Black Stone Minerals, L.P. — Q3 2021 Form 10-Q
Reporting period: Three and nine months ended September 30, 2021. Black Stone Minerals owns mineral and royalty interests across 41 states, including interests in more than 70,000 producing wells, and also holds non-operated working interests.
Financial performance and liquidity
| Metric | Q3 2021 | Q3 2020 | Nine months 2021 | Nine months 2020 |
|---|---|---|---|---|
| Revenue from customer contracts | $137.4 million | $64.8 million | $344.8 million | $215.6 million |
| Total revenue, including derivative gains or losses | $59.8 million | $43.7 million | $179.8 million | $265.3 million |
| Operating income | $17.5 million | $25.2 million | $51.8 million | $100.4 million |
| Net income | $16.2 million | $23.7 million | $47.8 million | $91.5 million |
| Net income attributable to common units; EPS | $10.9 million; $0.05 | $18.5 million; $0.09 | $32.0 million; $0.15 | $75.7 million; $0.37 |
| Adjusted EBITDA | $76.5 million | $65.5 million | $214.8 million | $209.0 million |
| Distributable cash flow | $70.2 million | $58.8 million | $196.1 million | $189.5 million |
- Production and realized prices: Q3 production was 38.0 MBoe/day, essentially flat year over year. Realized prices excluding derivatives rose 86% for oil to $67.15/Bbl and 148% for natural gas to $4.73/Mcf. For the first nine months, production fell 11.6% to 37.7 MBoe/day, while equivalent realized prices rose 81% to $32.33/Boe.
- Margins and earnings drivers: Higher commodity prices lifted product sales, but derivative losses and a $24.0 million asset-sale gain in Q3 2020 affected comparisons. Q3 2021 included $77.6 million of derivative losses, versus $21.1 million in Q3 2020. Nine-month derivative results swung to a $164.9 million loss from a $49.8 million gain. Operating income and net income also reflect the prior-year $51.0 million impairment, which did not recur in 2021. The filing does not present a single standardized operating-margin measure.
- Cash flow: Nine-month operating cash flow was $183.4 million, down from $221.4 million, mainly because derivative settlements shifted from $66.8 million received in 2020 to $56.0 million paid in 2021. Investing activities used $13.9 million, compared with $150.6 million provided in 2020, when asset-sale proceeds were substantial. Financing activities used $168.1 million.
- Balance sheet and debt: At September 30, cash was $3.3 million, accounts receivable $88.3 million, and total assets $1.247 billion. Credit-facility borrowings were $99.0 million, down from $121.0 million at year-end 2020; $301.0 million remained available under the $400 million borrowing base. The facility matures November 2024. The Partnership reported compliance with its financial covenants.
- Liquidity consideration: Current liabilities were $131.5 million versus current assets of $93.1 million, primarily reflecting $114.5 million of current derivative liabilities. The filing reports covenant compliance; the current-ratio covenant is defined under the credit agreement.
Material changes and developments
- Product revenue increased substantially year over year as oil and gas prices recovered, but nine-month total revenue declined because derivative results reversed from gains to losses.
- Lower nine-month production reflected, among other factors, 2020 Permian Basin divestitures and lower working-interest gas volumes in the Haynesville/Bossier area.
- Q3 general and administrative expense rose 31% to $12.3 million, primarily from higher cash and equity incentive compensation. Nine-month G&A increased 14% to $37.4 million; 2020 included restructuring costs that did not recur.
- The Partnership acquired northern Midland Basin acreage in Q2 for $20.8 million, paid with $10.0 million cash and $10.8 million in common units. In Q3 it sold TLW Investments for $0.2 million and recorded a $2.9 million gain; TLW carried $3.0 million of net property book value and $5.7 million of asset-retirement obligations.
- Common-unit distributions were $0.25 per unit for Q3 and $0.60 per unit for the first nine months, compared with $0.15 and $0.53, respectively, in 2020. The board approved the Q3 $0.25 distribution after quarter-end, payable November 19, 2021. Preferred-unit distributions were $5.25 million per quarter.
Outlook, risks, and contingencies
- No earnings or revenue guidance is provided. The 2021 non-operated working-interest capital budget was approximately $5.0 million, net of farmout reimbursements; $4.1 million had been spent through September. Planned spending primarily covers Austin Chalk test-well participation and workovers.
- Management said commodity prices had recovered in 2021 but remained uncertain. It cited commodity-price volatility, COVID-19 developments, operator drilling activity and access to capital, production levels, transportation capacity, regulation, and the ability to generate cash sufficient for distributions as key risks. Common-unit distributions are not contractually guaranteed and remain subject to board discretion and facility restrictions.
- Hedges partially mitigate price volatility but can produce significant cash and accounting losses when market prices exceed swap prices. At quarter-end, derivative liabilities totaled $128.9 million. The Partnership had hedged 100% of available 2021 oil volumes and 84% of available 2021 gas volumes, with hedge coverage declining for later periods. Derivatives are not designated as accounting hedges, so fair-value changes affect current-period revenue.
- Development updates: Aethon brought the first two Angelina County program wells to sales and began work on four more; in October 2021 it spud the first three San Augustine County wells. One Austin Chalk well had been brought to sales and five more were being drilled. Farmout commitments and operator execution remain important to development outcomes.
- The Partnership said it did not expect the LIBOR transition to materially affect it. Environmental remediation costs were not considered significant and no provision was recorded. Management believed pending routine litigation would not materially affect financial condition or operations. No material off-balance-sheet arrangements were reported.
Important facts for investors to verify
- How hedge settlements and mark-to-market liabilities affect future cash flow and reported revenue as contracts mature.
- Whether production stabilizes or continues to decline, especially in working-interest properties, and whether operator drilling commitments are met.
- Borrowing-base capacity, covenant headroom, and liquidity at future redeterminations; the next scheduled redetermination was April 2022.
- Whether operating cash flow and distributable cash flow support common distributions after preferred distributions, capital spending, and debt needs.
- The economics and execution progress of the Midland Basin acquisition, TLW divestiture, and Aethon/Pivotal/Canaan development and farmout arrangements.