Black Stone Minerals, L.P. — FY2018 Form 10-K
Reporting period: Fiscal year ended December 31, 2018. This is an annual filing, not a standalone fourth-quarter report; quarterly figures are identified separately below. The partnership owns mineral and royalty interests and non-operated working interests across 41 states. Its core mineral and royalty assets are largely non-cost-bearing.
Financial and operating results
| Metric | 2018 | 2017 | Change |
|---|---|---|---|
| Total revenue | $609.6 million | $429.7 million | +41.9% |
| Net income | $295.6 million | $157.2 million | +88.1% |
| Operating income | $318.4 million | $172.1 million | +85.0% |
| Cash from operating activities | $385.4 million | $281.9 million | +$103.5 million |
| Adjusted EBITDA | $419.4 million | $309.8 million | +35.4% |
| Distributable cash flow | $368.2 million | $273.3 million | +34.8% |
| Production | 16.899 million Boe | 13.515 million Boe | +25.0% |
Operating margin was approximately 52.2% of revenue, compared with 40.0% in 2017; net margin was approximately 48.5%, compared with 36.6%. Growth reflected higher production and realized commodity prices. Production averaged 46.3 MBoe/d. Realized oil and condensate prices rose to $62.53/Bbl from $47.78; realized natural gas prices, including NGL value, rose to $3.47/Mcf from $3.19. Production costs and ad valorem taxes increased to $64.4 million from $47.5 million.
Oil and condensate sales were $310.3 million, natural gas and NGL sales were $248.2 million, lease bonus and other income was $36.2 million, and derivative gains were $14.8 million. Derivative cash settlements were a net $38.2 million paid, versus $15.2 million received in 2017. No oil and natural gas property impairment was recorded in 2018 or 2017. A $6.8 million PepperJack B#1 exploratory well cost was expensed.
Fourth-quarter context: 2018 Q4 revenue was $246.0 million and net income was $164.1 million, versus revenue of $95.4 million and net income of $19.4 million in Q4 2017. The filing’s quarterly table reports Q4 operating income of $170.7 million. Investors should examine the quarter’s drivers, including production, pricing, and derivative valuations, rather than treating the quarterly result as a run rate.
Cash, debt, liquidity, and distributions
At year-end, cash was $5.4 million, current assets were $157.5 million, and current liabilities were $64.8 million. The reported current ratio was approximately 2.4. Long-term credit-facility borrowings were $410.0 million, up from $388.0 million; the weighted-average interest rate was 4.76%. The borrowing base was $675.0 million, leaving $265.0 million of available borrowing capacity. The facility matures November 1, 2022; the partnership reported compliance with its covenants at year-end. Covenants include total debt/EBITDAX of no more than 3.5:1 and a current ratio of at least 1.0:1.
Investing cash outflow was $163.8 million, compared with $454.2 million in 2017, reflecting lower acquisition spending and $124.5 million of farmout proceeds. Financing cash outflow was $221.8 million, including distributions and unit repurchases. The partnership acquired interests for total consideration of $149.9 million in 2018, including $22.6 million in common units. It sold $40.5 million of common units through its ATM program.
Common-unit distributions declared for 2018 totaled $1.33 per unit and subordinated-unit distributions totaled $1.13. The Q4 distribution was $0.37 per common and subordinated unit, approved in February 2019. Distributions are not contractually guaranteed and are determined by the general partner’s board after reserves and required preferred distributions. Series B preferred units carry a 7% annual distribution priority; $21.0 million was attributed to Series B distributions in 2018. The $75 million common-unit repurchase authorization announced in November 2018 resulted in $2.0 million of repurchases during the year.
Material changes and portfolio
- Proved reserves increased 2.9% to 69.9 million Boe from 67.9 million Boe. Proved developed reserves were 91.5% of the total, up from 83.5%; proved undeveloped reserves were 6.0 million Boe, down from 11.2 million.
