Black Stone Minerals (BSM) Q3 2026 earnings review
Black Stone raises its payout, while annual output stays lower
Black Stone Minerals, an owner of oil and gas royalty rights, raised its cash payout again as high crude oil prices made up for flat annual production. Distributable cash flow climbed 18% from a year ago to $93 million because realized oil held near $87 a barrel, letting co-chief executives Taylor DeWalch and Fowler Carter lift the quarterly distribution 9% to $0.35 per unit at 1.25x coverage — well above what the company's own hedge book pointed to at lower oil prices. Daily output bounced 6% from last quarter as new East Texas and Permian wells started flowing, yet total volumes remain 2% below a year ago.
| Revenue from customers (excl. hedge marks) | $129.9M +23% from a year ago |
|---|---|
| Total daily production | 35.6 MBoe/d +6% from last quarter, -2% from a year ago |
| Distributable cash flow | $93.0M +18% from a year ago; 1.25x payout coverage |
| Shelby Trough drilling plans | Expanded Caturus area up 730k acres to 950k; Adamas Q4 adds 4 wells |
⚖️ Verdict: 🟢 Bullish
The story got better because the partnership kept its $87 oil windfall for a second quarter and quadrupled its Caturus Energy drilling agreement by 730,000 gross acres to 950,000. The cautions: proving that new land takes until 2028 to 2038, Adamas Energy left one well under evaluation, and credit facility debt has doubled from a year ago to $197 million as land buying continues.
The question now is whether East Texas gas drilling will grow total production before oil prices cool toward the $64 to $66 swap floor. One view is that contracted schedules from Adamas, Revenant and Caturus assure a multi-year volume climb; the other is that operator flexibility, contract revisions and natural well declines will keep total output flat while debt and overhead rise. Fourth-quarter well completions and 2027 production targets will tell.
🐂 Bull Case
High Oil Prices Funded a Second Payout Raise
Black Stone Minerals owns oil and natural gas mineral rights, collecting royalties from drillers without paying to drill the wells. While management pitches a multi-year natural gas expansion, crude oil is carrying results right now, "reflecting increased development activity and higher oil production and revenue," co-chief executive Taylor DeWalch said.
- Realized oil price: $86.95 per barrel, up 38.9% from a year ago and nearly unchanged from $87.08 last quarter
- Oil and condensate sales: $77.6 million, up 36.0% from a year ago and making up 63% of oil and gas revenue
- Lease bonus and other income (upfront payments from drillers to lease land): $7.2 million, up 43.4% from a year ago
- Distributable cash flow (cash available to pay unitholders): $93.0 million, up 18.4% from a year ago
Because realized oil stayed near $87 per barrel, the Houston partnership lost only $0.4 million on cash derivative settlements and beat the 0.99x to 1.07x distribution coverage ratio (distributable cash flow divided by total payouts) that our math pointed to at $65 to $75 oil. That cash surge let the board raise the quarterly payout 9% to $0.35 per unit while keeping coverage at 1.25x. The firm also locked in more protection for 2027, raising its oil price swaps to 570,000 barrels per quarter at $65.55.
What to watch: fourth-quarter realized oil prices against the $64.39 per barrel swap price covering 615,000 barrels. A drop toward that hedged floor would test whether the higher $0.35 payout holds above 1.1x coverage without another oil windfall.
Shelby Trough Contracts Quadrupled Caturus Acreage
The partnership's growth strategy rests on signing structured drilling contracts in the Shelby Trough, a natural gas basin in East Texas. Co-chief executive Fowler Carter said this inventory "positions Black Stone well as the industry prepares to meet anticipated growth in natural gas demand" from power plants and liquefied natural gas (LNG) export terminals.
In October 2026, the mineral owner expanded its agreement with driller Caturus Energy by 730,000 gross acres to 950,000 gross acres across two new Texas areas. Meanwhile, current drilling lifted mineral and royalty production 6.2% from last quarter to 34.5 thousand barrels of oil equivalent per day (MBoe/d, a measure combining oil and gas volume), as partner Adamas Energy turned 7 gross (0.7 net, meaning Black Stone's fractional royalty share) wells to sales and Blue Arrow Operating brought 7 gross (0.6 net) Permian wells online.
