Black Stone Minerals, L.P. — Form 10-Q Summary
Reporting period: Quarter and nine months ended September 30, 2016. Financial statements are unaudited. The Partnership owns mineral and royalty interests across 41 states and 61 onshore basins, as well as non-operated working interests.
Financial performance and liquidity
| Metric | Q3 2016 | Q3 2015 | Nine months 2016 | Nine months 2015 |
|---|---|---|---|---|
| Total revenue | $99.2 million | $137.0 million | $204.1 million | $292.9 million |
| Operating income (loss) | $39.3 million | $54.7 million | $31.4 million | $(46.3) million |
| Net income (loss) | $37.5 million | $53.9 million | $27.5 million | $(51.6) million |
| Operating cash flow | Not reported separately | Not reported separately | $141.6 million | $217.2 million |
| Cash used in investing | Not reported separately | Not reported separately | $(203.8) million | $(104.2) million |
- Q3 production averaged 35.0 thousand Boe/day, up 20.4% in total volume from the prior-year quarter. Nine-month production averaged 32.3 thousand Boe/day, up 10.6%.
- Nine-month realized prices fell year over year: oil and condensate to $36.72/Bbl from $47.45; natural gas to $2.38/Mcf from $2.92; and equivalent production to $21.50/Boe from $27.52.
- At September 30, cash was $4.8 million, current assets were $84.2 million, and current liabilities were $44.4 million. Credit-facility debt was $299.0 million, with $151.0 million of borrowing availability under the then-effective borrowing base. The Partnership reported compliance with financial covenants.
- The revolving facility had a $450 million borrowing base at September 30; a subsequent redetermination raised it to $500 million effective October 31. Facility maturity is February 2019. The weighted-average interest rate was 2.53% at quarter-end.
- Total assets were $1.137 billion; total liabilities were $364.3 million, including $54.0 million of redeemable preferred units classified as mezzanine equity. The filing gives no separate gross-margin measure.
Changes versus comparable periods
- Q3 revenue declined 27.6% year over year, mainly because derivative gains were much smaller ($7.8 million versus $56.4 million). Higher production and lease bonus income partly offset the decline. Q3 net income fell to $37.5 million from $53.9 million.
- For the first nine months, revenue fell 30.3%. The $69.7 million year-over-year deterioration in derivative results and lower realized commodity prices outweighed higher production and lease bonus income. Net income improved from a $51.6 million loss to $27.5 million profit, largely alongside substantially lower impairment expense ($6.8 million versus $156.7 million).
- Nine-month operating cash flow decreased by $75.6 million. Management attributed the decline primarily to lower cash collections from oil and gas sales and working-capital changes. Investment outflows increased with acquisitions and working-interest capital spending.
- Debt increased from $66.0 million at December 31, 2015 to $299.0 million at September 30, 2016. Cash distributions to common and subordinated unitholders were $130.9 million for the nine months.
Outlook, management commentary, risks and unusual items
- Management expected 2016 drilling expenditures of $70–$75 million, including $65–$70 million in the Haynesville/Bossier play. It reported $50.4 million spent on drilling and completion through September 30. The filing does not provide full-year revenue or earnings guidance.
- Management’s stated objective is long-term growth in reserves, production and operating cash, with distributions to unitholders when practicable. The distribution policy is not a contractual guarantee. A November 7, 2016 distribution approval set $0.2875 per common unit and $0.18375 per subordinated unit.
- Open swaps covered, including contracts entered after quarter-end, 92.6% of available oil hedge volumes and 96.8% of available natural-gas hedge volumes for the remainder of 2016; coverage for 2017 was 78.7% and 99.7%, respectively. Derivative fair-value changes flow through revenue rather than hedge accounting.
- Acquisitions during 2016 included Permian Basin interests for $10.0 million, a Colorado mineral package for $34.0 million, a Freeport-McMoRan package for $87.6 million, and Texas interests for $8.3 million. The Partnership also repurchased and canceled 1.3 million common units for $24.7 million under a program that ended September 15.
- Commodity prices, production on operator-controlled properties, operator access to capital, acquisition execution, transportation, regulation and counterparty/customer credit are key risks. Management noted continued commodity-price volatility and elevated natural-gas storage levels. A 10% discount to SEC commodity pricing was estimated to reduce proved reserves by approximately 3.0%.
- Environmental remediation costs were not considered significant and no provision was recorded. Management said pending litigation was not expected to have a material adverse effect; no material changes to previously disclosed risk factors or contractual obligations were reported. The CFO planned to step down effective November 11, 2016, with a successor expected to be appointed.
Important facts for investors to verify
- Whether production growth and lease-bonus activity can offset weaker realized prices and changing derivative gains or losses.
- Liquidity, debt levels, borrowing-base availability, interest costs and continued compliance with credit-facility covenants.
- Whether acquisition spending and planned working-interest capital expenditures generate adequate returns and sustainable cash flow after distributions.
- The assumptions underlying reserve estimates, impairment assessments and hedge volumes, including commodity-price and operator-performance exposure.
- The effect of preferred-unit redemption or conversion rights and the sustainability of distributions, which are not guaranteed.