Business context and reporting period
Black Stone Minerals, L.P. is a U.S. owner and manager of oil and natural gas mineral, royalty and non-operated working interests. This Form 10-K covers the fiscal year ended December 31, 2017; it also reports fourth-quarter results. Its business emphasizes leasing mineral acreage, encouraging operator drilling and selectively funding working-interest development.
At year-end, the Partnership reported mineral interests covering approximately 16.8 million acres, plus NPRIs across 1.9 million acres and ORRIs across 2.1 million acres. Its interests spanned 41 states and included 55,728 mineral-and-royalty-interest wells. Proved reserves were 67.945 million Boe, 83.5% developed.
Key financial and operating metrics
| Metric | 2017 | 2016 |
|---|---|---|
| Total revenue | $429.7 million | $260.8 million |
| Operating income | $172.1 million | $27.5 million |
| Net income | $157.2 million | $20.2 million |
| Net income per common unit, basic | $1.01 | $0.26 |
| Operating cash flow | $281.9 million | $196.7 million |
| Cash used in investing | $454.2 million | $221.5 million |
| Adjusted EBITDA (non-GAAP) | $309.8 million | $262.3 million |
| Distributable cash flow after net working-interest capital expenditures (non-GAAP) | $233.8 million | $152.6 million |
Revenue increased 64.7%; operating margin was approximately 40.0% versus 10.5% in 2016, and net margin approximately 36.6% versus 7.7%. These margins are calculated from reported GAAP figures.
Production totaled 13.515 million Boe, or 37.0 MBoe/d, up 16.5% from 2016. Oil and condensate volumes fell 3.5% to 3.552 million barrels, while natural gas volumes rose 25.9% to 59.779 Bcf. Realized prices excluding derivatives increased to $47.78/Bbl for oil and $3.19/Mcf for natural gas. Derivative gains were $26.9 million, compared with losses of $36.5 million in 2016. Lease bonus and other income was $42.1 million.
At December 31, 2017, cash was $5.6 million, current assets $87.6 million and current liabilities $59.7 million. Credit-facility borrowings were $388.0 million at a 4.06% weighted-average rate; the borrowing base was $550.0 million, leaving $162.0 million of unused borrowing availability. The facility’s maximum credit amount was $1.0 billion and maturity was extended to November 1, 2022. The Partnership reported compliance with its covenants. Total assets were $1.576 billion.
Cash distributions declared for 2017 were $1.20 per common unit and $0.79 per subordinated unit. The fourth-quarter distribution, paid in February 2018, was $0.3125 per common unit and $0.20875 per subordinated unit. Series B preferred units have distribution priority at a 7% annual rate.
Material changes versus the prior comparable period
- Higher realized commodity prices, increased production—particularly natural gas—and improved derivative results drove the revenue and earnings recovery. Net income rose from $20.2 million in 2016; 2015 had a $101.3 million net loss.
- Production growth was led by Haynesville/Bossier and Wilcox activity. Oil volumes declined slightly even as oil sales revenue rose on higher prices.
- Cash used in investing more than doubled, largely reflecting acquisitions: property acquisitions were $425.7 million in 2017 versus $141.1 million in 2016. Operating cash flow did not cover investing outlays.
- Debt rose from $316.0 million to $388.0 million, while interest expense increased from $7.5 million to $15.7 million.
- No oil and natural gas property impairment was recorded in 2017, versus $6.8 million in 2016 and $249.6 million in 2015.
Outlook, management commentary, risks and unusual items
- The November 2017 Noble acquisition added mineral and royalty interests across 20 states for a stated purchase price of $335 million before customary adjustments. It was funded with approximately $300 million from Series B preferred units and $35 million of credit-facility borrowings. The acquisition contributed $2.8 million of 2017 revenue after closing; its purchase-price allocation remained preliminary.
- The Partnership entered into Canaan and Pivotal farmouts for East Texas working-interest development. Management expected these arrangements to reduce annual capital requirements by approximately $40–$50 million during the Canaan agreement and to make working-interest capital needs minimal beyond the first quarter of 2018.
- The 2018 working-interest drilling budget was expected to be $15–$25 million, with approximately 99% allocated to Haynesville/Bossier. Management also expected to spend $10–$12 million on two 100%-working-interest Lower Wilcox exploratory wells. These are budget expectations, not guaranteed expenditures or results.
- Management cited EIA forecasts of average WTI prices of about $58/Bbl in 2018 and 2019, and Henry Hub prices of $3.20/MMBtu in 2018 and $3.08/MMBtu in 2019. These are external forecasts, not company guidance. Year-end hedge coverage was 85.5% of available oil volumes and 98.8% of available natural gas volumes for 2018; coverage was lower for 2019.
- Key exposures include commodity-price volatility, reliance on unaffiliated operators for drilling and production, reserve-estimation uncertainty, acquisition execution and financing, borrowing-base reductions, and the possibility that operating or regulatory constraints delay development. Environmental, hydraulic-fracturing, water-disposal and induced-seismicity rules may increase costs or restrict activity. Exxon’s subsidiary XTO accounted for approximately 20.8% of 2017 revenue.
- Distributions are at the general partner’s discretion and are not guaranteed. Series B preferred distributions rank ahead of common and subordinated units; for the initial distribution period, preferred distributions could be paid in cash, in kind, or in a combination. Series A preferred units not redeemed by March 31, 2018 were to convert under their terms.
- The filing reported no material off-balance-sheet arrangements and stated that ordinary-course legal matters were not expected to materially affect financial condition or results. A co-owner put option related to acquired assets had not been exercised at year-end; no liability was recorded.
Important facts for investors to verify
- Whether production growth and realized prices persist, and the sensitivity of cash generation and reserves to lower commodity prices.
- Acquisition integration, final Noble purchase-price adjustments, and the possible exercise and valuation of the acquired co-owners’ repurchase options.
- Actual drilling, capital spending and production outcomes under the Canaan and Pivotal farmouts and the Lower Wilcox exploratory program.
- Credit-facility borrowing-base redeterminations, covenant headroom, interest costs and liquidity after acquisition spending and distributions.
- Preferred-unit distribution obligations, conversion or redemption outcomes, and the resulting effect on cash available and unit dilution.
- Reserve estimates and the assumptions underlying the reported 16.5% proved-undeveloped share; estimates are independently evaluated but remain subject to uncertainty.