Gulfport Energy Corp.: Q4 FY2025 earnings call

What management said about Q4 FY2025, from the documents filed with the SEC on 24 February 2026: press release. Guidance figures: 1 raised, 17 new, 1 kept. The quarter’s numbers.

Key takeaways

Fourth quarter production rose 4%: Net production was 1.10 Bcfe per day in the fourth quarter of 2025, up 4% on fourth quarter 2024. Net liquids were 18.2 MBbl per day, up 12% year over year. Source
Fourth quarter earnings and EBITDA: The company reported net income of $132.4 million and adjusted EBITDA of $234.8 million for the quarter. Adjusted EBITDA is a non-GAAP measure. Source
First U-development in Utica completed: The company completed its first U-development in the Utica, unlocking 20 gross high-return dry gas locations. $37.5 million was allocated to discretionary appraisal projects in 2025. Source
Operating cash flow and adjusted FCF: Fourth quarter net cash from operations was $185.4 million and adjusted free cash flow was $120.2 million. Full year figures were $803.2 million and $324.7 million. Source
Full year buybacks include preferred redemption: Full year repurchases were about 1.8 million shares for $336.3 million. This included the redemption of all preferred stock for $31.3 million. Source

“The 2026 development plan centers on both dry gas and wet gas activity, our highest-return areas in the current commodity environment and positions the Company for enhanced adjusted free cash flow generation at recent strip pricing.”
John Reinhart, President and CEO

Guidance

Area	Period	Figure	Against last quarter
Discretionary acreage acquisition program Source	by end of first quarter 2026	approximately $100 million	Raised from $75 million - $100 million
Common stock repurchases Source	first quarter 2026	more than $140 million	New
Leverage Source	2026	approximately 1.0x or below	Kept
Fourth quarter net daily equivalent production Source	fourth quarter 2026 compared with fourth quarter 2025	approximately 5% growth	New
Net daily liquids production Source	full year 2026	18.0 to 21.0 MBbl per day, about 5% above full year 2025	New
Net daily equivalent production Source	full year 2026	1.030 to 1.055 Bcfe per day	New
Natural gas share of production Source	full year 2026	about 89%	New
Total capital expenditures Source	full year 2026	$400 million to $430 million	New
Maintenance land and seismic capital Source	full year 2026	$35 million to $40 million	New
Operated drilling and completion capital Source	full year 2026	$365 million to $390 million	New
Workover capital Source	full year 2026	approximately $15 million	New
Northern Marcellus activity Source	2026	incremental $10 million	New
Natural gas realization differential Source	full year 2026, before hedges	$(0.15) to $(0.30) per Mcf to NYMEX settled price	New
NGL realization Source	full year 2026, before hedges	40% to 50% of WTI	New
Oil realization differential Source	full year 2026, before hedges	$(6.00) to $(7.00) per Bbl to NYMEX WTI	New
Lease operating expense Source	full year 2026	$0.21 to $0.25 per Mcfe	New
Taxes other than income Source	full year 2026	$0.07 to $0.09 per Mcfe	New
Transportation, gathering, processing and compression Source	full year 2026	$0.95 to $1.00 per Mcfe	New
Recurring cash general and administrative Source	full year 2026	$0.12 to $0.14 per Mcfe	New

What changed from last quarter

New guidance: Full year 2026 operational and financial guidance appears in this release. The prior release gave no 2026 figures. Source
Guidance raised: The discretionary acquisition program was expanded. It is now about $100 million by end of first quarter 2026, against the prior $75 million to $100 million. Source
New guidance: A first quarter 2026 share repurchase plan of more than $140 million was added. Source
New: The common stock repurchase authorization was raised by 50% to a total of $1.5 billion. Source
New: A Marcellus North activity program was started to evaluate phase window and production mix. Source
Guidance kept: The leverage target of approximately 1.0x or below is kept, worded as at or below one times in the prior release. Source
New: The first U-development in the Utica was completed, unlocking 20 gross Utica dry gas locations. Source

Fourth quarter and full year results

Fourth quarter production rose 4%: Net production was 1.10 Bcfe per day in the fourth quarter of 2025, up 4% on fourth quarter 2024. Net liquids were 18.2 MBbl per day, up 12% year over year. Source
Full year production held flat: Full year 2025 net production averaged 1.04 Bcfe per day, in line with 2024. Net liquids rose about 29% to 18.7 MBbl per day. Source
Fourth quarter earnings and EBITDA: The company reported net income of $132.4 million and adjusted EBITDA of $234.8 million for the quarter. Adjusted EBITDA is a non-GAAP measure. Source
Full year earnings and EBITDA: Full year net income was $427.8 million and adjusted EBITDA was $878.5 million, for the twelve months ended December 31, 2025. Source

