Black Stone Minerals, L.P. — Q1 2021 Form 10-Q
Business context and period. Black Stone Minerals owns oil and natural gas mineral and royalty interests across 41 U.S. states, as well as non-operated working interests. This unaudited report covers the three months ended March 31, 2021; comparisons are to Q1 2020. The partnership operates as one reportable segment.
Financial results and position
| Metric | Q1 2021 | Q1 2020 |
|---|---|---|
| Revenue, including derivative gains/losses | $61.6 million | $183.1 million |
| Revenue from customer contracts | $89.5 million | $93.0 million |
| Operating income | $17.2 million | $80.5 million |
| Net income | $16.2 million | $76.1 million |
| Net income attributable to general partner and common units | $10.9 million; $0.05 per unit | $70.9 million; $0.34 per unit |
| Operating cash flow | $55.7 million | $71.5 million |
| Distributable cash flow (non-GAAP) | $53.8 million | $66.2 million |
| Capital spending on oil and gas properties | $0.2 million | $3.5 million |
Revenue fell 66% year over year, principally because commodity derivatives produced a $27.9 million loss versus a $90.0 million gain in Q1 2020. The 2021 derivative result included $4.5 million of realized losses and $23.4 million of unrealized losses. Without derivatives, customer-contract revenue declined 3.9%: higher realized prices and natural gas/NGL sales partly offset lower volumes, lower oil sales, and reduced lease bonus income.
Production declined: oil and condensate volumes were down 28.7%, natural gas down 19.9%, and total equivalent production down 22.3%. Average realized prices rose 19.0% for oil and 46.2% for natural gas. There was no property impairment in Q1 2021, compared with $51.0 million in Q1 2020. DD&A declined 32.6% to $15.6 million; interest expense fell to $1.2 million from $4.4 million.
Cash and cash equivalents were $3.8 million at March 31, 2021. Current assets were $64.8 million and current liabilities $56.8 million. Credit-facility debt was $111.0 million, down from $121.0 million at year-end; $289.0 million of borrowing capacity remained under the $400 million borrowing base. The weighted-average interest rate was 2.37%. The partnership reported compliance with its financial covenants. Total liabilities were $189.4 million, and Series B preferred units were recorded as $298.4 million of mezzanine equity.
Changes, distributions, and outlook
- Common-unit distributions declared and paid were $0.175 per unit in Q1 2021, versus $0.30 in Q1 2020. The board subsequently approved another $0.175 per common unit for Q1, payable May 21, 2021. Preferred distributions were $5.25 million for the quarter.
- Operating cash flow decreased $15.8 million year over year, primarily because of cash paid on derivative settlements rather than cash received in Q1 2020. Financing cash outflow was lower, mainly because common-unit distributions decreased.
- Management budgeted approximately $5.0 million of 2021 non-operated working-interest capital expenditures, net of farmout reimbursements; $0.2 million had been spent through March 31. No formal earnings or production guidance is provided in the filing.
- After quarter-end, the credit facility borrowing base was reaffirmed at $400 million and maturity extended to November 1, 2024. Margins increased, and distribution restrictions were added, including limits when availability is below 10% of lender commitments or debt to EBITDAX is at least 3.0.
- Management described commodity prices as having recovered from 2020 lows but remaining uncertain amid the continuing effects of COVID-19. Operators’ drilling activity, commodity prices, and production remain key drivers. Management said a 10% reduction to SEC commodity prices would reduce proved reserves by approximately 4%.
- Post-quarter plans include Austin Chalk test and development activity, an Aethon development agreement in San Augustine County, and a proposed $20.7 million northern Midland Basin acquisition, funded with $10.0 million cash and $10.7 million in common units, expected to close in Q2 2021.
- Open swaps covered 100% of available 2021 oil hedge volumes and 81% of available 2021 natural gas hedge volumes; 22% of available 2022 oil volumes were hedged. Derivative liabilities were $44.4 million at quarter-end. The partnership does not use derivatives for speculation.
Risks, contingencies, and unusual items
Principal risks include oil and gas price volatility, operator drilling and financing decisions, production declines, COVID-19-related market uncertainty, reserve replacement, and potential borrowing-base reductions. The credit facility is secured by substantially all oil and gas assets and has financial covenants; distributions may be restricted under specified conditions. Derivative counterparties create credit exposure, although the seven counterparties were rated Baa1 or better. Management reported no material off-balance-sheet arrangements and believed pending litigation and environmental matters would not materially affect the partnership; no environmental remediation provision was recorded. The filing also notes that estimates of property fair value and reserves are uncertain and that lower prices could lead to future impairments.
Important facts for investors to verify
- How much of the revenue and earnings decline reflects derivative mark-to-market changes versus underlying production, prices, and lease activity.
- Whether lower production volumes persist, particularly in the Permian and Haynesville/Bossier areas, and how operator activity develops.
- The cash-flow coverage and sustainability of common-unit distributions, including the impact of preferred distributions and new credit-facility restrictions.
- Effects of the higher credit-facility margins, October 2021 borrowing-base redetermination, and floating interest rates on liquidity and debt capacity.
- Progress, costs, and results of Austin Chalk and Aethon development programs, and completion and funding of the proposed Midland Basin acquisition.