EPS Forecast
Revenue Forecast
EX-99.1
2
a12312019-exhibit991ng.htm
EX-99.1
Document
 | Exhibit 99.1 News For Immediate Release | ||||
Black Stone Minerals, L.P. Announces Fourth Quarter and Full Year 2019 Results;
Provides Guidance for 2020
HOUSTON--(BUSINESS WIRE) - Black Stone Minerals, L.P. (NYSE: BSM) (“Black Stone Minerals,” “Black Stone,” or “the Company”) today announces its financial and operating results for the fourth quarter and full year of 2019 and provides guidance for 2020.
Fourth Quarter 2019 Highlights
•Reported total production in the fourth quarter of 46.2 MBoe/d.
•Recognized net income and Adjusted EBITDA for the quarter of $40.0 million and $100.0 million, respectively.
•Reported Distributable cash flow of $90.2 million, resulting in distribution coverage for all units of 1.5x based on the announced cash distribution of $0.30 per unit; retained $28.4 million of distributable cash in the fourth quarter.
•Reduced debt by almost $20 million during the fourth quarter to $394 million; total debt to trailing twelve-month Adjusted EBITDA was 1.0x at year-end.
Other Financial and Operational Highlights
•Achieved full year 2019 production of 48.5 MBoe/d; mineral and royalty volumes in 2019 increased 14% over the prior year to average 36.4 MBoe/d.
•Reported 2019 net income and Adjusted EBITDA of $214.4 million and $399.5 million, respectively.
•Reported estimated proved reserves at year-end 2019 of 68.5 MMBoe (75% natural gas and 87% proved developed producing), a decrease of 2% over year-end 2018.
Management Commentary
Thomas L. Carter, Jr., Black Stone Minerals’ Chief Executive Officer and Chairman commented, “In an industry environment of challenging metrics, we are fortunate to have had another year of solid operational and financial performance in 2019. We delivered record royalty production and continued to strengthen the balance sheet by reducing total debt levels during the year. We are positioned to deal with the current difficult commodity price environment, which has resulted in slowing industry activity, and intend to continue to be conservative financially. In recognition of this, we lowered our distribution with respect to the fourth quarter. We have also taken significant steps to lower our cost structure in 2020 forward to better align our organization with current industry conditions. We made the difficult decision to reduce our headcount, and have lowered executive and Board compensation levels. We anticipate recommending to the Board a distribution of approximately $1.00 per common unit for the full year 2020, depending on actual commodity prices and producer activity on our acreage during the year, a move that we expect will further strengthen our balance sheet through debt reduction while preserving a meaningful return to our unitholders."
Quarterly Financial and Operating Results
Production
Black Stone Minerals reported average production of 46.2 MBoe/d (76% mineral and royalty, 73% natural gas) for the fourth quarter of 2019. Total production was 49.7 MBoe/d and 49.0 MBoe/d for the quarters ended December 31, 2018 and September 30, 2019, respectively.
Mineral and royalty volume was 35.1 MBoe/d (67% natural gas) for the fourth quarter of 2019, compared to 35.8 MBoe/d for the comparable period in 2018. Royalty production for the third quarter of 2019 was 37.5 MBoe//d.
Working interest production for the fourth quarter of 2019 was 11.1 MBoe/d, and represents decreases of 4% and 20%, respectively, from the 11.5 MBoe/d and 13.9 MBoe/d for the quarters ended September 30, 2019 and December 31, 2018. The decline in working interest volumes is consistent with the Company's decision to farm out its working-interest participation to third-party capital providers.
Realized Prices, Revenues, and Net Income
The Company’s average realized price per Boe, excluding the effect of derivative settlements, was $25.02 for the quarter ended December 31, 2019. This is an increase of 3% from $24.30 per Boe from the third quarter of 2019 and a 26% decrease compared to $33.97 for the fourth quarter of 2018.
Black Stone reported oil and gas revenue of $106.3 million (60% oil and condensate) for the fourth quarter of 2019, a decrease of 3% from $109.6 million in the third quarter of 2019. Oil and gas revenue in the fourth quarter of 2018 was $155.4 million.
