Gulfport Energy (GPOR) Q3 2026 earnings review
Gulfport liquids output rebounds, but land deals lift its debt
Gulfport Energy, an oil and gas producer in Ohio and Oklahoma, reversed three quarters of falling liquids output as new wet-gas wells came online, but land purchases and buybacks pushed debt above $1 billion. Daily liquids volume jumped 67% from the second quarter, lifting free cash flow excluding one-offs to $89 million. Chief executive Nick Dell'Osso kept the full-year outlook unchanged, which by our math requires fourth-quarter gas and liquids output to climb another 4% to 9% while drilling spending drops.
| Commodity sales before derivatives | $323.9M +3.5% from a year ago |
|---|---|
| Daily liquids production | 23.5 MBbl/d +67% from last quarter |
| Free cash flow, excluding one-offs | $89.0M $6.4M last quarter |
| Full-year 2026 outlook | Unchanged middle of the range: 1.043 Bcfe/d |
⚖️ Verdict: ⚪ Neutral
The story is unchanged because operational gains in the field were offset by higher balance-sheet leverage. On the positive side, the Utica liquids rebound arrived on schedule and management locked in hedges for 63% of 2027 gas output, easing two major risks from last quarter. The caution is that closing $130 million of Ohio land deals alongside share buybacks added $140 million to the credit line in a single quarter.
The question now is whether shifting to a continuous two-rig drilling program in 2027 will crowd out debt paydown and share buybacks before production grows in 2028. Bulls see steady two-rig drilling lowering well costs and filling new Midwest power contracts; bears see higher 2027 capital spending eating into cash flow while credit line debt sits at $419 million. Management's formal 2027 budget in February will settle it.
🐂 Bull Case
New Utica Wells Reversed the Liquids Slide
Gulfport produces natural gas, crude oil and natural gas liquids (NGLs, such as propane and butane used in plastics and heating). Liquids fell for three straight quarters into the summer, which raised doubts about the full-year outlook. Chief executive Nick Dell'Osso said "our back-half-weighted turn-in-line schedule drove production up approximately 10% from the second quarter, led by new liquids-rich wet gas Utica pads".
- Daily liquids production: 23.5 thousand barrels per day, up 67% from last quarter and up 6.8% from a year ago
- Total daily production: 1,057 million cubic feet of gas equivalent per day, up 9.8% from last quarter
- Free cash flow excluding one-offs: $89.0 million, up from $6.4 million last quarter
- Lease operating expense: $0.21 per unit of gas equivalent, down from $0.23 last quarter
This rebound matters because liquids sell for much more than dry gas per unit of energy. In the third quarter, NGLs fetched $35.81 per barrel before hedges, up 28% from a year ago, while oil brought $79.59 per barrel. That richer product mix lifted total realized prices including hedges by 10% to $3.71 per unit and spread field operating costs over more volume.
What to watch: fourth-quarter liquids volume against the 19.2 to 25.1 thousand barrels per day implied by the full-year outlook. Landing near the middle of that band would prove the new Utica wells can sustain their early output rates.
Added 2027 Hedges Cut Commodity Price Exposure
Energy producers use derivative contracts — financial swaps and price collars — to lock in floor prices for future gas and oil output. Entering this quarter, Gulfport had hedged only 38% of its 2027 gas volume, leaving next year's cash flow exposed if gas prices fell.
During the third quarter, the Oklahoma City-based producer added 235 billion British thermal units per day of 2027 natural gas swaps. That brings total 2027 gas protection to 577 billion British thermal units per day, or 63% of third-quarter gas production by our math, at a blended floor price of $3.61 per unit. It also raised 2027 oil swaps to 3,756 barrels per day at $71.64.
Locking in more than 60% of next year's gas output removes a major cash flow risk, especially while the company considers running two drilling rigs in 2027. The trade-off is a slightly lower protected floor, down from $3.84 per unit last quarter because the new swaps were struck at $3.59.
What to watch: 2028 gas hedge additions in the fourth-quarter report, where only 90 billion British thermal units per day are locked in today. Adding 2028 swaps above $3.50 per unit would protect the cash flow needed for the planned 2028 production growth.
Midwest Power Deals Lock In Better Gas Prices
Appalachian gas producers usually sell their output at regional prices that trade at a discount to the national Henry Hub benchmark because local pipelines fill up. Gulfport wants to shrink that discount by selling directly to regional power plants and industrial buyers in Ohio and the US Midwest.
