Gulfport Energy is an Ohio Utica and Oklahoma SCOOP producer whose wet gas liquids content, hedged revenue book, and shrinking share count together make it a cash generation machine in a rising crude price environment, with the open question being how much of the upside in a stronger gas complex the market should already be paying for.
The most important recent development is the Ohio state land lease acquisition, which added 4,700 net undeveloped acres in the highest return tier of the portfolio. Those acres sit adjacent to existing infrastructure and in a part of the Utica where Gulfport has demonstrated liquids rich drilling results, so the incremental capital required per location is low and the return on invested capital is high relative to the rest of the program. The deal is expected to add roughly 16 net wet gas locations, with operations commencing in 2027.
The tension runs through the hedge book and the balance sheet. The 2026 positions lock in a substantial portion of second half production at gas prices near 3.75 per MMBtu, which caps the benefit of any sharp rally in Henry Hub. At the same time, the balance sheet carries 650 million in 2029 senior notes, and the CFO resignation announced in late July leaves the capital allocation function without a permanent lead during a period when buyback pace and land spending decisions are both elevated.
The catalyst to watch is the second half liquids ramp from the newly completed wet gas Utica pads. That ramp should lift NGL and oil production and push realized prices higher before the 2027 hedge positions start to bind.
Gulfport Energy operates in two basins. The Utica and Marcellus in eastern Ohio is the core, with roughly 223,000 net reservoir acres concentrated in Belmont, Harrison, Jefferson, and Monroe counties. The SCOOP, or Southern Oklahoma Outpost, targets the Woodford and Springer formations in central Oklahoma. The Utica and Marcellus generated about 81 percent of total production in 2025, making Ohio the center of gravity for both capital allocation and cash flow.
The strategic posture has shifted from growth to capital return and inventory quality. The repurchase program has been running since 2022. The company has bought back roughly 8.6 million shares in aggregate, for a total outlay of about 1.2 billion. The weighted average price on those purchases was near 135 per share. The authorization still holds 336.8 million of remaining capacity. The company emerged from Chapter 11 in May 2021 with a restructured balance sheet, and the current strategy reflects a post bankruptcy discipline: buy back stock when it is cheap, acquire only the highest return land, and keep leverage at a level that survives a gas price drawdown.
The two basin structure matters for the thesis. The Utica is a wet gas play where liquids content drives a meaningful share of revenue, and the first Marcellus pads began contributing in 2025. The SCOOP is a smaller, lower decline gas play that provides a stable cash flow base and a hedge against Ohio basis risk, but it is not a growth asset. The company treats both as a single portfolio and allocates capital by return on invested capital rather than by basin quota, which has allowed it to concentrate in the highest return locations in the Utica while maintaining a modest SCOOP program.
The Ohio state land acquisition is the clearest expression of this strategy. The 4,700 net acres and 16 net locations sit in the same part of the Utica where Gulfport has already drilled its highest return wells, and the proximity to existing gathering and processing infrastructure means the incremental cost per location is well below the company average. A new 140 million dollar discretionary program extends the logic to private and corporate lands, with management targeting roughly 40 net high quality, low breakeven locations by year end. Together these investments are expected to lift total Utica inventory by more than 20 percent and extend the development runway by more than 2.5 years, a meaningful addition for a company that has been drilling out its best locations for several years.
Gulfport does not sell a differentiated product. The product is natural gas, crude oil, and NGL, and the pricing is set by the Henry Hub, WTI, and regional NGL benchmarks. The moat, to the extent one exists, is in the location and quality of the inventory, the operating efficiency that comes from a concentrated footprint, and the ability to extract more liquids per Mcfe than a typical Appalachian gas producer.
The wet gas character of the Ohio inventory is the real differentiator. The Utica in the counties Gulfport operates is liquids rich, and the company has demonstrated that longer laterals and improved completion techniques can lift oil and NGL recovery relative to offset wells. The latest Marcellus pad, brought online under disciplined choke management, is producing stronger oil recoveries than nearby wells, and management attributes this to the longer lateral lengths and lower drilling costs. This is not a technology moat in the traditional sense, but it is a repeatable operating advantage that shows up in lower breakevens and higher cash flow per well.
The infrastructure advantage is real but not exclusive. Gulfport has gathering and processing contracts that allow it to monetize NGL and oil at prices closer to the commodity benchmark than a producer without those contracts would receive. The basis swap positions in the hedge book, which lock in differentials at the Rex Zone 3, Tetco M2, and other delivery points, are a financial expression of this advantage, converting what would be a volatile basis exposure into a fixed, known cash flow. The company has also invested in its own processing capacity in parts of the portfolio, which gives it a cost and volume control that a pure leasehold operator would not have.