The Company reported a loss on commodity derivative instruments of $17.2 million for the fourth quarter of 2019, composed of a $9.5 million gain from realized settlements and a non-cash $26.8 million unrealized loss due to the change in value of Black Stone’s derivative positions during the quarter. Black Stone reported gains on commodity derivative instruments of $24.3 million and $83.0 million for the quarters ended September 30, 2019 and December 31, 2018, respectively.
Lease bonus and other income was $14.0 million for the fourth quarter of 2019, of which $8.7 million related to lease bonus activity in the Haynesville, Permian, and Bakken/Three Forks and $5.1 million related to contractual payments or legal settlements. Lease bonus and other income for the quarters ended September 30, 2019 and December 31, 2018 was $3.5 million and $7.6 million, respectively.
The Company reported net income of $40.0 million for the quarter ended December 31, 2019, compared to net income of $70.2 million in the preceding quarter. For the quarter ended December 31, 2018, net income was $164.1 million.
Adjusted EBITDA and Distributable Cash Flow
Adjusted EBITDA for the fourth quarter of 2019 was $100.0 million, which compares to $96.2 million in the third quarter of 2019 and $110.0 million in the fourth quarter of 2018. Distributable cash flow for the quarter ended December 31, 2019 was $90.2 million. For the quarters ended September 30, 2019 and December 31, 2018, distributable cash flow was $85.8 million and $96.7 million, respectively.
2019 Proved Reserves
Estimated proved oil and natural gas reserves at year-end 2019 were 68.5 MMBoe, a decrease of 2% from 69.9 MMBoe at year-end 2018, and were approximately 75% natural gas and 87% proved developed producing. The standardized measure of discounted future net cash flows was $847.9 million at the end of 2019 as compared to $1,087.6 million at year-end 2018.
Netherland, Sewell and Associates, Inc., an independent, third-party petroleum engineering firm, evaluated Black Stone Minerals’ estimate of its proved reserves and PV-10 at December 31, 2019. These estimates were prepared using reference prices of $55.85 per barrel of oil and $2.58 per MMBTU of natural gas in accordance with the applicable rules of the Securities and Exchange Commission. These prices were adjusted for quality and market differentials, transportation fees, and in the case of natural gas, the value of natural gas liquids. A reconciliation of proved reserves is presented in the summary financial tables following this press release.
Financial Position and Activities
As of December 31, 2019, Black Stone Minerals had $8.1 million in cash and $394.0 million outstanding under its credit facility. The ratio of total debt at year-end to 2019 Adjusted EBITDA was 1.0x. The Company’s borrowing base at December 31, 2019 was $650 million, and the Company's next regularly scheduled borrowing base redetermination is set for April 2020. Black Stone is in compliance with all financial covenants associated with its credit facility.
As of February 21, 2020, $362.0 million was outstanding under the credit facility and the Company had $5.3 million in cash.
During the fourth quarter of 2019, the Company made no repurchases of units under the Board-approved $75 million unit repurchase program and issued no units under its at-the-market offering program.
Fourth Quarter 2019 Distributions
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As previously announced, the Board of Directors of the general partner approved a cash distribution of $0.30 for each common unit attributable to the fourth quarter of 2019. The quarterly distribution coverage ratio attributable to the fourth quarter of 2019 was approximately 1.5x. These distributions were paid on February 24, 2020 to unitholders of record as of the close of business on February 17, 2020.
Summary 2020 Guidance
Following are the key assumptions in Black Stone Minerals’ 2020 guidance, as well as comparable results for 2019:
| FY 2019 Actual | FY 2020 Est. | ||||||||||
| Mineral and royalty production (MBoe/d) | 36.4 | 32 - 34 | |||||||||
| Working interest production (MBoe/d) | 12.1 | 8.5 - 9.5 | |||||||||
| Total production (MBoe/d) | 48.5 | 40.5 - 43.5 | |||||||||
| Percentage natural gas | 73% | ~71% | |||||||||
| Percentage royalty interest | 75% | ~79% | |||||||||
| Lease bonus and other income ($MM) | $29.8 | $20 - $30 | |||||||||
| Lease operating expense ($MM) | $17.7 | $16 - $18 | |||||||||
| Production costs and ad valorem taxes (as % of total pre-derivative O&G revenue) | 13.1% | 14% - 16% | |||||||||
| G&A - cash ($MM) | $42.9 | $31 - $33 | |||||||||
| G&A - non-cash ($MM) | $20.5 | $8 - $10 | |||||||||
| G&A - TOTAL ($MM) | $63.4 | $39 - $43 | |||||||||
| DD&A ($/Boe) | $6.19 | $6.00 - $6.50 | |||||||||
Production
Black Stone expects royalty production to decline by approximately 9% in 2020 due to lower levels of drilling activity in major areas outside the Midland and Delaware basins. The Company anticipates the largest production declines to occur on its dry-gas weighted Haynesville acreage, including on the Shelby Trough Haynesville/Bossier position in East Texas. Black Stone remains engaged in constructive discussions to bring in a new producer for the Shelby Trough acreage formerly operated by BPX Energy.
