Black Stone Minerals, L.P. — 2022 Form 10-K
Reporting period: Fiscal year ended December 31, 2022; this is an annual filing, not a standalone fourth-quarter report. Black Stone Minerals (NYSE: BSM) owns mineral, royalty, and non-operated working interests across U.S. oil and gas basins. Its business principally earns royalties and lease bonuses, with limited working-interest exposure.
Key financial and operating metrics
| Metric | 2022 | 2021 |
|---|---|---|
| Total revenue, including commodity derivatives | $663.6 million | $359.3 million |
| Revenue from customer contracts, before derivative gains or losses | $784.3 million | $505.7 million |
| Operating income | $482.5 million | $187.3 million |
| Net income | $476.5 million | $182.0 million |
| Basic earnings per common unit | $2.18 | $0.77 |
| Adjusted EBITDA (non-GAAP) | $466.4 million | $292.5 million |
| Distributable cash flow (non-GAAP) | $441.1 million | $267.4 million |
| Cash provided by operating activities | $425.0 million | $256.9 million |
| Production | 13.55 million Boe; 37.1 MBoe/d | 13.89 million Boe; 38.0 MBoe/d |
| Proved reserves at year-end | 64.1 million Boe | 59.8 million Boe |
- Oil and condensate realized price rose 44.8% to $93.65/Bbl; natural gas and NGL realized price rose 75.0% to $7.28/Mcf. Production volumes declined 2.4% overall.
- Commodity derivatives produced a reported net loss of $120.7 million, compared with a $146.5 million loss in 2021. In 2022, cash settlements were net losses of $203.2 million, partly offset by $82.5 million of unrealized gains.
- Net income attributable to common units was $455.5 million after $21.0 million of preferred distributions. Common distributions declared and paid totaled $1.54 per unit for 2022, versus $0.85 in 2021.
- Year-end cash was $4.3 million. Current assets were $173.4 million and current liabilities $30.7 million. Receivables were $135.7 million, including $129.1 million of accrued customer-contract revenue.
- Credit-facility borrowings were $10.0 million, down from $89.0 million. The borrowing base was $550 million, lender commitments were $375 million, and reported unused availability was $365 million. Weighted-average borrowing rate was 6.92%; the facility matures October 31, 2027. The partnership reported covenant compliance at year-end.
- Oil and gas properties, net, were $1.087 billion. No proved-property impairment was recorded in 2022 or 2021; 2020 included a $51.0 million impairment.
Material changes versus 2021
- Total revenue increased 84.7%, primarily reflecting higher realized commodity prices and a smaller derivative loss; production volumes were lower.
- Net income rose to $476.5 million from $182.0 million. Operating cash flow increased $168.1 million to $425.0 million.
- Proved reserves increased 7.2% to 64.1 million Boe. Proved undeveloped reserves rose to 5.5 million Boe from 3.3 million, mainly from Haynesville/Bossier development additions; 3.3 million Boe transferred to developed reserves.
- Common distributions paid increased to $322.4 million from $176.9 million. Financing cash outflow also increased, principally due to higher distributions, alongside net repayments on the credit facility.
- The October 2022 facility amendment extended maturity to 2027, raised the borrowing base to $550 million, reduced commitments to $375 million, and replaced LIBOR with SOFR.
Outlook, commentary, and risks
- Management provided no formal earnings or revenue guidance. The 2023 non-operated working-interest capital budget is approximately $6.9 million, net of farmout reimbursements, mainly for an Austin Chalk well and Shelby Trough workovers and recompletions. No material acquisition activity occurred in 2022.
- Management described commodity markets as uncertain. It cited elevated inflation, the Ukraine conflict, and changes in LNG export capacity and weather as factors affecting prices. Freeport LNG’s 2022 outage weighed on gas-market conditions; limited operations had resumed by February 2023.
- At year-end, the partnership had hedged 81% of available 2023 oil and condensate hedge volumes and 68% of available natural gas hedge volumes. These swaps reduce, but do not eliminate, commodity-price exposure.
- Concentration merits attention: three Shelby Trough operators generated 13% of 2022 royalty revenue and 35% of working-interest revenue, and only one had an active drilling program on the acreage. XTO accounted for 12% of total oil and gas revenue, down from 19% in 2021.
- Other principal risks include reliance on unaffiliated operators and their drilling decisions and financing; production declines; reserve-estimate uncertainty; price volatility; pipeline and disposal capacity; environmental, climate, and hydraulic-fracturing regulation; and restrictions on distributions under the credit facility.
- Common distributions are discretionary and subordinate to cumulative preferred distributions. Series B preferred units carry a 7% annual distribution rate, with a rate reset beginning November 2023; the preferred holders have distribution priority over common unitholders.
- Subsequent events: the board declared a $0.475-per-common-unit distribution for the fourth quarter of 2022, payable February 23, 2023. CFO Jeffrey Wood was scheduled to leave effective February 28, 2023; the partnership named Evan Kiefer interim CFO and said it did not expect a material operational impact.
- The auditor issued unqualified opinions on the financial statements and internal control over financial reporting. Critical audit matters included depletion calculations reliant on reserve estimates and the estimation of accrued customer-contract revenue.
Important facts for investors to verify
- Whether operator drilling and production—particularly in the Shelby Trough—sustain or replace declining volumes and support reserve growth.
- How realized oil and gas prices, derivative settlements, and hedge coverage affect cash generation and future distributions.
- The April 2023 borrowing-base redetermination, current facility availability, covenant headroom, and compliance with distribution restrictions.
- The collectability and eventual settlement of the $129.1 million accrued customer-contract receivable, which depends on estimates of production and prices.
- Whether the preferred-unit distribution reset or redemption rights affect cash available to common unitholders, and whether declared distributions are supported by distributable cash flow.
- Progress on 2023 capital spending, farmout well commitments, reserve development, and the CFO transition.