Black Stone Minerals, L.P. — Q1 2024 Form 10-Q
Reporting period: Three months ended March 31, 2024. Black Stone Minerals owns mineral and royalty interests across 41 states and also holds non-operated working interests. The interim statements are unaudited; management cautions that quarterly results are not necessarily indicative of full-year results.
Financial performance
- Revenue: Total revenue was $105.5 million, down 39.6% from $174.6 million. Revenue from customer contracts was $116.8 million, down 4.5%; oil and condensate sales rose 16.9% to $71.2 million, while natural gas and NGL sales fell 26.8% to $42.0 million.
- Commodity derivatives: The partnership recorded an $11.3 million derivative loss, compared with a $52.3 million gain in Q1 2023. Q1 2024 included $13.8 million in realized gains and $25.1 million in unrealized losses.
- Profit: Net income was $63.9 million versus $134.4 million. After preferred-unit distributions, income attributable to common units was $56.6 million, or $0.27 per unit, versus $129.2 million, or $0.62 per unit. Operating income was $64.0 million versus $135.2 million.
- Management’s non-GAAP measures: Adjusted EBITDA was $104.1 million versus $109.9 million; distributable cash flow was $96.4 million versus $104.1 million. These measures are not substitutes for GAAP results.
- Production and prices: Equivalent production increased 3.8% to 3.668 million Boe (40.3 MBoe/d). Realized oil price excluding derivatives was $77.17/Bbl, up 0.5%; realized natural gas price was $2.55/Mcf, down 26.9%.
- Cash flow: Operating cash flow was $104.5 million, down from $137.2 million. Investing cash outflow was $24.0 million, primarily reflecting $23.0 million of mineral and royalty acquisitions. Financing cash outflow was $110.3 million, mainly common and preferred distributions.
- Liquidity and debt: Cash was $40.5 million at quarter-end, compared with $70.3 million at December 31, 2023. No credit-facility principal was outstanding; $375 million of elected commitments was unused. The borrowing base was reaffirmed at $580 million in April 2024. The partnership reported compliance with all financial covenants.
- Distributions: The Q1 common-unit distribution was $0.475 per unit. Separately, on April 17 the board approved a $0.375 per-unit distribution for Q1, payable May 17. Preferred units carry a 9.8% annual distribution rate, reset in November 2023.
Changes and notable developments
- Lower natural gas and NGL prices and the reversal from derivative gains to losses were the main reasons total revenue and net income declined year over year. Higher oil volumes partly offset these pressures.
- Cash used for mineral and royalty acquisitions increased: the partnership acquired interests for $23.0 million in Q1, primarily in the Gulf Coast region. It acquired a further $12.3 million after quarter-end.
- In December 2023, Aethon invoked temporary drilling pauses under joint exploration agreements for acreage in Angelina and San Augustine counties. In April 2024, Aethon began curtailing a small number of wells, with an expected temporary reduction of approximately 800 Boe/d, and indicated it would delay initial production from another 10 wells until the second half of 2024.
- The 2024 non-operated working-interest capital budget is approximately $2.3 million, net of farmout reimbursements; $0.3 million had been invested through March 31. The partnership also spent $0.7 million on leases around drilling programs.
Outlook, risks, and contingencies
- No specific earnings or production guidance is provided. Management expects targeted mineral and royalty acquisitions to remain part of its commercial strategy. The next scheduled credit-facility borrowing-base redetermination is October 2024.
- Management described oil prices as supported by geopolitical risks and OPEC+ production cuts, while natural gas prices were pressured by high storage inventories and mild-winter demand. The EIA forecast cited in the filing projected U.S. gas storage at 4.1 Tcf at the end of October 2024, 10% above the five-year average.
- As of March 31, the partnership had hedged 72% of available oil volumes and 69% of available natural gas volumes for 2024; for 2025, the respective proportions were 71% and 60%. Derivatives can reduce exposure to price changes but also create earnings volatility.
- Principal disclosed risks include commodity-price volatility, operator drilling and financing decisions, reserve replacement, production interruptions, transportation constraints, regulation, and the ability to generate sufficient cash for distributions. A 10% discount to SEC commodity pricing was estimated to reduce proved reserves by approximately 2.2% versus the undiscounted scenario.
- Management said routine litigation and environmental matters were not expected to have a material adverse effect; no provision for potential environmental remediation was recorded. No oil and gas property impairment was recognized in either comparative quarter.
Investor verification priorities
- Track Aethon’s resumption of drilling, the timing of delayed wells, and the effect of the reported curtailments on production and royalty revenue.
- Reconcile derivative settlements and fair-value changes with realized commodity prices and future hedge positions.
- Assess whether operating cash flow can sustain common and preferred distributions, acquisitions, and other cash needs, particularly given the preferred-unit distribution priority and 9.8% rate.
- Review the October 2024 borrowing-base redetermination, covenant headroom, and the terms and actual use of the $375 million elected credit commitment.
- Monitor natural gas prices and storage, oil and gas production volumes, and the pace and returns of mineral-interest acquisitions.