Production and product mix

Gas about 89% of 2025 output: Full year net daily production was roughly 89% natural gas, 7% natural gas liquids and 4% oil and condensate. Source
Utica and Marcellus carry most volume: Full year 2025 production was 841.5 MMcfe per day from the Utica and Marcellus and 197.4 MMcfe per day from the SCOOP. Source
Fourth quarter gas and liquids output: Fourth quarter natural gas averaged 988,107 Mcf per day, against 958,075 a year earlier. Oil and condensate was 4,752 Bbl per day, down from 5,229, and NGL rose to 13,467 Bbl per day. Source

“These additions unlock substantial value across our core assets, improving our gross inventory by more than 40% since 2022 and bringing our total net inventory to roughly 15 years with break-evens below $2.50 per MMBtu.”
John Reinhart, President and CEO

Prices and unit costs

Fourth quarter gas price rose: Natural gas averaged $3.27 per Mcf before derivatives and $3.36 with settled derivatives in the fourth quarter, against $2.51 and $2.99 a year earlier. Source
Total realized price per Mcfe: Total realized price was $3.52 per Mcfe before derivatives and $3.65 with settled derivatives in the fourth quarter. Full year figures were $3.49 and $3.64. Source
Oil and NGL prices lower: Fourth quarter oil averaged $53.61 per barrel before derivatives, against $65.05 a year earlier. NGL averaged $28.38, against $31.59. Source
Lease operating cost rose: Lease operating expense was $0.25 per Mcfe in the fourth quarter, against $0.20 a year earlier. Full year was $0.22, against $0.18. Source
Gathering and transport cost steady: Transportation, gathering, processing and compression cost $0.92 per Mcfe in the fourth quarter, against $0.91. Recurring cash G&A was $0.12 per Mcfe. Source

Capital investment and drilling

Fourth quarter base capital $36.4M: Fourth quarter base capital spending was $36.4 million: $25.0 million on operated drilling and completion and $11.4 million on maintenance land and leasehold. Source
Discretionary spend in fourth quarter: Fourth quarter discretionary appraisal and development capital totaled $55.7 million, on top of the base program. Source
Full year base capital of $389.1 million: Full year 2025 base capital was $389.1 million, including $354.3 million of operated drilling and completion. The third quarter update had planned about $390 million. Source
First U-development in Utica completed: The company completed its first U-development in the Utica, unlocking 20 gross high-return dry gas locations. $37.5 million was allocated to discretionary appraisal projects in 2025. Source
Operated Utica drilling activity: Operated Utica activity in 2025 included 24 wells spud, 27 drilled, 32 completed and 30 turned to sales. SCOOP had 2 wells completed and turned to sales. Source

“After accounting for adjusted free cash flow utilized for discretionary acreage acquisitions, the Company returned more than 100% of our adjusted free cash flow to shareholders through common stock repurchases during 2025”
John Reinhart, President and CEO

Acreage, inventory and reserves

Acreage acquisitions of $62.9 million: Opportunistic discretionary acreage acquisitions totaled $62.9 million in 2025, with $47.2 million completed in the fourth quarter. Source
Marcellus inventory over four years: Marcellus inventory grew through delineation and development to more than four years at the current development pace. Source
Proved reserves up about 7%: Year-end 2025 proved reserves were 4.3 Tcfe, about 7% above 2024, with 57% proved developed. Proved undeveloped reserves totaled about 1,848 Bcfe. Source
Extensions added 701 Bcfe: Proved reserves moved from 3,969 Bcfe to 4,253 Bcfe. Extensions and discoveries added 701 Bcfe, offset by 379 Bcfe of current production and a 38 Bcfe revision. Source
PV-10 of proved reserves: PV-10 was $3,622 million at year-end 2025, using average WTI of $66.01 per barrel and Henry Hub of $3.39 per MMBtu. Standardized measure was $3,403 million. Source