Working interest production is expected to decline by approximately 25% in 2020 as a result of Black Stone's decision to farm out participation in its working interest opportunities.
General and administrative
In light of the current industry and capital markets environment, Black Stone has decided to significantly reduce its general and administrative (“G&A”) expenses. This includes broad workforce reductions and lower executive and Board compensation levels going forward. The Company expects to incur a one-time cash charge of approximately $5 million in the first quarter of 2020 associated with severance agreements for affected employees. This non-recurring charge is not included in the G&A guidance range above.
Distributions
Under the current outlook for commodity prices and drilling activity, management anticipates recommending quarterly distributions for 2020 of approximately $0.25 per unit, or $1.00 per unit for the full year. Management expects this distribution level to allow the Company to continue to retain a portion of its free cash flow for further debt reduction, and potentially for other uses such as unit repurchases and acquisitions. To the extent those factors, among others, change relative to expectations,
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management may recommend different distribution amounts. Actual distributions will be determined on a quarterly basis by the Board of Directors of our general partner.
For similar reasons, Black Stone expects the taxable income allocated to all its limited partners in 2020 to be substantially less than the income allocated in 2018 and 2019. Total taxable income generated by the Company is negatively impacted by lower commodity prices, while the amount of depletion generated by the Company is primarily a function of production volumes. For example, Black Stone expects that a limited partner who purchased common units in the Company's initial public offering and who continue to hold those units through the 2020 calendar year would be allocated an amount of federal taxable income that is less than 20% of the expected $1.00 per unit distribution for 2020. Black Stone estimates the average legacy owner will be allocated an amount of federal taxable income that is less than 65% of the expected $1.00 per unit distribution for 2020. Accordingly, assuming a 37% effective tax rate for investors, the reduction in after-tax proceeds will be significantly less than the reduction in the amount per unit distributed by the Company. These expectations and assumptions are subject to, among other things, numerous business, economic, tax, regulatory, legislative, competitive, and political uncertainties beyond the Company's control. Accordingly, Black Stone cannot assure that these estimates will prove to be correct. Moreover, Black Stone is not in the business of providing tax advice and cannot provide any unitholder with advice particular to their own situation. Accordingly, Black Stone encourages each unitholder to consult the unitholder's own tax advisor in analyzing the tax consequences particular to that unitholder.
Hedge Position
Black Stone has commodity derivative contracts in place covering portions of its anticipated production for 2020. The Company's current hedge position is summarized in the following tables:
| Oil Hedge Position | ||||||||||||||||||||
| Oil Swap | Weighted Avg Oil Swap Price | Oil Costless Collars | Weighted Avg Collar Floor | Weighted Avg Collar Ceiling | ||||||||||||||||
| MBbl | $/Bbl | MBbl | $/Bbl | $/Bbl | ||||||||||||||||
| 1Q20 | 630 | $57.32 | 210 | $56.43 | $67.14 | |||||||||||||||
| 2Q20 | 630 | $57.32 | 210 | $56.43 | $67.14 | |||||||||||||||
| 3Q20 | 630 | $57.32 | 210 | $56.43 | $67.14 | |||||||||||||||
| 4Q20 | 630 | $57.32 | 210 | $56.43 | $67.14 | |||||||||||||||
| Gas Hedge Position | ||||||||
| Gas Swap | Weighted Avg Gas Swap Price | |||||||
| MMcf | $/Mcf | |||||||
| 1Q20 | 10,010 | $2.69 | ||||||
| 2Q20 | 10,010 | $2.69 | ||||||
| 3Q20 | 10,120 | $2.69 | ||||||
| 4Q20 | 10,120 | $2.69 | ||||||
More detailed information about the Company's existing hedging program can be found in the Annual Report on Form 10-K, which is expected to be filed on February 25, 2020.
