Black Stone Minerals, L.P. — Q1 2017 Form 10-Q
Business context and reporting period. Unaudited results for the three months ended March 31, 2017, compared with Q1 2016. The partnership owns oil and natural gas mineral and royalty interests across 41 states and 64 onshore basins, as well as certain non-operated working interests. Results for the quarter are not necessarily indicative of the full year.
Financial performance and liquidity
| Metric | Q1 2017 | Q1 2016 |
|---|---|---|
| Total revenue | $124.6 million | $64.4 million |
| Income from operations | $65.0 million | $11.6 million |
| Net income | $61.6 million | $10.7 million |
| Net income attributable to common and subordinated units | $60.5 million | $8.9 million |
| Basic earnings per common / subordinated unit | $0.37 / $0.26 | $0.09 / $0.01 |
| Operating cash flow | $64.0 million | $25.9 million |
| Investing cash flow | $(64.1) million | $(35.1) million |
| Financing cash flow | $4.4 million | $1.0 million |
Revenue rose 93.5%; operating margin was approximately 52.2%, compared with 18.0% in Q1 2016. Revenue included a $22.7 million commodity-derivative gain and $13.7 million of lease bonus and other income. Adjusted EBITDA, a non-GAAP measure, was $77.9 million versus $55.7 million; cash generated from operations available for distribution and reinvestment was $68.5 million versus $48.2 million.
Production averaged 35.6 thousand Boe per day, up 5.3 thousand Boe per day. Equivalent production increased 16.0% to 3.204 million Boe; oil and condensate volumes declined 2.8%, while natural gas volumes increased 25.0%. Realized prices increased 52.9% for oil and condensate and 52.0% for natural gas.
At March 31, cash was $14.0 million, current assets $90.1 million, and current liabilities $47.6 million (current ratio approximately 1.9). Credit-facility borrowings were $388.0 million, up from $316.0 million at year-end; the weighted-average rate was 3.73%. Under the then-current $500 million borrowing base, $112 million was unused. The borrowing base increased to $550 million effective April 25. The partnership reported compliance with debt covenants. The filing reports $45.4 million of distributions to common and subordinated unitholders during the quarter. Subsequent to quarter-end, the board approved Q1 distributions of $0.2875 per common unit and $0.18375 per subordinated unit, payable May 25.
Material changes versus Q1 2016
- Higher realized commodity prices, increased natural gas production, derivative gains, and higher lease bonus income drove revenue and earnings growth.
- Production costs and ad valorem taxes rose to $11.9 million from $7.1 million, largely reflecting higher prices and gas volumes; DD&A increased to $26.4 million from $21.7 million.
- No property impairment was recorded, versus $6.1 million in Q1 2016. General and administrative expense was broadly stable at $17.2 million.
- Operating cash flow increased, while investing outflows grew due to mineral-interest acquisitions. The partnership funded acquisitions partly through increased credit-facility borrowings.
Outlook, management commentary, and risks
- Management expected 2017 drilling expenditures of $50–$60 million, with approximately 90% directed to the Haynesville/Bossier play. Q1 drilling and completion costs were $20.4 million; mineral-interest acquisition costs were approximately $60.6 million.
- A Canaan farmout covering San Augustine County acreage is expected to reduce capital expenditures by approximately $30–$35 million in 2017 and an average of $40–$50 million annually thereafter, while providing overriding royalty interests. These are estimates, not guarantees.
- Management reported hedging, including contracts entered into after quarter-end, approximately 95.9% and 95.5% of available oil hedge volumes and 98.8% and 99.2% of available natural gas hedge volumes for the remainder of 2017 and 2018, respectively. Derivatives are not designated as accounting hedges; fair-value changes affect reported earnings.
- Key risks include oil and gas price volatility, production levels and operator activity, reserve replacement, acquisition execution, transportation and service availability, regulatory and environmental requirements, and the ability to generate cash sufficient for distributions. Distributions are not contractually guaranteed and may be changed by the board.
- Ten derivative counterparties were rated Baa1 or better by Moody’s; the partnership estimated $13.2 million of fair-value exposure if counterparties collectively failed to perform. A 1% interest-rate increase on quarter-end debt was estimated to raise quarterly interest expense by about $1.0 million.
- Management said routine litigation was not expected to have a material adverse effect; no environmental remediation provision was recorded. No material change to previously disclosed risk factors or material off-balance-sheet arrangements was reported.
- Subsequent to quarter-end, the partnership agreed to acquire additional East Texas mineral interests for 2.0 million common units and $2.2 million cash, subject to closing conditions and adjustments. The filing also notes agreements to accelerate development in parts of the Shelby Trough.
Investor verification points
- Separate recurring operating performance from derivative fair-value gains and unusually high lease bonus income when assessing the earnings increase.
- Verify acquisition closings, consideration, and integration, including the East Texas transactions announced after quarter-end.
- Track borrowing-base availability, debt balances, floating-rate costs, covenant headroom, and future redeterminations.
- Assess whether production, realized prices, lease activity, and hedge coverage support the stated drilling budget and distribution policy.
- Confirm the timing and impact of the Canaan farmout and the estimated capital savings, and monitor preferred-unit redemptions and conversions.