Cash flow, buybacks and balance sheet

Operating cash flow and adjusted FCF: Fourth quarter net cash from operations was $185.4 million and adjusted free cash flow was $120.2 million. Full year figures were $803.2 million and $324.7 million. Source
Fourth quarter buybacks of $135.0 million: The company repurchased about 664.7 thousand shares of common stock in the fourth quarter for about $135.0 million. Source
Full year buybacks include preferred redemption: Full year repurchases were about 1.8 million shares for $336.3 million. This included the redemption of all preferred stock for $31.3 million. Source
Authorization raised to $1.5 billion: The repurchase authorization was raised by 50% to $1.5 billion, with about $579.6 million remaining at December 31, 2025. Source
Year-end liquidity of $806.1 million: Liquidity comprised $1.8 million of cash and about $804.3 million of revolver availability. The revolver had $147.0 million drawn, and $650.0 million of 2029 senior notes were outstanding. Source

Coming up, as management said on 24 February 2026

First quarter 2026 buybacks above $140M: The company plans to repurchase more than $140 million of common stock in the first quarter of 2026. Source
Active repurchases through 2026: Management expects an active repurchase program throughout 2026, funded from adjusted free cash flow and revolver capacity. Source
Marcellus North evaluation under way: Northern Marcellus activity is aimed at evaluating phase window and production mix to support development planning in Jefferson and Belmont Counties. Source

Figures management reported

Figure	Reported
Production volumes Source	1.04 Bcfe per day (full year 2025); 1.10 Bcfe per day (fourth quarter 2025)
Realized prices Source	Natural gas $3.36 per Mcf including settled derivatives (fourth quarter 2025)
Reserves Source	4.3 Tcfe total proved reserves at year-end 2025
Capital expenditure Source	$389.1 million base capital (2025); $400 million to $430 million planned (2026)
Unit costs Source	Lease operating expense $0.25 per Mcfe (fourth quarter 2025)
Shareholder returns Source	$336.3 million of repurchases, about 1.8 million shares (full year 2025)

Risks management discussed

Operational: Known production downtime and Winter Storm Fern are included in the 2026 production range. Source
External: Commodity price exposure is partly addressed with derivative contracts on expected production volumes. Source

Earlier plans management reported on

Not stated: The program is described as previously announced and expanded, with about $100 million targeted by end of first quarter 2026. Source
Met: The release states the first U-development in the Utica was completed, unlocking 20 gross Utica dry gas locations. Source
Not stated: Discretionary development activity of $36.7 million was reported, anticipated to mitigate known production impacts in early 2026. Source
Not stated: Full year 2025 repurchases were reported at $336.3 million, including preferred stock on an as-converted basis. Source
Not stated: Year-end 2025 leverage is described as below 1.0x while repurchases continued. Source

Other quarters

Summarised with AI from the documents the company filed with the SEC. Every point is checked against the filing before it is shown: management’s own words word for word, figures against the line or table row they come from. A point that fails the check is left out. Source opens the filing at that line.

As filed with the SEC

Open the filing on EDGAR

Gulfport Energy Reports Fourth Quarter and Full Year 2025 Financial and Operating Results and Provides 2026 Operational and Financial Guidance

OKLAHOMA CITY (February 24, 2026) Gulfport Energy Corporation (NYSE: GPOR) (“Gulfport” or the “Company”) today reported financial and operating results for the three and twelve months ended December 31, 2025 and provided its 2026 outlook.

Full Year 2026 Outlook

Adjusted free cash flow expected to grow meaningfully, driven by disciplined, return-focused capital allocation that prioritizes highest-return development opportunities
Continue accretive discretionary acreage acquisitions, with previously announced program investment achieving approximately $100 million by the end of first quarter 2026, including $62.9 million deployed at year-end 2025
Enhance shareholder returns through common stock repurchases, supported by adjusted free cash flow and revolver capacity while maintaining leverage at approximately 1.0x or below
Forecast fourth quarter 2026 net daily equivalent production to grow approximately 5% compared to fourth quarter 2025
Estimate net daily liquids production to increase approximately 5%compared to full year 2025, with a range of 18.0 to 21.0 MBbl per day
Expect full year net daily equivalent production in the range of 1.030 to 1.055 Bcfe per day, including impacts from known production downtime and Winter Storm Fern
Plan total capital expenditures of $400 million to $430 million, including $35 million to $40 million on maintenance land and seismic investments