In the fourth quarter, the gas producer signed a firm sales agreement for 50,000 million British thermal units per day starting in 2028, "supporting growing Midwest demand". Combined with an earlier 10-year contract for 65,000 units per day starting in mid-2027, Gulfport has locked in about 10% of its projected net output "at a premium to historical realizations" using its existing pipeline capacity.
Using existing pipeline rights means the company captures higher regional power-linked prices without taking on new long-term pipeline fees. Because the first contract does not start until mid-2027, however, these agreements do not help 2026 cash flow.
What to watch: the 2027 natural gas price differential outlook when full-year 2027 plans arrive in February. A narrower discount than this year's $0.15 to $0.30 below benchmark would show the mid-2027 contract lifting realized prices.
🐻 Bear Case
Land Purchases and Buybacks Pushed Debt Over $1 Billion
Dell'Osso has made expanding Gulfport's Utica drilling inventory a priority while returning cash to investors, saying his plans will "balance reinvestment with returns to shareholders while preserving our strong balance sheet". Last quarter, those twin goals were both a growth driver for drilling locations and a balance-sheet concern because revolver borrowings funded the spending.
In the third quarter, the balance-sheet cost grew larger. Gulfport closed its $83.0 million Ohio state land lease, spent $46.9 million on discretionary land deals, and bought back $36.2 million of stock. Although the business generated $89.0 million of free cash flow excluding one-offs, cash outflows for land and buybacks exceeded that total by $77.1 million.
- Long-term debt: $1,061.8 million, up $139.5 million from last quarter and up $273.6 million since December
- Credit facility borrowings: $419.0 million, up from $280.0 million in June and $147.0 million in December
- Interest expense: $17.3 million ($0.18 per unit of output), up 27% from $13.6 million ($0.13 per unit) a year ago
- Remaining 2026 discretionary land budget: $52.9 million by our math to reach the $140 million target
The board expanded the buyback authorization by 33% to $2.0 billion, yet third-quarter repurchases slowed to $36.2 million from $70.0 million in the second quarter and $172.8 million in the first. Borrowing on the credit line to buy undeveloped land and shares has lifted interest costs by 5 cents per unit of gas over the past year.
What to watch: credit facility borrowings at year-end, after Gulfport finishes the remaining $52.9 million of its 2026 land program. A drop below $400 million would show fourth-quarter cash flow paying down the land tab rather than adding permanent debt.
Holding the 2026 Plan Leaves a Steep Fourth-Quarter Climb
Gulfport drilled most of its 2026 wells in the first half of the year, counting on second-half output to make up for a slow start. Dell'Osso said third-quarter momentum is "keeping us on track to deliver full-year production and capital expenditures in line with our guidance", and the company left every full-year target unchanged.
By our math, nine-month production of 1,005.8 million cubic feet per day means fourth-quarter output must jump to 1,102 million per day just to hit the bottom of the full-year range, or 1,151 million per day to reach the middle. At the same time, nine-month base capital spending of $382.0 million leaves only $48.0 million for the fourth quarter, down from $111.7 million in the third.
Pipeline and processing costs also ran hot. Transportation, gathering, processing and compression expense rose to $1.02 per unit in the third quarter from $0.94 a year ago, pushing nine-month costs to $1.00 — the top edge of the $0.95 to $1.00 full-year plan — as wetter gas required more processing.
What to watch: fourth-quarter daily production against the 1,102 million cubic feet per day needed for the bottom of the 2026 range. Any third-party pipeline or processing delay would push full-year volumes below the outlook.
Risks this quarter didn't answer
Three standing operational, governance and legal concerns received no resolution in the third-quarter earnings release.
- Oklahoma SCOOP asset plans: Gulfport spud, drilled, completed and turned in line zero SCOOP wells in the third quarter as the basin's output fell 17.3% from a year ago to 167.7 million cubic feet per day; management's February 2027 plan will show whether SCOOP gets capital or is sold.
- Finance chief vacancy: Former finance chief Michael Hodges departed on August 5, 2026, triggering a $2.8 million stock-award forfeiture credit in general and administrative tables, and the release named no replacement; a permanent hire announcement will settle the leadership transition.
- Ohio royalty lawsuit exposure: The release did not update the Ohio class action challenging whether processing fees ($99.3 million in the third quarter) can be deducted from landowner royalties; the quarterly Form 10-Q legal footnote will carry any status change.
👓 Other Themes
Evaluating a Two-Rig Plan for 2028 Growth
To fix the uneven pattern where output dips early each year, Dell'Osso said Gulfport is "evaluating a more continuous two-rig Appalachia development program" for 2027. Management believes running two rigs steadily will "drive meaningful operational efficiencies through steadier rig and crew utilization, lower our development costs, concentrate capital in our highest-return asset area and position the business for production growth beginning in 2028". Full 2027 plans arrive in February.