What to watch: first-half 2027 initial gas production from the first 2 development wells that Caturus began drilling in October 2026. Strong early flow rates would prove that the westward expansion of the Shelby Trough can add volume before the new contract areas start pilot drilling in 2028.
🐻 Bear Case
Operator Delays and Contract Tweaks Slow the Gas Ramp
DeWalch said higher oil cash flow supports the partnership "as our natural gas development programs continue to ramp". Yet total daily production of 35.6 MBoe/d remains 1.9% lower than a year ago, and natural gas output of 14,301 million cubic feet (MMcf) is still down 1.8% from last year despite rebounding 8.9% from a weak second quarter.
- Adamas second-half 2026 well turn-in-lines: 3 gross wells in Q3 (after 4 in July) plus 4 expected in Q4, totaling 7 for the back half vs 8 planned last quarter, "with the remaining well under further evaluation"
- Revenant Energy contract amendment: added 7,000 gross lateral feet (horizontal well length) to 2027, but delayed the requirement to drill in a second area until 2029
- Caturus expansion timeline: pilot wells in the two new areas are not due until early 2028 and late 2031, ramping to 12 gross wells a year by 2034 and 2038
Moreover, the expanded Caturus contract gives the driller "flexibility to satisfy a portion of its annual development commitments for each development area through drilling in the other development areas". Because third-party operators control the rigs and keep winning timeline extensions or cross-area flexibility, contracted acreage keeps growing while actual year-over-year production stands still.
What to watch: whether Adamas turns all 4 expected gross wells to sales in the fourth quarter and finishes the 2 remaining Revenant wells on time. Any further slip into 2027 would leave full-year 2026 royalty production flat or down.
Debt Doubled While Land Buying Continued After Quarter End
Black Stone has spent $335.5 million buying mostly undeveloped mineral rights since September 2023 to feed its East Texas drilling partnerships. It bought $14.6 million of minerals during the third quarter and then accelerated spending in October 2026, paying $30.6 million in cash, $2.1 million in common units, and "additional consideration tied to future production" for Shelby Trough minerals and surface rights.
Because the firm is raising unitholder payouts at the same time it buys non-producing land, credit facility debt reached $195.0 million at quarter end — more than double the $95.0 million owed a year ago — and stood at $197.0 million on October 30. That higher balance pushed quarterly cash interest expense up 71.1% from a year ago to $3.7 million, alongside $7.4 million in quarterly payouts on its 9.8% Series B preferred units.
What to watch: credit facility borrowings at year-end after the November distribution and October cash purchases settle. A debt figure climbing past $210 million would show that acquisition spending is outrunning the cash left over after payouts.
Higher Overhead and Seismic Bills Cut Into Revenue
Even though royalty owners do not pay drilling bills, Black Stone's internal operating costs are rising faster than its customer revenue. General and administrative overhead (staff pay and office costs) climbed 34.0% from a year ago to $16.5 million, expanding by 1.0 percentage point to 12.7% of customer revenue, or $5.03 per barrel of oil equivalent vs $3.68 a year ago.
At the same time, exploration expense more than doubled from a year ago to $4.7 million, rising 1.6 percentage points to 3.6% of customer revenue. Nearly all of that was $4.4 million for 3D seismic data (underground mapping used to pitch acreage to drillers), which management adds back when calculating Adjusted EBITDA and distributable cash flow; by our math, counting that cash spend as a normal cost would trim third-quarter distribution coverage from 1.25x to 1.19x.
What to watch: fourth-quarter seismic data spending against the original $28 million to $32 million full-year exploration plan. With $14.2 million spent through nine months, either fourth-quarter mapping bills will jump or the partnership has slowed its survey work.
Risks this quarter didn't answer
Two standing operational and outlook questions received no update in the third-quarter earnings release.