Conference Call
Black Stone Minerals will host a conference call and webcast for investors and analysts to discuss its results for the fourth quarter and full year of 2019 on Tuesday, February 25, 2020 at 9:00 a.m. Central Time. To join the call, participants should dial (877) 447-4732 and use conference code 3758668. A live broadcast of the call will also be available at
http://investor.blackstoneminerals.com. A recording of the conference call will be available at that site through March 25, 2020.
About Black Stone Minerals, L.P.
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Black Stone Minerals is one of the largest owners of oil and natural gas mineral interests in the United States. The Company owns mineral interests and royalty interests in 41 states in the continental United States. Black Stone believes its large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable to growing production and reserves over time, allowing the majority of generated cash flow to be distributed to 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 Company 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 Company’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 Company’s ability to execute its business strategies;
•the volatility of realized oil and natural gas prices;
•the level of production on the Company’s properties;
•overall supply and demand for oil and natural gas, as well as regional supply and demand factors, delays, or interruptions of production;
•the Company’s ability to replace its oil and natural gas reserves;
•the Company’s ability to identify, complete, and integrate acquisitions;
•general economic, business, or industry conditions;
•competition in the oil and natural gas industry; and
•the level of drilling activity by the Company's operators, particularly in areas such as the Shelby Trough where the Company has concentrated acreage positions.
Black Stone Minerals, L.P. Contact
Brent Collins
Investor Relations
Telephone: (713) 445-3200
investorrelations@blackstoneminerals.com
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BLACK STONE MINERALS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per unit amounts)
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2019 | 2018 | |||||||||||||||||||||||||||||||||||
| REVENUE | ||||||||||||||||||||||||||||||||||||||
| Oil and condensate sales | $ | 63,647 | $ | 77,358 | $ | 263,678 | $ | 310,278 | ||||||||||||||||||||||||||||||
| Natural gas and natural gas liquids sales | 42,643 | 78,064 | 199,265 | 248,243 | ||||||||||||||||||||||||||||||||||
| Lease bonus and other income | 13,987 | 7,600 | 29,833 | 36,216 | ||||||||||||||||||||||||||||||||||
| Revenue from contracts with customers | 120,277 | 163,022 | 492,776 | 594,737 | ||||||||||||||||||||||||||||||||||
| Gain (loss) on commodity derivative instruments | (17,249) | 83,025 | (4,955) | 14,831 | ||||||||||||||||||||||||||||||||||
| TOTAL REVENUE | 103,028 | 246,047 | 487,821 | 609,568 | ||||||||||||||||||||||||||||||||||
| OPERATING (INCOME) EXPENSE | ||||||||||||||||||||||||||||||||||||||
| Lease operating expense | 4,168 | 5,648 | 17,665 | 18,415 | ||||||||||||||||||||||||||||||||||
| Production costs and ad valorem taxes | 15,614 | 17,425 | 60,533 | 64,364 | ||||||||||||||||||||||||||||||||||
| Exploration expense | 25 | 1,161 | 397 | 7,943 | ||||||||||||||||||||||||||||||||||