💲 Other KPIs
Direct sales of gas, oil and NGLs rose 3.5% from a year ago and 23.8% from last quarter as higher liquids volumes and prices offset lower gas output. Total reported revenue fell 4.5% from a year ago to $362.5 million only because paper gains on derivative hedges were $38.5 million against $66.8 million last year.
Operating profit was $140.8 million, or 38.8% of total revenue, down 3.0 percentage points from 41.9% a year ago. Smaller unrealized hedge gains reduced the revenue base, while midstream pipeline and processing fees rose 2.0 percentage points of revenue to 27.4% and depreciation rose 1.6 points to 23.5%.
Weighted-average diluted shares fell 3.3% from a year ago and 1.4% from last quarter as the producer bought back 218.7 thousand shares for $36.2 million ($165.52 per share by our math). Combined with last year's retirement of preferred stock, the lower share count turned a 13.5% drop in net income into a 22.5% rise in diluted profit per share to $5.45.
🔮 Guidance
Unchanged. The full-year plan still calls for roughly flat daily production against 2025's 1.040 billion cubic feet per day. By our math, nine-month output of 1.006 billion per day leaves 1.102 billion per day in the fourth quarter to reach the low end, or 1.151 billion per day (+4.9% from a year ago) for the middle of the range.
Unchanged. The target still points to 4.4% growth at the 19.5 thousand barrels per day middle of the range. After third-quarter liquids jumped to 23.5 thousand per day, nine-month liquids average 17.6 thousand per day. By our math, fourth-quarter liquids need 19.2 thousand per day for the low end or 25.1 thousand per day for the middle.
Unchanged. Natural gas made up 89.5% of nine-month output after dropping to 86.7% in the third quarter on new wet-gas wells. By our math, fourth-quarter gas share needs to run near 87.5% for the full year to finish at 89%.
Unchanged. Base capital spending includes ~$395 million for operated drilling and completion (held) and ~$35 million for maintenance land (held). With $382.0 million incurred through September ($363.0 million drilling and $19.0 million maintenance land), our math leaves just $48.0 million for the fourth quarter ($32.0 million drilling and $16.0 million land).
Unchanged. Dell'Osso reiterated plans to finish the $140 million targeted leasing program by year-end. Gulfport spent $46.9 million in the third quarter to reach $87.1 million for the year's program, leaving $52.9 million for the fourth quarter by our math.
Unchanged. Third-quarter midstream costs rose to $1.02 per unit on higher wet-gas processing, lifting the nine-month average to $1.00 per unit. By our math, hitting the $0.975 middle of the range would require fourth-quarter costs to drop to $0.91 per unit, so finishing near the $1.00 ceiling looks far more realistic.
Unchanged. Third-quarter field operating costs dropped to $0.21 per unit as production climbed, bringing the nine-month rate to $0.23 per unit. That sits right at the middle of the full-year range.
Unchanged. Production and property taxes ran $0.08 per unit in the third quarter and $0.09 per unit over the first nine months, tracking inside the full-year band.
Unchanged. Recurring cash overhead (which includes capitalized overhead costs and excludes executive transition charges) was $0.14 per unit in both the third quarter and the first nine months, sitting at the top edge of the target range.
Unchanged. All three pre-hedge price relationships were kept intact. Third-quarter NGL prices rose to $35.81 per barrel (45% of realized oil prices before hedges), recovering from a weak second quarter as winter heating demand approaches.
❓ Key Questions
What will the two-rig Appalachia plan cost in 2027?
Evaluating a continuous two-rig program for 2027 suggests higher drilling capital before production grows in 2028. Investors need to know how much 2027 base capital will rise above this year's $430 million.
Will credit line borrowings fall in the fourth quarter?
Credit facility debt climbed to $419 million in the third quarter while $52.9 million of planned 2026 land purchases remain. With fourth-quarter base drilling capital dropping to $48 million, how much debt will be paid down by December?
Is the Oklahoma SCOOP asset a sale candidate?
Gulfport did not drill or complete a single SCOOP well in the third quarter, and the basin's output fell 17% from a year ago. Concentrating two rigs in Appalachia raises the question of whether SCOOP will be sold to pay down debt.
Why hold the 1.0425 Bcfe/day production midpoint for 2026?
Reaching the middle of the full-year production range requires fourth-quarter output to average 1,151 million cubic feet per day, up 9% from the third quarter while drilling capital drops by more than half. Does management expect the low end or the middle?