The competitive set for the moat argument is other Appalachian gas producers with wet gas positions. The distinction is that Gulfport has a smaller, more concentrated footprint in the highest return part of the Utica, and it has not diluted the base with lower return acreage. The share count has fallen from roughly 18.8 million at the start of the year to 17.7 million by mid year. The inventory quality per share has risen as a result. That is the practical moat: a shrinking share base applied to a portfolio where the marginal location is still high return.
The second quarter results show a company earning well on a rising crude price backdrop, with the gas complex running below the hedged levels. Net income was 87.1 million, down from 184.5 million a year earlier, but that comparison is distorted by derivative fair value gains that were much larger in the prior year quarter. Adjusted EBITDA was 179.1 million for the quarter, with the six month figure running higher still. The price mix is the defining feature of the second quarter. The average realized gas price without derivatives was 2.48 per Mcf, down from 2.97 a year earlier. The average realized oil price without derivatives was 85.86 per barrel, up sharply from 58.20. NGL prices rose sharply to 33.94 per barrel, and the net effect is a revenue mix that is now more liquids weighted than it was twelve months ago, exactly the profile that benefits most from a strong crude complex.
The derivative book was the largest swing factor in the quarter. It generated 50.2 million in total gains, primarily from natural gas settlement gains of 41.6 million as the forward gas curve sat above the hedged swap prices. The six month net derivative gain was 45.9 million, which flatters reported earnings but is largely a mark to market effect that reverses as positions settle. The cash impact of settled derivatives was a 20.9 million net payment outflow for the six months, reflecting the fact that the company locked in oil prices below where WTI actually traded.
Capital spending ran at a heavy clip in the first half. The six month incurred total was 350.1 million, of which 259.6 million was operated drilling and completion. The company updated full year base capital to about 430 million, including 35 million for maintenance land and seismic. Operating cash flow for the six months was 442.8 million, but adjusted free cash flow after capex and interest was a modest 6.4 million for the quarter, reflecting the heavy second half capex profile and the oil hedge payment outflows.
The balance sheet at mid year carried 930 million in total funded debt. The senior notes maturing in 2029 account for 650 million of that total. The coupon on those notes is 6.75 percent. Total liquidity was 772.4 million, almost entirely unused revolver capacity. The balance sheet also passed the full cost ceiling test without recording any impairment. On the reserve side, the year end proved base stood at 4,253 Bcfe. The present value of that reserve base was 3,622 million. Roughly 43 percent of that base was classified as PUDs.
Full year guidance points to production of 1.030 to 1.055 Bcfe per day. The mix is about 89 percent natural gas, with the remaining liquids running up to 21.0 MBbl per day. The guidance assumes commodity strips as of mid July and no property acquisitions or divestitures beyond the discretionary program already underway. On pricing, the gas differential is 0.15 to 0.30 per Mcf below the NYMEX settled price, and the oil differential runs well below the WTI benchmark.
The execution risk centers on the pace of the second half liquids ramp from the newly completed wet gas Utica pads. Management expects a meaningful increase in liquids production in the second half, and the WTI strip running well above the hedged oil book means that each incremental barrel of oil and NGL is highly accretive to cash flow. If the ramp is slower than planned, the second half cash flow benefit shrinks, and the buyback pace that has defined the stock over the past several quarters loses its funding source.
The discretionary acreage program adds a second layer of execution risk. The 140 million dollar target is a commitment to deploy capital in the second half, and the returns depend on finding the right locations at the right price. The Ohio state land deal set a high bar, and the private land transactions that follow need to clear a similar return threshold to justify the capital outlay. Slippage in the land program is a smaller risk than slippage in the liquids ramp, but it still matters for the 2027 inventory picture and for the pace at which the company can sustain high return capital deployment.
The CFO transition rounds out the execution risk. Michael Hodges, the CFO, resigned effective early August, with an advisory role running through September 1. The company has retained a search firm, but the gap between the departure and the appointment of a permanent successor is a period when capital allocation decisions, hedge book management, and buyback execution all run without a permanent owner. The risk is not that a temporary arrangement makes a bad decision, but that the pace of execution on the items that require a senior financial officer slows. The 2027 hedge book is modest. It holds 225 BBtupd of fixed price gas swaps at 3.89 per MMBtu, which leaves the next year cash flow exposed to the gas complex in a way that the current year is not, and the judgment calls about managing that exposure land squarely in the CFO seat.
The dominant risk is the gas price complex. The hedge book locks in a substantial portion of second half production at a fixed price of 3.73 to 3.77 per MMBtu. That level is above the current forward curve, but well below the price that would make the full capital program and buyback program look cheap in hindsight. If Henry Hub rallies sharply, the company captures only a fraction of the upside on the hedged volumes, and the derivative liability on the unhedged volumes provides only partial offset.
