Black Stone Minerals, L.P. — Q3 2022 Form 10-Q Summary
Reporting period: Quarter and nine months ended September 30, 2022. Black Stone Minerals owns mineral and royalty interests across 41 states and also holds non-operated working interests. The interim financial statements are unaudited.
Financial performance
| Metric | Q3 2022 | Q3 2021 | Nine months 2022 | Nine months 2021 |
|---|---|---|---|---|
| Total revenue, including derivative results | $216.4 million | $59.8 million | $433.2 million | $179.8 million |
| Revenue from customer contracts | $221.2 million | $137.4 million | $585.3 million | $344.8 million |
| Net income | $168.5 million | $16.2 million | $293.3 million | $47.8 million |
| Net income attributable to general partner and common units | $163.2 million | $10.9 million | $277.5 million | $32.0 million |
| Adjusted EBITDA | $123.1 million | $76.5 million | $334.7 million | $214.8 million |
| Distributable cash flow | $116.5 million | $70.2 million | $315.7 million | $196.1 million |
| Operating cash flow | Not stated separately for quarter | Not stated separately for quarter | $268.6 million | $183.4 million |
Q3 diluted earnings were $0.75 per common unit versus $0.05; nine-month diluted earnings were $1.31 versus $0.15. The filing does not report a standard operating-margin metric.
- Production and prices: Q3 production averaged 40.0 thousand Boe/day, up 5.3% year over year; nine-month average production was 35.5 thousand Boe/day, down 5.8%. Q3 realized prices, excluding derivatives, rose 41.6% for oil to $95.07/Bbl and 71.5% for natural gas to $8.11/Mcf. Nine-month realized prices increased 58.7% for oil and 102.9% for natural gas.
- Derivative effects: Derivative losses in revenue were $4.7 million in Q3 versus $77.6 million in Q3 2021, and $152.1 million for the first nine months versus $164.9 million. Q3 included $68.9 million of realized losses and $64.1 million of unrealized gains. Nine-month cash settlements paid were $162.6 million.
- Costs: Q3 operating expenses were $46.2 million, versus $42.3 million. Higher production and ad valorem taxes reflected higher commodity prices; DD&A declined to $12.2 million from $14.9 million. Nine-month operating expenses were $135.7 million versus $128.1 million, including higher production taxes.
- Cash and capital allocation: Nine-month investing cash outflow was $0.7 million, including $11.8 million of property additions and $11.3 million of farmout proceeds. Financing cash outflow was $275.9 million, principally reflecting $228.2 million of common-unit distributions and $15.8 million of preferred distributions. Cash declined by $8.0 million to $0.8 million.
- Debt and liquidity: Credit Facility borrowings were $60.0 million at September 30, down from $89.0 million at year-end; the weighted-average rate was 5.50%. Reported unused availability was $340.0 million. The Partnership said it complied with financial covenants. Total liabilities were $149.1 million; current assets were $161.0 million and current liabilities $71.5 million.
Material changes and operating developments
- Q3 revenue growth primarily reflected higher oil, natural gas and NGL sales and substantially lower derivative losses. Nine-month sales growth was driven by higher realized prices despite lower overall production.
- Natural gas volumes increased in Q3, supported by new activity in Louisiana’s Haynesville/Bossier trend. For the nine-month period, production declined as natural declines in the Shelby Trough outpaced new development and farmouts reduced working-interest volumes.
- Management reported Aethon had turned ten Angelina County wells to sales and commenced operations on eight more; in San Augustine County, four wells were turned to sales, with one being drilled and another awaiting completion. The Austin Chalk redevelopment had 22 modern-completion wells producing, with five more being drilled or completed.
- The common-unit distribution declared and paid was $0.42 for Q3 2022, versus $0.25 a year earlier. After quarter-end, the Board approved a $0.45 per-unit distribution, payable November 17, 2022.
Outlook, risks and unusual items
- No full-year financial or production guidance is stated. The 2022 non-operated working-interest capital budget was approximately $2.0 million net of farmout reimbursements; $0.5 million had been invested through September.
- On October 31, 2022, the Partnership amended its revolving credit agreement: maturity was extended to October 31, 2027, the borrowing base increased to $550 million, and elected lender commitments were reduced to $375 million. The amendment also replaced LIBOR with SOFR-based rates. These were post-quarter changes.
- The Partnership uses fixed-price swaps to partly mitigate commodity-price volatility and does not designate them as accounting hedges. At September 30, it had hedged 98% of available 2022 and 66% of 2023 oil volumes, and 72% of available 2022 and 65% of 2023 natural-gas volumes. Swap settlements can materially reduce cash receipts when market prices exceed contract prices.
- Management cited commodity-price volatility, inflation and higher interest rates, potential recession, operator drilling activity and financing, LNG export capacity, pipeline access, and environmental and regulatory matters as risks. It warned that these conditions may affect cash generation and distributions. Common-unit distributions are not contractually guaranteed; credit-agreement restrictions can also limit distributions.
- Environmental remediation costs were not considered significant and no provision was recorded. Management said existing litigation was not expected to materially affect financial condition or operations. No impairment of oil and gas properties was recorded for the periods presented.
Key facts investors should verify
- How much future cash flow and distributable cash flow may be reduced by derivative settlements, particularly given the size and pricing of the open swaps.
- Whether Shelby Trough and other operator-led development can offset natural production declines, and whether Aethon meets its drilling commitments.
- Whether the $0.45 common-unit distribution is sustainable under commodity-price, production, interest-rate and covenant scenarios; the preferred units carry a 7% annual distribution.
- The effect of the amended borrowing base, lower elected commitments, SOFR transition and future borrowing-base redeterminations on liquidity and borrowing costs.
- Whether the quarter’s higher production and prices persist, and how much reported earnings reflect derivative fair-value movements rather than realized operating cash flows.