) |
|
1,316 |
|
|
1,183 |
|
|
2,424 |
|
|
2,372 |
|
||||
Natural gas (MMcf)1 |
|
20,594 |
|
|
17,311 |
|
|
39,209 |
|
|
33,052 |
|
||||
Equivalents (MBoe) |
|
4,748 |
|
|
4,068 |
|
|
8,959 |
|
|
7,881 |
|
||||
Equivalents/day (MBoe) |
|
52.2 |
|
|
44.7 |
|
|
49.5 |
|
|
43.5 |
|
||||
Revenue: |
|
|
|
|
|
|
|
|
||||||||
Oil and condensate sales |
|
$ |
74,072 |
|
|
$ |
77,225 |
|
|
$ |
131,776 |
|
|
$ |
150,208 |
|
Natural gas and natural gas liquids sales1 |
|
53,642 |
|
|
53,854 |
|
|
115,282 |
|
|
107,099 |
|
||||
Lease bonus and other income |
|
6,717 |
|
|
11,577 |
|
|
12,362 |
|
|
16,176 |
|
||||
Revenue from contracts with customers |
|
134,431 |
|
|
142,656 |
|
|
259,420 |
|
|
273,483 |
|
||||
Gain (loss) on commodity derivative instruments |
|
29,187 |
|
|
(33,347 |
) |
|
(11,996 |
) |
|
(49,680 |
) |
||||
Total revenue |
|
$ |
163,618 |
|
|
$ |
109,309 |
|
|
$ |
247,424 |
|
|
$ |
223,803 |
|
Realized prices, without derivatives: |
|
|
|
|
|
|
|
|
||||||||
Oil and condensate ($/Bbl) |
|
$ |
56.30 |
|
|
$ |
65.28 |
|
|
$ |
54.37 |
|
|
$ |
63.33 |
|
Natural gas ($/Mcf)1 |
|
2.60 |
|
|
3.11 |
|
|
2.94 |
|
|
3.24 |
|
||||
Equivalents ($/Boe) |
|
$ |
26.90 |
|
|
$ |
32.22 |
|
|
$ |
27.58 |
|
|
$ |
32.65 |
|
Operating expenses: |
|
|
|
|
|
|
|
|
||||||||
Lease operating expense |
|
$ |
3,849 |
|
|
$ |
4,290 |
|
|
$ |
9,141 |
|
|
$ |
8,538 |
|
Production costs and ad valorem taxes |
|
14,450 |
|
|
14,373 |
|
|
29,042 |
|
|
29,298 |
|
||||
Exploration expense |
|
304 |
|
|
6,745 |
|
|
308 |
|
|
6,748 |
|
||||
Depreciation, depletion, and amortization |
|
29,725 |
|
|
30,292 |
|
|
57,558 |
|
|
58,862 |
|
||||
General and administrative |
|
14,347 |
|
|
19,812 |
|
|
35,561 |
|
|
38,333 |
|
||||
Per Boe: |
|
|
|
|
|
|
|
|
||||||||
Lease operating expense (per working interest Boe) |
|
$ |
3.40 |
|
|
$ |
3.45 |
|
|
$ |
3.92 |
|
|
$ |
3.42 |
|
Production costs and ad valorem taxes |
|
3.04 |
|
|
3.53 |
|
|
3.24 |
|
|
3.72 |
|
||||
Depreciation, depletion, and amortization |
|
6.26 |
|
|
7.45 |
|
|
6.42 |
|
|
7.47 |
|
||||
General and administrative |
|
3.02 |
|
|
4.87 |
|
|
3.97 |
|
|
4.86 |
|
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 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
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)
|
||||||||||||||
Net income (loss) |
|
$ |
95,087 |
|
|
$ |
28,690 |
|
|
$ |
104,104 |
|
|
$ |
70,647 |
|
Adjustments to reconcile to Adjusted EBITDA: |
|
|
|
|
|
|
|
|
||||||||
Depreciation, depletion, and amortization |
|
29,725 |
|
|
30,292 |
|
|
57,558 |
|
|
58,862 |
|
||||
Interest expense |
|
5,652 |
|
|
5,280 |
|
|
11,177 |
|
|
9,801 |
|
||||
Income tax expense (benefit) |
|
35 |
|
|
(446 |
) |
|
166 |
|
|
1,061 |
|
||||
Accretion of asset retirement obligations |
|
277 |
|
|
273 |
|
|
554 |
|
|
542 |
|
||||
Equity–based compensation |
|
3,816 |
|
|
9,124 |
|
|
13,039 |
|
|
15,350 |
|
||||
Unrealized (gain) loss on commodity derivative instruments |
|
(26,256 |
) |
|
27,057 |
|
|
16,670 |
|
|
39,015 |
|
||||
Adjusted EBITDA |
|
108,336 |
|
|
100,270 |
|
|
203,268 |
|
|
195,278 |
|
||||
Adjustments to reconcile to Distributable cash flow: |
|
|
|
|
|
|
|
|
||||||||
Change in deferred revenue |
|
294 |
|
|
(1 |
) |
|
(10 |
) |
|
1,302 |
|
||||
Cash interest expense |
|
(5,392 |
) |
|
(4,969 |
) |
|
(10,661 |
) |
|
(9,285 |
) |
||||
(Gain) loss on sale of assets, net |
|
— |
|
|
— |
|
|
— |
|
|
(2 |
) |
||||
Estimated replacement capital expenditures1 |
|
— |
|
|
(2,750 |
) |
|
(2,750 |
) |
|
(6,000 |
) |
||||
Cash paid to noncontrolling interests |
|
— |
|
|
(62 |
) |
|
— |
|
|
(114 |
) |
||||
Preferred unit distributions |
|
(5,250 |
) |
|
(5,250 |
) |
|
(10,500 |
) |
|
(10,525 |
) |
||||
Distributable cash flow |
|
$ |
97,988 |
|
|
$ |
87,238 |
|
|
$ |
179,347 |
|
|
$ |
170,654 |
|
|
|
|
|
|
|
|
|
|
||||||||
Total units outstanding2 |
|
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. |
|
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. |
View source version on businesswire.com: https://www.businesswire.com/news/home/20190805005627/en/
Source:
Black Stone Minerals, L.P. Contact
Brent Collins
Vice President, Investor Relations
Telephone: (713) 445-3200
investorrelations@blackstoneminerals.com