- Production growth was strongest in oil and condensate: volumes increased 39.7%, while natural gas volumes increased 19.8%. Mineral and royalty oil production rose substantially, led by the Permian and Bakken/Three Forks.
- Acquisition consideration was lower than the prior year’s major acquisition activity: 2018 acquisitions totaled $149.9 million, while 2017 included the Noble acquisition and other purchases. In 2018, acquisitions were concentrated primarily in the Permian Basin and East Texas.
- Farmout agreements with Canaan and Pivotal had generated cumulative receipts of $80.7 million and $63.0 million, respectively, by year-end. Management expected these arrangements to keep net working-interest capital needs minimal in 2019.
- Common and subordinated units outstanding increased during 2018. The partnership also reported Series B preferred units outstanding of 14.7 million; these may convert into common units beginning November 2019 under the stated terms.
Outlook, commentary, and risks
Management’s stated objective is long-term growth in reserves, production, and operating cash while paying a growing distribution where practicable. The 2019 non-operated working-interest capital budget was approximately $10 million, mainly for workovers and leasehold acreage intended for farmout. The filing cites EIA forecasts of average WTI prices of $54.79/Bbl in 2019 and $58.00/Bbl in 2020, and Henry Hub gas prices of $2.83/MMBtu and $2.80/MMBtu, respectively; these are external forecasts, not company guidance. The filing does not provide a clear company-wide production or earnings forecast.
- Commodity exposure: Revenue, reserves, borrowing capacity, and distributions are sensitive to oil and gas prices. The partnership hedged 70.2% of available 2019 oil volumes and 93.2% of available 2019 gas volumes as of year-end; hedges limit, but do not eliminate, price risk.
- Concentration and operator dependence: Two Shelby Trough operators accounted for 21.4% of 2018 revenue and 36.7% of production. XTO Energy alone represented 15.4% of revenue. The partnership generally depends on unaffiliated operators for drilling and production decisions.
- Distribution and financing risk: Distributions are discretionary, preferred units rank ahead of common and subordinated units, and credit-facility provisions can restrict distributions. Debt is secured by substantially all partnership assets and the borrowing base is subject to redetermination.
- Exploration and contingencies: PepperJack A#1 was considered prospective and entered completion operations in Q4; the partnership retained a 25% working interest. PepperJack B#1 was not expected to be completed in the near term, prompting the $6.8 million expense. A pipeline extension agreement could require payment of the partnership’s 50% share of unrecovered costs if fees fail to recover them within four years; management expected full recovery and recorded no liability.
- Other risks: The filing discusses environmental and hydraulic-fracturing regulation, water disposal and induced seismicity, pipeline constraints, Louisiana mineral-servitude reversion, reserve-estimation uncertainty, cyber threats, and climate-related regulatory and demand risks. Management said ordinary-course legal matters were not expected to have a material adverse effect.
The partnership adopted ASC 606 on January 1, 2018 using the modified retrospective method and reported no material financial-statement impact. Management and the independent auditor concluded internal control over financial reporting was effective as of year-end; the financial-statement audit opinion was unqualified.
Most important facts for investors to verify
- Whether 2018’s production and revenue growth can persist, particularly in the Permian, Bakken, and Haynesville/Bossier assets, and how Q4 results compare with normalized operating trends.
- Current realized prices, hedge coverage and settlements, derivative fair values, and the effect of price changes on cash flow, reserves, and borrowing capacity.
- Debt covenant headroom and the outcome of the scheduled April 2019 borrowing-base redetermination, alongside the $265 million year-end availability.
- Distribution sustainability after Series B preferred distributions, capital spending, acquisitions, and the potential conversion of subordinated units and Series B preferred units.
- Operator activity and development plans in the Shelby Trough, and whether Canaan and Pivotal continue funding farmout wells as expected.
- Progress and remaining exposure on PepperJack and the pipeline extension cost-recovery arrangement.