“As we enter 2026, we remained focused on prioritizing our most attractive opportunities and allocating capital designed to maximize value across our asset portfolio. The 2026 development plan centers on both dry gas and wet gas activity, our highest-return areas in the current commodity environment and positions the Company for enhanced adjusted free cash flow generation at recent strip pricing. Our announced guidance also includes approximately $15 million of workover capital targeting base production improvements across both basins, as well as an incremental $10 million in the Marcellus to initiate activity in the northern portion of the play. This Marcellus North activity is aimed at evaluating phase window and production mix, which will support future development planning across our substantial inventory position in Jefferson and Belmont Counties. We continue to believe the most attractive uses of our available adjusted free cash flow are discretionary acreage acquisitions and the repurchase of our common stock. The expanded previously announced program is expected to add more than two years of additional inventory upon completion in the first quarter of 2026. Supported by our strong balance sheet and liquidity position, we expect to maintain an active repurchase program throughout 2026, utilizing adjusted free cash flow and available capacity on our revolving credit facility while maintaining leverage at approximately 1.0x or below. With this framework in place, we plan to repurchase more than $140 million of our outstanding common stock during the first quarter of 2026,” commented John Reinhart, President and CEO.

Fourth Quarter 2025

Delivered total net production of 1.10 Bcfe per day, an increase of 4% over fourth quarter 2024
Produced total net liquids production of 18.2 MBbl per day, an increase of 12% over fourth quarter 2024
Incurred base capital expenditures of $36.4 million, which includes $25.0 million of base operated D&C capital expenditures and $11.4 million of maintenance land and leasehold spending
Invested incremental $55.7 million on discretionary appraisal and development capital expenditures
Reported $132.4 million of net income and $234.8 million of adjusted EBITDA
Generated $185.4 million of net cash provided by operating activities and $120.2 million of adjusted free cash flow
Completed opportunistic discretionary acreage acquisitions totaling $47.2 million
Repurchased approximately 664.7 thousand shares of common stock for approximately $135.0 million

Full Year 2025 Highlights

Delivered total net production of 1.04 Bcfe per day, in line with full year 2024
Produced total net liquids production of 18.7 MBbl per day, an increase of approximately 29% over full year 2024
Incurred base capital expenditures of $389.1 million, which includes $354.3 million of base operated D&C capital expenditures and $34.8 million of maintenance land and leasehold spending
Allocated $37.5 million toward discretionary appraisal projects, including the successful development of the Company’s first U-development in the Utica
Invested $36.7 million toward discretionary development activity that is anticipated to mitigate known production impacts in early 2026
Reported $427.8 million of net income and $878.5 million of adjusted EBITDA
Generated $803.2 million of net cash provided by operating activities and $324.7 million of adjusted free cash flow
Maintained a strong balance sheet and low financial leverage, with liquidity at December 31, 2025 totaling $806.1 million
Expanded common stock repurchase authorization by 50% to a total of $1.5 billion, with approximately $579.6 million remaining at December 31, 2025
Repurchased approximately 1.8 million shares of common stock (including preferred stock on an as-converted basis) for approximately $336.3 million, including the optional redemption of all the Company’s outstanding preferred stock for approximately $31.3 million
Completed opportunistic discretionary acreage acquisitions totaling $62.9 million
Expanded undeveloped Marcellus inventory through delineation and development, capturing significant value and growing Marcellus inventory to more than four years at current development pace
Completed successful U-development in the Utica, unlocking 20 gross high-return Utica dry gas locations

Reinhart continued, “Gulfport delivered another year of strong operational and financial performance in 2025, while strategically expanding our high-quality resource base and remaining consistent in our commitment to returning capital to shareholders. The continued expansion of our inventory is driven by our targeted discretionary acreage acquisitions and further bolstered by our development efforts in the Marcellus and the successful execution of U-development on our Utica position. These additions unlock substantial value across our core assets, improving our gross inventory by more than 40% since 2022 and bringing our total net inventory to roughly 15 years with break-evens below $2.50 per MMBtu. After accounting for adjusted free cash flow utilized for discretionary acreage acquisitions, the Company returned more than 100% of our adjusted free cash flow to shareholders through common stock repurchases during 2025, all while maintaining a solid financial position with leverage below 1.0x at year-end.”

A company presentation to accompany the Gulfport earnings conference call can be accessed by clicking here.

Assumes midpoint of 2026 guidance.
A non-GAAP financial measure. Reconciliations of these non-GAAP measures and other disclosures are provided with the supplemental financial tables available on our website at www.gulfportenergy.com.

