Black Stone Minerals, L.P. — 2016 Form 10-K
Reporting period: Fiscal year ended December 31, 2016. The filing was signed March 1, 2017. Black Stone is a publicly traded limited partnership focused on U.S. oil and natural gas mineral and royalty interests, with a non-operated working-interest program. It held mineral interests covering approximately 15.5 million acres and had interests in about 50,000 producing wells.
Key financial and operating metrics
| Metric | 2016 | 2015 |
|---|---|---|
| Total revenue | $260.8 million | $392.9 million |
| Net income (loss) | $20.2 million | $(101.3) million |
| Operating cash flow | $196.7 million | $284.7 million |
| Adjusted EBITDA | $262.3 million | $251.0 million |
| Cash generated from operations available for common and subordinated units and reinvestment | $232.8 million | $233.7 million |
| Capital expenditures and acquisitions, cash used | $221.5 million | $91.0 million |
| Credit-facility borrowings at year-end | $316.0 million | $66.0 million |
| Cash at year-end | $9.8 million | $13.2 million |
- Production rose 10.8% to 11.596 million Boe, or 31.7 MBoe/d. Oil and condensate volumes increased 3.2%; natural gas volumes increased 14.8%.
- Average realized prices, excluding derivative effects, fell: oil and condensate to $38.69/Bbl from $45.87; natural gas and NGLs to $2.59/Mcf from $2.80. Production costs and ad valorem taxes were $3.06/Boe, down from $3.42.
- Oil and gas revenue before derivative effects totaled $265.2 million. Derivative instruments produced a net loss of $36.5 million in 2016, versus a $90.3 million gain in 2015.
- Year-end assets were $1.129 billion; current assets were $79.0 million and current liabilities $71.3 million. The resulting current ratio was approximately 1.11. The credit-facility borrowing base was $500 million, with $184 million of unused availability; the partnership reported compliance with covenants.
- Gross margin is not presented as a distinct filing metric. Net income attributable to common units was $0.26 per unit; subordinated units recorded a loss of $0.11 per unit. Declared distributions were $1.10 per common unit and $0.74 per subordinated unit for 2016.
Material changes versus 2015
- Revenue declined 33.6%, primarily because of the $126.8 million adverse year-over-year swing in derivative results and lower realized commodity prices. Higher production and $9.0 million more lease bonus and other income partly offset the decline.
- Net income improved to $20.2 million from a $101.3 million loss. Property impairment expense fell substantially, from $249.6 million to $6.8 million, supporting the reversal to reported profitability.
- Operating cash flow fell by $88.1 million, while investing cash use rose by $130.5 million, reflecting acquisitions and higher working-interest capital spending. Borrowings increased to fund investments and other uses of cash.
- Proved reserves increased 27.4% to 63.425 million Boe. Proved developed reserves were 87.2% of the total; proved undeveloped reserves were 8.098 million Boe. The reserve estimate used SEC benchmark prices averaging $42.75/Bbl for oil and $2.48/MMBtu for natural gas, before property adjustments.
- Fourth-quarter 2016 revenue was $56.7 million and net loss was $7.3 million. Production was adversely affected by estimated shut-ins of 1.0 MBoe/d during the quarter, associated with offset completion work and Haynesville processing-plant downtime.
Outlook, management commentary, and risks
- Management described commodity prices as the largest variable affecting results and said active leasing, hedging, and expense and capital discipline supported 2016 performance. The partnership’s objective is long-term growth in reserves, production, and operating cash, while growing distributions when practicable.
- For 2017, the working-interest drilling budget was expected to be $50–$60 million, with approximately 90% directed to Haynesville/Bossier. A February 2017 farmout covering San Augustine County acreage was expected to reduce capital obligations by $30–$35 million in 2017 and by an average of $40–$50 million annually thereafter, while providing overriding royalty interests.
- Management cited an EIA outlook for oil prices to remain below $60/Bbl through the end of 2018. It also noted potential natural-gas price support from lower-than-average inventories and increasing pipeline and LNG exports. These are third-party expectations, not company guidance.
- Commodity hedges covered, including contracts entered after year-end, 90.3% of available oil hedge volumes and 91.1% of available natural-gas hedge volumes for 2017; 2018 coverage was 97.2% for oil and 60.3% for natural gas. Derivatives were not designated as accounting hedges, so fair-value changes affected reported earnings.
- Key risks include commodity-price declines, dependence on unaffiliated operators’ drilling decisions and financing, reserve-estimate uncertainty, acquisition and capital-funding risks, and possible borrowing-base reductions or covenant restrictions on distributions. Regulatory, environmental, hydraulic-fracturing, induced-seismicity, transportation, and Louisiana mineral-servitude risks are also discussed.
- The board approved a fourth-quarter distribution of $0.2875 per common unit and $0.18375 per subordinated unit, paid February 27, 2017. Distributions are discretionary, are subject to preferred-unit priority and debt restrictions, and are not guaranteed by the partnership agreement.
- The filing reports no material off-balance-sheet arrangements and no legal proceedings believed likely to have a material adverse effect. Management and the auditor concluded that internal control over financial reporting was effective; the financial-statement audit opinion was unqualified.
Most important facts for investors to verify
- Reconcile the large revenue decline with the impact of derivatives, realized prices, lease bonuses, and production growth; distinguish cash settlements from unrealized derivative marks.
- Review current hedge positions, settlement prices, counterparty exposure, and how much future production is covered.
- Assess the $316 million debt balance, $500 million borrowing base, $184 million availability, covenant headroom, and the next borrowing-base redetermination.
- Test reserve growth and PUD development assumptions against actual operator activity, capital requirements, and the filing’s sensitivity showing a 10% price reduction would lower proved volumes by about 7%.
- Evaluate whether operating cash flow can support distributions, acquisitions, and working-interest spending, including the preferred units’ 10% yield and distribution priority.
- Confirm the expected capital savings and royalty terms of the Canaan farmout, and track subsequent acquisitions, unit issuance, production, and quarterly distribution decisions.