Black Stone Minerals, L.P. (NYSE: BSM) — Q3 2019 Form 10-Q
Reporting period: Quarter and nine months ended September 30, 2019. Unaudited consolidated results. The partnership owns mineral and royalty interests across 41 states and also holds non-operated working interests. Dollar amounts below are in millions unless otherwise indicated.
Financial performance
| Metric | Q3 2019 | Q3 2018 | Nine months 2019 | Nine months 2018 |
|---|---|---|---|---|
| Total revenue, including derivatives | $137.4 | $139.7 | $384.8 | $363.5 |
| Revenue from customer contracts | $113.1 | $158.2 | $372.5 | $431.7 |
| Operating income | $75.2 | $66.2 | $190.5 | $147.7 |
| Net income | $70.2 | $60.8 | $174.4 | $131.4 |
| Net income attributable to common and subordinated units | $65.0 | $55.5 | $158.6 | $115.6 |
| Adjusted EBITDA | $96.2 | $114.2 | $299.4 | $309.4 |
| Distributable cash flow | $85.8 | $100.8 | $265.2 | $271.5 |
| Operating cash flow | Not presented for quarter | Not presented for quarter | $306.3 | $289.7 |
Operating margin, calculated as operating income divided by total revenue, was 54.8% in Q3 2019 versus 47.4% in Q3 2018, and 49.5% for the first nine months versus 40.6% in 2018. Total revenue includes non-cash derivative fair-value changes; customer-contract revenue declined in both comparisons.
- Production and pricing: Q3 production was 49.0 MBoe/day, up 1.4% year over year. Oil and condensate volumes fell 3.5%, while natural gas volumes rose 3.5%. Realized prices excluding derivatives fell 14.5% for oil and 36.5% for natural gas. For the nine months, production rose 9.3%, but realized oil, gas, and equivalent prices declined 14.3%, 18.7%, and 19.0%, respectively.
- Cash flow and investment: Nine-month investing cash outflow was $48.8 million, versus $143.7 million in 2018, reflecting lower property acquisitions and expenditures and farmout proceeds. Financing cash outflow was $260.9 million, mainly distributions, unit repurchases, and net credit-facility repayments. Cash ended at $2.0 million, down from $5.4 million at year-end 2018.
- Liquidity and debt: Credit-facility borrowings were $413.0 million at September 30, at a 4.30% weighted-average rate; reported unused availability was $262.0 million. The facility borrowing base was reduced from $675 million to $650 million effective October 23, after quarter-end. The partnership reported compliance with its covenants. Current assets were $121.3 million and current liabilities $23.0 million.
- Distributions and units: Common-unit distributions were $0.37 per unit for Q3, declared October 23 and payable November 21, 2019. The subordinated units converted one-for-one into common units on May 24, 2019; 205.952 million common units were outstanding at quarter-end. Series B preferred units carry a 7% annual distribution, and their distributions become cash-only beginning with the ninth quarter. They may first be converted into common units on November 29, 2019, subject to stated terms.
Material changes versus comparable periods
- Q3 total revenue edged down 1.7%, although customer-contract revenue fell 28.5%; a $24.3 million derivative gain, versus an $18.5 million loss in Q3 2018, substantially offset weaker commodity sales and lease bonuses.
- Nine-month total revenue increased 5.9% because derivatives swung to a $12.3 million gain from a $68.2 million loss. Customer-contract revenue declined 13.7%. Net income rose 32.7%, while Adjusted EBITDA fell 3.2% and distributable cash flow fell 2.3%.
- Lower oil and gas prices and lower lease-bonus income pressured sales, partly offset by higher production, particularly natural gas. Lower general and administrative expense, mainly reduced incentive compensation, also supported operating income.
- Nine-month common and subordinated unit distributions totaled $228.2 million, compared with $174.3 million in 2018. The company did not sell units through its ATM program in the 2019 period, compared with $38.4 million of net proceeds in 2018.
Outlook, risks and unusual items
- Shelby Trough: Management reported slower drilling activity in East Texas, partly attributed to natural-gas prices. XTO planned to postpone most remaining 2019 drilling and completions until 2020 or later; BPX had significantly reduced development and released more than 100,000 gross acres. Management intended to seek another operator or operators for the acreage in late 2019 or early 2020. A prolonged slowdown could reduce production and cash available for distributions.
- Capital plans: The 2019 development-capital budget for non-operated working interests was approximately $5 million net of farmout reimbursements; $4 million had been invested through September. The partnership acquired mineral and royalty interests for approximately $43.0 million cash and $0.9 million in units during the first nine months.
- Hedging and exposure: The partnership uses derivatives for risk management, not speculation. At September 30, it had hedged 94% of available oil volumes and 87% of available gas volumes for 2019, and 71% and 62%, respectively, for 2020. Derivative fair-value changes affect reported revenue and earnings. Counterparty credit, commodity prices, production, operator activity, and transportation capacity remain risks.
- Interest-rate sensitivity: Management estimated that a 1 percentage-point increase in rates on the September 30 debt balance would have increased nine-month interest expense by approximately $3.1 million, assuming debt remained constant. No interest-rate hedges were in place.
- Other matters: The partnership recorded no environmental-remediation provision, stated that routine litigation was not expected to have a material adverse effect, and had not received notice exercising co-owners’ put options related to the Noble acquisition. No liability was recorded for those options. Adoption of lease accounting resulted in operating-lease assets and liabilities that management considered immaterial.
- Guidance: The filing provides no formal earnings, production, or distribution forecast. It cites EIA price forecasts, which are external estimates rather than partnership guidance. Management cautions that distributions are not legally or contractually assured.
Important facts for investors to verify
- Whether XTO’s delay and BPX’s acreage release lead to replacement operators, renewed drilling, or sustained production weakness in the Shelby Trough.
- How the lower $650 million borrowing base affects available liquidity, especially alongside distributions, acquisitions, and the $413 million outstanding balance.
- Whether realized commodity prices, production, and derivative settlements support distributable cash flow and future distributions; distinguish cash settlements from non-cash fair-value gains or losses.
- The terms and potential dilution or cash-distribution implications of Series B preferred-unit conversion eligibility beginning November 29, 2019.
- Whether acquisition returns and farmout reimbursements offset capital needs, and whether the partnership remains compliant with credit covenants as conditions change.