The oil hedge is a different kind of risk. The 2026 fixed price oil swaps are at 72.19 per barrel, and the WTI strip is running well above that level. The company is paying the difference in cash settlements, which is why the six month settled derivative cash flow was a net outflow. If WTI stays elevated, the cash outflow continues and reduces the free cash flow available for buybacks and land. The risk is not that the hedge is wrong in direction, but that the cash timing of the payments creates a drag on the balance sheet in the second half.
The PUD exposure is a structural risk that the full cost ceiling test only partially addresses. With 43 percent of proved reserves classified as PUDs, a sustained decline in gas prices or an increase in drilling costs could force a write down of those reserves and a reduction in the borrowing base. The 2029 senior notes come due in September of that year. Refinancing or repaying that debt is an event in the 2028 to 2029 window that the current cash flow profile is sized to handle, but only if the gas complex does not deteriorate further.
The balance sheet leverage is manageable but not trivial. Net debt of roughly 930 million against a trailing twelve month adjusted EBITDA puts the company at about 1.5 times leverage. That sits in the middle of the Appalachian gas producer range. The buyback program has been a significant use of cash, and the remaining 336.8 million of capacity is large relative to the current market capitalization. The risk is not solvency, but that the pace of buybacks in a period of elevated oil hedge payments and heavy land spending could push leverage higher than management intends if the commodity mix shifts against the company.
The valuation framework rests on three variables: the 2026 to 2028 cash flow profile, the share count trajectory, and the exit multiple applied to the mature production base. The share count is the most controllable of the three variables, and it is moving in the right direction. The company repurchased roughly 1.3 million shares in the first half of the year at an average price near 185.
The base case assumes the second half liquids ramp comes through as described, WTI stays in the high 80s, and the gas complex holds near the current forward levels. In that scenario, adjusted free cash flow after base capex is roughly 200 million for the year, the share count ends the year near 17.2 million, and the company enters the following year with a thinner hedge book and a larger inventory base. Applying a 4.5 times multiple to a normalized annual cash flow, on a net debt adjusted basis, gives a value in the mid 1.5 billion range on a per share basis.
The bear case assumes WTI retraces to the low 70s, the gas complex weakens, and the discretionary land program delivers returns below the company average. That is a scenario where the hedge book provides less protection than it appears to on the surface. In that scenario, cash flow is closer to 120 million and the buyback pace slows. The multiple compresses to 3.5 times on a weaker forward cash flow base. The value in that case is roughly 700 million, or about 40 per share.
The bull case assumes WTI holds above 90, the gas complex rallies on a supply constraint or demand surprise, and the liquids ramp outperflows expectations. The hedge book caps the direct benefit on hedged volumes, but the unhedged forward position and the incremental liquids production from the new pads provide meaningful upside that the bear case does not. The hedge book caps the direct benefit on hedged volumes, but the unhedged 2027 position and the incremental liquids production from the new pads provide meaningful upside. In that scenario, cash flow in the forward year could reach 450 million. A 5.5 times multiple on that base gives a value near 2.4 billion per share on a fully diluted basis. The current market price of 173 per share sits above the base case and below the bull case, which means the market is already pricing in a version of the liquids ramp and a stronger gas complex. The value creation from here depends on the share count continuing to fall and on the 2027 cash flow exceeding the base case, which requires the gas complex to perform better than the current forward curve implies.
The argument for Gulfport is not that it is cheap on a multiple basis, but that the combination of a shrinking share count, a high return inventory base, and a liquids rich production profile creates a cash flow per share that is growing faster than the headline production number suggests. The hedge book is a drag on the upside in a strong crude environment, but it is also the reason the company is able to buy back stock at a pace that a fully exposed producer could not sustain.
The counterargument is that the current price already reflects the second half liquids ramp and a reasonable gas complex. The current year hedge book caps the benefit of the most favorable commodity scenario, and the 650 million in 2029 notes plus the CFO vacancy are the kind of overhangs that keep the multiple from expanding to the level that a fully unhedged, fully staffed producer would command. None of those factors is a deal breaker on its own, but together they set a ceiling on what the market pays for the portfolio.
The judgment is that the risk reward is balanced slightly to the downside at the current price, because the market is paying for a gas story that the hedge book does not fully allow the company to capture in 2026. The 2027 position is where the real optionality sits, and the investor who is willing to hold through the 2026 hedge drag to reach that point is the one for whom the thesis is strongest. The share count decline provides a floor on the downside, but it does not remove the commodity price risk that is the core of the business.