Operational Update

The table below summarizes Gulfport’s operated drilling and completion activity for the full year of 2025:

	Year Ended December 31, 2025
	Gross	Net	Lateral Length
Spud
Utica	24	23.9	13,400
SCOOP	-	-	-
Drilled
Utica	27	26.9	13,700
SCOOP	2	1.8	11,500
Completed
Utica	32	31.9	13,600
SCOOP	2	1.8	11,500
Turned-to-Sales
Utica	30	30.0	13,800
SCOOP	2	1.8	11,500

Gulfport’s net daily production for the full year of 2025 averaged 1.04 Bcfe per day, primarily consisting of 841.5 MMcfe per day in the Utica and Marcellus and 197.4 MMcfe per day in the SCOOP. For the full year of 2025, Gulfport’s net daily production mix was comprised of approximately 89% natural gas, 7% natural gas liquids (“NGL”) and 4% oil and condensate.

	Three Months Ended December 31, 2025	Three Months Ended December 31, 2024	Year Ended December 31, 2025	Year Ended December 31, 2024
Production
Natural gas (Mcf/day)	988,107	958,075	926,837	967,633
Oil and condensate (Bbl/day)	4,752	5,229	6,193	3,986
NGL (Bbl/day)	13,467	11,004	12,477	10,431
Total (Mcfe/day)	1,097,422	1,055,472	1,038,854	1,054,136
Average Prices
Natural gas:
Average price without the impact of derivatives ($/Mcf)	$3.27	$2.51	$3.12	$2.02
Impact from settled derivatives ($/Mcf)	$0.09	$0.48	$0.14	$0.80
Average price, including settled derivatives ($/Mcf)	$3.36	$2.99	$3.26	$2.82
Oil and condensate:
Average price without the impact of derivatives ($/Bbl)	$53.61	$65.05	$59.12	$69.64
Impact from settled derivatives ($/Bbl)	$8.93	$0.70	$4.04	$0.11
Average price, including settled derivatives ($/Bbl)	$62.54	$65.75	$63.16	$69.75
NGL:
Average price without the impact of derivatives ($/Bbl)	$28.38	$31.59	$29.30	$29.56
Impact from settled derivatives ($/Bbl)	$0.81	$(0.61)	$(0.07)	$(0.56)
Average price, including settled derivatives ($/Bbl)	$29.19	$30.98	$29.23	$29.00
Total:
Average price without the impact of derivatives ($/Mcfe)	$3.52	$2.93	$3.49	$2.41
Impact from settled derivatives ($/Mcfe)	$0.13	$0.43	$0.15	$0.73
Average price, including settled derivatives ($/Mcfe)	$3.65	$3.36	$3.64	$3.14
Selected operating metrics
Lease operating expenses ($/Mcfe)	$0.25	$0.20	$0.22	$0.18
Taxes other than income ($/Mcfe)	$0.08	$0.08	$0.08	$0.08
Transportation, gathering, processing and compression expense ($/Mcfe)	$0.92	$0.91	$0.95	$0.91
Recurring cash general and administrative expenses ($/Mcfe) (non-GAAP)	$0.12	$0.15	$0.13	$0.13
Interest expenses ($/Mcfe)	$0.13	$0.14	$0.14	$0.16

Capital Investment

Capital investment was $463.2 million (on an incurred basis) for the full year of 2025, of which $428.4 million related to drilling and completion (“D&C”) activity and $34.8 million related to maintenance leasehold and land investment. This includes $37.5 million on discretionary appraisal projects, including capital directed toward DUC activity and recomplete opportunities on historical Utica development and the Company’s first U-development in the Utica, and approximately $36.7 million on discretionary development activity.

Gulfport also invested approximately $62.9 million in discretionary acreage acquisitions and incurred approximately $4.1 million related to non-operated drilling and completion activities.

Stock Repurchase Program

Gulfport repurchased approximately 664.7 thousand shares of common stock during the fourth quarter for approximately $135.0 million. As of December 31, 2025, the Company had repurchased approximately 7.4 million shares of common stock (including the underlying shares of common stock into which the preferred stock was convertible) at a weighted average price of $125.19 per share since the program initiated in March 2022, totaling approximately $920.4 million in aggregate. As of December 31, 2025, the Company currently has approximately $579.6 million of remaining capacity under the share repurchase program.