| Depreciation, depletion, and amortization | 24,651 | 34,518 | 109,584 | 122,653 | ||||||||||||||||||||||||||||||||||
| General and administrative | 13,603 | 16,296 | 63,353 | 76,712 | ||||||||||||||||||||||||||||||||||
| Accretion of asset retirement obligations | 288 | 283 | 1,117 | 1,103 | ||||||||||||||||||||||||||||||||||
| (Gain) loss on sale of assets, net | — | (1) | — | (3) | ||||||||||||||||||||||||||||||||||
| TOTAL OPERATING EXPENSE | 58,349 | 75,330 | 252,649 | 291,187 | ||||||||||||||||||||||||||||||||||
| INCOME (LOSS) FROM OPERATIONS | 44,679 | 170,717 | 235,172 | 318,381 | ||||||||||||||||||||||||||||||||||
| OTHER INCOME (EXPENSE) | ||||||||||||||||||||||||||||||||||||||
| Interest and investment income | 22 | 60 | 159 | 183 | ||||||||||||||||||||||||||||||||||
| Interest expense | (4,863) | (5,437) | (21,435) | (20,756) | ||||||||||||||||||||||||||||||||||
| Other income (expense) | 179 | (1,202) | 472 | (2,248) | ||||||||||||||||||||||||||||||||||
| TOTAL OTHER EXPENSE | (4,662) | (6,579) | (20,804) | (22,821) | ||||||||||||||||||||||||||||||||||
| NET INCOME (LOSS) | 40,017 | 164,138 | 214,368 | 295,560 | ||||||||||||||||||||||||||||||||||
| Net (income) loss attributable to noncontrolling interests | — | (23) | — | (24) | ||||||||||||||||||||||||||||||||||
| Distributions on Series A redeemable preferred units | — | — | — | (25) | ||||||||||||||||||||||||||||||||||
| Distributions on Series B cumulative convertible preferred units | (5,250) | (5,250) | (21,000) | (21,000) | ||||||||||||||||||||||||||||||||||
| NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS | $ | 34,767 | $ | 158,865 | $ | 193,368 | $ | 274,511 | ||||||||||||||||||||||||||||||
| ALLOCATION OF NET INCOME (LOSS): | ||||||||||||||||||||||||||||||||||||||
| General partner interest | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||||
| Common units | 34,767 | 83,625 | 169,375 | 154,662 | ||||||||||||||||||||||||||||||||||
| Subordinated units | — | 75,240 | 23,993 | 119,849 | ||||||||||||||||||||||||||||||||||
| $ | 34,767 | $ | 158,865 | $ | 193,368 | $ | 274,511 | |||||||||||||||||||||||||||||||
| NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: | ||||||||||||||||||||||||||||||||||||||
| Per common unit (basic) | $ | 0.17 | $ | 0.78 | $ | 1.01 | $ | 1.46 | ||||||||||||||||||||||||||||||
| Weighted average common units outstanding (basic) | 205,966 | 108,465 | 168,230 | 106,064 | ||||||||||||||||||||||||||||||||||
| Per subordinated unit (basic) | $ | — | $ | 0.78 | $ | 0.64 | $ | 1.25 | ||||||||||||||||||||||||||||||
| Weighted average subordinated units outstanding (basic) | — | 96,329 | 37,740 | 96,099 | ||||||||||||||||||||||||||||||||||
| Per common unit (diluted) | $ | 0.17 | $ | 0.72 | $ | 1.01 | $ | 1.45 | ||||||||||||||||||||||||||||||
| Weighted average common units outstanding (diluted) | 206,552 | 124,354 | 168,376 | 121,264 | ||||||||||||||||||||||||||||||||||
| Per subordinated unit (diluted) | $ | — | $ | 0.78 | $ | 0.64 | $ | 1.25 | ||||||||||||||||||||||||||||||
| Weighted average subordinated units outstanding (diluted) | — | 96,329 | 37,740 | 96,346 | ||||||||||||||||||||||||||||||||||
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The following table shows the Company’s production, revenues, realized prices, and expenses for the periods presented.
