Black Stone Minerals, L.P. — Q1 2018 Form 10-Q
Reporting period: Three months ended March 31, 2018. Black Stone Minerals owns mineral and royalty interests across 41 states and 64 onshore basins and also holds non-operated working interests. Unless otherwise noted, figures below are in U.S. dollars; financial statement amounts are in millions.
Financial results and liquidity
| Metric | Q1 2018 | Q1 2017 / prior date |
|---|---|---|
| Revenue from customer contracts | $130.8 | $101.9 |
| Total revenue, including commodity derivatives | $114.5 | $124.6 |
| Income from operations | $48.0 | $65.0 |
| Net income | $42.0 | $61.6 |
| Net income attributable to common and subordinated units | $36.7 | $60.5 |
| Basic earnings per common / subordinated unit | $0.23 / $0.13 | $0.37 / $0.26 |
| Cash provided by operating activities | $76.5 | $64.0 |
| Cash used in investing activities | $60.2 | $64.1 |
| Cash and cash equivalents at period end | $6.3 | $5.6 at Dec. 31, 2017 |
| Credit facility borrowings | $436.0 | $388.0 at Dec. 31, 2017 |
| Unused borrowing availability | $114.0 | $162.0 at Dec. 31, 2017 |
Production increased 19% to 3.814 million Boe (42.4 MBoe/day). Oil and condensate volumes rose 38.2%; natural gas volumes rose 12.0%. Realized oil and condensate price increased 30.5% to $61.33/Bbl, while realized natural gas price was essentially flat at $3.38/Mcf.
Adjusted EBITDA, a non-GAAP measure, was $95.0 million versus $77.9 million; distributable cash flow was $83.4 million versus $68.5 million. Distributions declared and paid were $0.3125 per common unit and $0.2088 per subordinated unit. The board subsequently approved the same quarterly rates for Q1, payable May 24, 2018.
Material changes versus the prior comparable period
- Customer-contract revenue increased 28.4%, reflecting higher production and oil prices. Total revenue nevertheless fell 8.1%, primarily because commodity derivative results shifted from a $22.7 million gain to a $16.3 million loss, and lease bonus and other income declined $9.1 million to $4.6 million.
- Net income attributable to common and subordinated units decreased to $36.7 million from $60.5 million. Operating expenses rose, including production costs and ad valorem taxes, DD&A, and G&A; interest expense also increased to $4.5 million from $3.5 million.
- Operating cash flow improved by $12.5 million, while investing cash outflow was slightly lower. Financing cash flow turned to a $15.7 million outflow from a $4.4 million inflow, reflecting higher distributions and credit-facility repayments.
- Q1 acquisitions totaled approximately $32.2 million, including Permian Basin and East Texas mineral and royalty interests. The Noble acquisition, completed in November 2017, contributed $10.0 million of Q1 2018 revenue.
Outlook, risks and unusual items
- Management estimated a 2018 capital expenditure budget of $32–$40 million, including $20–$25 million net of farmout reimbursements for working-interest participation and $12–$15 million for two Lower Wilcox exploratory wells. In Q1, working-interest program spending net of farmout proceeds was $21.9 million; one Lower Wilcox well cost $6.3 million. Q1 acquisition spending was additional.
- Management expected to spend approximately $12–$15 million evaluating the PepperJack prospect. After encouraging results from the first well, it planned a step-out well in Q2 2018 to further assess the prospect and support structuring a deal with an operating partner.
- At March 31, the credit facility had a $550 million borrowing base and $436 million outstanding; the borrowing base increased to $600 million effective May 4. The facility matures November 1, 2022. The Partnership reported compliance with covenants, including total debt to EBITDAX of no more than 3.5:1.0 and a current ratio of at least 1.0:1.0.
- Open commodity derivatives were fixed-price swaps. Management reported hedging 92.2% of available oil and condensate volumes and 98.7% of available natural gas volumes for 2018, with lower coverage for 2019. Derivative fair-value changes affect reported earnings; Q1 included $16.3 million of derivative losses.
- Series A preferred units were fully redeemed or converted by March 31. Series B preferred units carried a 7% annual distribution; $5.25 million of Series B distributions was reflected in Q1 results. The Series B units are convertible beginning November 29, 2019, subject to stated terms.
- Farmout partners had paid $24.8 million under the Canaan agreement and $12.4 million under the Pivotal agreement. These amounts remained recorded as long-term liabilities because wells had not been completed and working interests had not been assigned as of quarter-end.
- Management cited commodity-price volatility, production and operator activity, acquisition execution, transportation, regulation, and the ability to generate cash sufficient for distributions among material risks. It reported no material change in risk factors, no material off-balance-sheet arrangements, and no expected material adverse effect from pending litigation. No environmental remediation provision was recorded.
Important facts for investors to verify
- Whether production growth and realized oil prices can offset variable lease-bonus revenue and derivative losses.
- Current hedge positions, settlement cash flows, and exposure to derivative counterparties; the filing cited $9.5 million of fair value at risk if counterparties collectively failed to perform.
- Credit-facility availability and covenant headroom after the borrowing-base increase, along with the effect of floating interest rates; a 1% rate increase was estimated to raise quarterly interest expense by $1.1 million at the reported debt level.
- Progress, costs, and results of the PepperJack and other planned capital projects, as well as farmout obligations and acquisition integration.
- Distribution coverage and the Partnership’s ability to sustain distributions, which are not legally or contractually guaranteed.