- Full-year 2026 production and cost outlook: absent from the release for a second consecutive quarter after being issued in Q4 2025 and affirmed in Q1 2026; the conference call or 10-Q filing will show if the 33.0 to 36.0 MBoe/d target still stands.
- Western Haynesville and Shelby Trough pipeline capacity: no update on third-party midstream buildout needed to carry incremental gas from the expanded 950,000-acre Caturus footprint; commentary on the call would clarify whether pipeline bottlenecks explain the multi-year pilot timelines.
💲 Other KPIs
Customer revenue — oil and gas sales plus lease bonuses, before derivative contract swings — grew 23.5% from a year ago and 6.4% from last quarter, accelerating from 14.4% annual growth in the second quarter. Reported total revenue fell 24.7% to $99.7 million only because rising forward commodity prices created a $29.8 million non-cash accounting loss on future price swaps.
Production and property taxes fell 13.1% from a year ago (down 3.1 percentage points of customer revenue to 7.3%), but jumped 55.6% from $6.1 million last quarter. On a unit basis, taxes rose from $2.00 per Boe in the second quarter back to $2.90 per Boe as one-time second-quarter tax refunds did not repeat, trimming sequential cash flow.
The diluted unit count crept up 0.4% from 211.9 million a year ago and was nearly unchanged from 212.6 million last quarter. Black Stone has not bought back units under its repurchase program, instead issuing small amounts of equity — including $2.1 million of common units in October 2026 — to help pay for East Texas mineral acquisitions.
🔮 Guidance
Cut on second-half turn-in-lines; unchanged on current-year drilling. After turning 4 gross wells to sales in July and 3 more during the rest of the third quarter, Adamas expects 4 gross (0.4 net) wells to come online in the fourth quarter, leaving 1 of the 14 prior-year wells under evaluation. That puts second-half completions at 7 gross wells instead of 8. Adamas has spud 6 of the 17 wells planned through June 2027.
Raised for 2027 lateral footage; held at 4 wells for 2026 after a May 2026 cut from 6 wells. Revenant drilled 2 wells by quarter-end that should start selling gas by year-end, and began drilling the remaining 2 wells in early October for mid-2027 production. A September amendment added 7,000 gross lateral feet to the 2027 requirement while postponing second-area drilling obligations until 2029.
Raised in long-term scope. Under the original deal, Caturus drilled its Cherokee County pilot in the third quarter and started 2 development wells in October for first-half 2027 production. The October 2026 expansion adds two contract areas where minimum net lateral feet ramp from 8,000 to 33,600 per year (~12 gross wells each) by 2034 and 2038, if Caturus proceeds after pilot wells due by early 2028 and late 2031.
Unchanged. Out of the 25 gross (1.9 net) well program in the southern Delaware Basin, 10 gross (0.9 net) wells were producing as of September 30 — meaning 7 gross (0.6 net) came online in the third quarter after 3 in the second quarter. The remaining 15 gross (1.0 net) wells remain on schedule for the fourth quarter of 2026 and first half of 2027.
❓ Key Questions
Does the 2026 production plan still hold?
Management has not printed its 33.0 to 36.0 MBoe/d full-year production target since the first quarter. By our math, the 34.5 MBoe/d middle of that range leaves fourth-quarter output falling to 31.9 MBoe/d. Is that full-year range still active?
Why is the fourteenth Adamas well under evaluation?
Adamas drilled 14 wells in the program year ended June 30, 2026, with 9 online and 4 due in the fourth quarter, leaving 1 well under evaluation. Did that well hit mechanical trouble or poor rock quality, and does it count toward minimum commitments?
How could Caturus cross-area drilling credits lower net royalties?
The expanded Caturus agreement lets the operator satisfy part of each area's annual drilling commitment by drilling in the other areas. Since Black Stone's royalty share varies by tract, how much could cross-area substitution reduce net royalty volume?
What are the terms of the October production earn-out?
Black Stone paid $30.6 million in cash and $2.1 million in units in October for Shelby Trough acreage, plus extra payments tied to future production. What is the maximum dollar payout and what production thresholds trigger it?