Black Stone Minerals, L.P. — Q3 2023 Form 10-Q
Business context and period: Black Stone Minerals owns oil and natural gas mineral and royalty interests across 41 states, plus non-operated working interests. This unaudited filing covers the three and nine months ended September 30, 2023; comparisons are with the corresponding 2022 periods.
Financial highlights
| Metric | Q3 2023 | Q3 2022 | Nine months 2023 | Nine months 2022 |
|---|---|---|---|---|
| Total revenue | $109.8 million | $216.4 million | $401.4 million | $433.2 million |
| Net income | $62.1 million | $168.5 million | $274.9 million | $293.3 million |
| Net income attributable to common units | $56.8 million | $163.2 million | $259.2 million | $277.5 million |
| Basic earnings per common unit | $0.27 | $0.78 | $1.23 | $1.33 |
| Adjusted EBITDA | $130.0 million | $123.1 million | $349.2 million | $334.7 million |
| Distributable cash flow | $124.4 million | $116.5 million | $332.1 million | $315.7 million |
Q3 operating income was $62.0 million versus $170.2 million; nine-month operating income was $276.0 million versus $297.5 million. The filing does not present a conventional operating margin. Adjusted EBITDA and distributable cash flow are non-GAAP measures and should be considered alongside GAAP results.
Production and pricing: Q3 production averaged 42.6 MBoe/day, up 6.5% year over year; nine-month production averaged 39.4 MBoe/day, up 11.0%. Q3 realized prices before derivatives fell 17.4% for oil to $78.50/Bbl and 64.6% for natural gas to $2.87/Mcf. Nine-month realized prices fell 21.6% for oil to $76.23/Bbl and 59.7% for gas to $3.07/Mcf.
Cash flow and liquidity: Operating cash flow for the first nine months was $387.1 million, compared with $268.6 million in 2022. Investing used $4.9 million and financing used $330.5 million, including $314.8 million of distributions to common and preferred unitholders. Cash was $56.0 million at September 30, 2023, versus $4.3 million at year-end 2022. Current assets were $167.0 million and current liabilities $33.8 million.
Debt: No credit-facility borrowings were outstanding at September 30, 2023, and $375 million of commitments were unused. The borrowing base was increased from $550 million to $580 million in an October 2023 redetermination, with commitments unchanged. The facility matures October 31, 2027; the partnership reported compliance with financial covenants.
Material changes and notable items
- Q3 total revenue declined 49.3% year over year, primarily because natural gas and NGL sales fell $88.9 million and derivative results worsened. Oil sales increased 6.8% as higher volumes partly offset lower prices.
- Q3 commodity derivatives produced a $26.9 million loss, including $24.2 million of realized gains and $51.1 million of unrealized losses. For the first nine months, derivatives contributed a $36.7 million gain, versus a $152.1 million loss in 2022, reflecting $65.7 million of realized gains and $29.0 million of unrealized losses.
- Despite lower nine-month revenue, higher cash receipts from derivative settlements helped lift operating cash flow. Common-unit distributions declared and paid were $0.475 per unit in Q3, versus $0.42 in Q3 2022.
- On October 18, the board approved a $0.475-per-unit Q3 distribution, payable November 16, 2023. On October 30, it authorized a new $150 million discretionary unit-repurchase program, replacing the prior $75 million program. Repurchases may be funded with cash or credit-facility borrowings; the program does not require purchases.
Outlook, risks, and contingencies
- Management provided no specific earnings or production guidance. The 2023 non-operated working-interest capital budget was approximately $4.1 million net of farmout reimbursements; $3.7 million had been invested through September.
- Management cited continuing commodity-price volatility, including weaker natural gas prices and uncertainty around supply, demand, storage, and geopolitical conditions. Derivatives partially mitigate price exposure but can create substantial period-to-period earnings volatility. At September 30, hedges covered 67% of available oil volumes and 63% of available gas volumes for 2023, and 56% of oil and 77% of gas for 2024.
- Development depends on third-party operators. Aethon had six rigs on Shelby Trough acreage; activity and well counts are detailed in the filing. Management also noted continued Austin Chalk redevelopment activity.
- Preferred units carry a 7% annual distribution. Beginning November 28, 2023, their rate resets to the greater of the existing rate or the 10-year Treasury rate plus 5.5%, and the partnership may redeem qualifying amounts during a 90-day window at $21.41 per unit. These terms could affect future cash available for common-unit distributions.
- The partnership reported no material expected environmental remediation costs and believes pending ordinary-course claims will not materially affect its financial condition or operations. It reported no property impairment for the periods presented. A 10% reduction in SEC commodity pricing would imply an estimated 2% reduction in proved reserves under the filing’s sensitivity analysis.
Important facts for investors to verify
- How production growth and realized commodity prices evolve, particularly for natural gas, and how much derivative results contribute to reported revenue and cash flow.
- Operator drilling and completion progress, including Aethon’s Shelby Trough commitments and development results.
- The preferred-unit distribution reset and redemption provisions, and their effect on cash available for common-unit distributions.
- Actual repurchases under the $150 million authorization, the source of funding, and any resulting impact on liquidity and leverage.
- Compliance with credit-facility covenants and the next borrowing-base redetermination scheduled for April 2024.