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2019 | 2018 | |||||||||||||||||||||||||||||||||||||||||
(Unaudited) (Dollars in thousands, except for realized prices) | ||||||||||||||||||||||||||||||||||||||||||||
| Production: | ||||||||||||||||||||||||||||||||||||||||||||
| Oil and condensate (MBbls) | 1,147 | 1,339 | 4,777 | 4,962 | ||||||||||||||||||||||||||||||||||||||||
Natural gas (MMcf)1 | 18,611 | 19,417 | 77,635 | 71,622 | ||||||||||||||||||||||||||||||||||||||||
| Equivalents (MBoe) | 4,249 | 4,575 | 17,716 | 16,899 | ||||||||||||||||||||||||||||||||||||||||
| Equivalents/day (MBoe) | 46.2 | 49.7 | 48.5 | 46.3 | ||||||||||||||||||||||||||||||||||||||||
| Realized prices, without derivatives: | ||||||||||||||||||||||||||||||||||||||||||||
| Oil and condensate ($/Bbl) | $ | 55.49 | $ | 57.77 | $ | 55.20 | $ | 62.53 | ||||||||||||||||||||||||||||||||||||
Natural gas ($/Mcf)1 | 2.29 | 4.02 | 2.57 | 3.47 | ||||||||||||||||||||||||||||||||||||||||
| Equivalents ($/Boe) | $ | 25.02 | $ | 33.97 | $ | 26.13 | $ | 33.05 | ||||||||||||||||||||||||||||||||||||
| Revenue: | ||||||||||||||||||||||||||||||||||||||||||||
| Oil and condensate sales | $ | 63,647 | $ | 77,358 | $ | 263,678 | $ | 310,278 | ||||||||||||||||||||||||||||||||||||
Natural gas and natural gas liquids sales1 | 42,643 | 78,064 | 199,265 | 248,243 | ||||||||||||||||||||||||||||||||||||||||
| Lease bonus and other income | 13,987 | 7,600 | 29,833 | 36,216 | ||||||||||||||||||||||||||||||||||||||||
| Revenue from contracts with customers | 120,277 | 163,022 | 492,776 | 594,737 | ||||||||||||||||||||||||||||||||||||||||
| Gain (loss) on commodity derivative instruments | (17,249) | 83,025 | (4,955) | 14,831 | ||||||||||||||||||||||||||||||||||||||||
| Total revenue | $ | 103,028 | $ | 246,047 | $ | 487,821 | $ | 609,568 | ||||||||||||||||||||||||||||||||||||
| Operating expenses: | ||||||||||||||||||||||||||||||||||||||||||||
| Lease operating expense | $ | 4,168 | $ | 5,648 | $ | 17,665 | $ | 18,415 | ||||||||||||||||||||||||||||||||||||
| Production costs and ad valorem taxes | 15,614 | 17,425 | 60,533 | 64,364 | ||||||||||||||||||||||||||||||||||||||||
| Exploration expense | 25 | 1,161 | 397 | 7,943 | ||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion, and amortization | 24,651 | 34,518 | 109,584 | 122,653 | ||||||||||||||||||||||||||||||||||||||||
| General and administrative | 13,603 | 16,296 | 63,353 | 76,712 | ||||||||||||||||||||||||||||||||||||||||
| Per Boe: | ||||||||||||||||||||||||||||||||||||||||||||
| Lease operating expense (per working interest Boe) | $ | 4.08 | $ | 4.41 | $ | 4.00 | $ | 3.55 | ||||||||||||||||||||||||||||||||||||
| Production costs and ad valorem taxes | 3.67 | 3.81 | 3.42 | 3.81 | ||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion, and amortization | 5.80 | 7.54 | 6.19 | 7.26 | ||||||||||||||||||||||||||||||||||||||||
| General and administrative | 3.20 | 3.56 | 3.58 | 4.54 | ||||||||||||||||||||||||||||||||||||||||
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 Company 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.
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Non-GAAP Financial Measures
Adjusted EBITDA and distributable cash flow are supplemental non-GAAP financial measures used by the Company's management and external users of the Company's financial statements such as investors, research analysts, and others, to assess the financial performance of the Company's assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.
The Company defines 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. The Company defines 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 U.S. GAAP financial measure. The Company's computation of Adjusted EBITDA and distributable cash flow may differ from computations of similarly titled measures of other companies.
| Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2019 | 2018 | |||||||||||||||||||||||||||||||||||||||||
(Unaudited) (In thousands, except per unit amounts) | ||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | 40,017 | $ | 164,138 | $ | 214,368 | $ | 295,560 | ||||||||||||||||||||||||||||||||||||
| Adjustments to reconcile to Adjusted EBITDA: | ||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion, and amortization | 24,651 | 34,518 | 109,584 | 122,653 | ||||||||||||||||||||||||||||||||||||||||
| Interest expense | 4,863 | 5,437 | 21,435 | 20,756 | ||||||||||||||||||||||||||||||||||||||||
| Income tax expense (benefit) | (148) | 1,250 | (335) | 2,309 | ||||||||||||||||||||||||||||||||||||||||
| Accretion of asset retirement obligations | 288 | 283 | 1,117 | 1,103 | ||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | 3,578 | 5,187 | 20,484 | 30,134 | ||||||||||||||||||||||||||||||||||||||||
| Unrealized (gain) loss on commodity derivative instruments | 26,791 | (100,799) | 32,817 | (53,066) | ||||||||||||||||||||||||||||||||||||||||
| Adjusted EBITDA | 100,040 | 110,014 | 399,470 | 419,449 | ||||||||||||||||||||||||||||||||||||||||
| Adjustments to Distributable cash flow: | ||||||||||||||||||||||||||||||||||||||||||||
| Change in deferred revenue | 15 | (40) | 42 | 1,260 | ||||||||||||||||||||||||||||||||||||||||
| Cash interest expense | (4,601) | (5,186) | (20,394) | (19,757) | ||||||||||||||||||||||||||||||||||||||||
| (Gain) loss on sale of assets, net | — | (1) | — | (3) | ||||||||||||||||||||||||||||||||||||||||
Estimated replacement capital expenditures1 | — | (2,750) | (2,750) | (11,500) | ||||||||||||||||||||||||||||||||||||||||
| Cash paid to noncontrolling interests | — | (50) | — | (211) | ||||||||||||||||||||||||||||||||||||||||
| Preferred unit distributions | (5,250) | (5,250) | (21,000) | (21,025) | ||||||||||||||||||||||||||||||||||||||||
| Distributable cash flow | $ | 90,204 | $ | 96,737 | $ | 355,368 | $ | 368,213 | ||||||||||||||||||||||||||||||||||||
Total units outstanding2 | 205,944 | 205,180 | ||||||||||||||||||||||||||||||||||||||||||
| Distributable cash flow per unit | 0.438 | 0.471 | ||||||||||||||||||||||||||||||||||||||||||
| Common unit price as of February 21, 2020 and February 22, 2019 | $ | 10.12 | $ | 18.15 | ||||||||||||||||||||||||||||||||||||||||
| Implied distributable cash flow yield | 17.3 | % | 10.4 | % | ||||||||||||||||||||||||||||||||||||||||
1 The Board established a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017, $13.0 million for the period of April 1, 2017 to March 31, 2018, and $11.0 million for the period of April 1, 2018 to March 31, 2019. Due to the expiration of the subordination period, the Company does not intend to establish a replacement capital expenditure estimate for periods subsequent to March 31, 2019.
2 The distribution attributable to the quarter ended December 31, 2019 is calculated using 205,944,172 common units as of the record date of February 17, 2020. Distributions attributable to the quarter ended December 31, 2018 were calculated using 108,851,353 common units and 96,328,836 subordinated units as of the record date of February 19, 2019.
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Proved Oil & Gas Reserve Quantities
A reconciliation of proved reserves is presented in the following table:
Crude Oil (MBbl) | Natural Gas (MMcf) | Total (MBoe) | |||||||||||||||
| Net proved reserves at December 31, 2018 | 17,567 | 314,020 | 69,904 | ||||||||||||||
| Revisions of previous estimates | 951 | 19,136 | 4,140 | ||||||||||||||
| Purchases of minerals in place | 46 | 279 | 92 | ||||||||||||||
| Extensions, discoveries, and other additions | 3,263 | 53,158 | 12,123 | ||||||||||||||
| Production | (4,777) | (77,635) | (17,716) | ||||||||||||||
| Net proved reserves at December 31, 2019 | 17,050 | 308,958 | 68,543 | ||||||||||||||
| Net Proved Developed Reserves | |||||||||||||||||
| December 31, 2018 | 17,567 | 278,233 | 63,939 | ||||||||||||||
| December 31, 2019 | 17,050 | 263,371 | 60,945 | ||||||||||||||
| Net Proved Undeveloped Reserves | |||||||||||||||||
| December 31, 2018 | — | 35,787 | 5,965 | ||||||||||||||
| December 31, 2019 | — | 45,587 | 7,598 | ||||||||||||||
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