Financial Position and Liquidity

As of December 31, 2025, Gulfport had approximately $1.8 million of cash and cash equivalents, $147.0 million of borrowings under its revolving credit facility, $48.7 million of letters of credit outstanding and $650.0 million of outstanding 2029 senior notes.

Gulfport’s liquidity at December 31, 2025, totaled approximately $806.1 million, comprised of the $1.8 million of cash and cash equivalents and approximately $804.3 million of available borrowing capacity under its revolving credit facility.

2026 Guidance

Gulfport released operational guidance and outlook for the full year 2026, including full year expense estimates and projections for production and capital expenditures. Gulfport’s 2026 guidance assumes commodity strip prices as of February 2, 2026, adjusted for applicable commodity and location differentials, and no property acquisitions or divestitures.

	Year Ending
	December 31, 2026
	Low	High
Production
Average daily gas equivalent (Bcfe/day)	1.030	1.055
Average daily liquids production (MBbl/day)	18.0	21.0
% Gas	~89%
Realizations (before hedges)
Natural gas (differential to NYMEX settled price) ($/Mcf)	$(0.15)	$(0.30)
NGL (% of WTI)	40%	50%
Oil (differential to NYMEX WTI) ($/Bbl)	$(6.00)	$(7.00)
Expenses
Lease operating expense ($/Mcfe)	$0.21	$0.25
Taxes other than income ($/Mcfe)	$0.07	$0.09
Transportation, gathering, processing and compression ($/Mcfe)	$0.95	$1.00
Recurring cash general and administrative(1,2) ($/Mcfe)	$0.12	$0.14

	Total
	(in millions)
Capital expenditures (incurred)
Operated D&C	$365	$390
Maintenance land and seismic	$35	$40
Total capital expenditures	$400	$430

Recurring cash G&A includes capitalization. It excludes non-cash stock compensation and expenses related to the continued administration of our prior Chapter 11 filing.
This is a non-GAAP measure. Reconciliations of these non-GAAP measures and other disclosures are provided with the supplemental financial tables available on our website at www.gulfportenergy.com.

Derivatives

Gulfport enters into commodity derivative contracts on a portion of its expected future production volumes to mitigate the Company’s exposure to commodity price fluctuations. For details, please refer to the “Derivatives” section provided with the supplemental financial tables available on our website at ir.gulfportenergy.com.

Estimated Proved Reserves

Gulfport reported year end 2025 total proved reserves of 4.3 Tcfe, consisting of 3.6 Tcf of natural gas, 23.9 MMBbls of oil and 82.8 MMBbls of natural gas liquids. Gulfport’s year end 2025 total proved reserves increased approximately 7% when compared to its 2024 total proved reserves. Proved developed reserves totaled approximately 2,404 Bcfe as of December 31, 2025 or approximately 57% of Gulfport’s proved reserves. Proved undeveloped reserves totaled approximately 1,848 Bcfe as of December 31, 2025.

The table below provides information regarding the components driving the 2025 net proved reserve adjustments:

	Total (Bcfe)
Proved Reserves, December 31, 2024	3,969
Extensions and discoveries	701
Revisions of prior reserve estimates	(38)
Current production	(379)
Proved Reserves, December 31, 2025	4,253
Total may not sum due to rounding.

The following table reconciles the standardized measure of future net cash flows to the PV-10 value of Gulfport’s proved reserves:

	December 31, 2025
	Proved Developed	Proved Undeveloped	Total Proved
	($ in millions)
Estimated future net revenue	$3,816	$3,145	$6,961
Present value of estimated future net revenue (PV-10)	$2,291	$1,331	$3,622
Standardized measure			$3,403
Totals may not sum due to rounding.

Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2025, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2025. The prices used in our PV-10 measure were the average WTI Spot price of $66.01 per barrel and the average Henry Hub Spot price of $3.39 per MMBtu, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2025. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense of $219 million as of December 31, 2025.

Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company’s current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company’s financial or operating performance presented in accordance with GAAP.

A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves.

Fourth Quarter and Full Year 2025 Conference Call

Gulfport will host a teleconference and webcast to discuss its fourth quarter and full year 2025 results, as well as its 2026 outlook, beginning at 10:00 a.m. ET (9:00 a.m. CT) on Wednesday, February 25, 2026.

The conference call can be heard live through a link on the Gulfport website, www.gulfportenergy.com. In addition, you may participate in the conference call by dialing 866-373-3408 domestically or 412-902-1039 internationally. A replay of the conference call will be available on the Gulfport website and a telephone audio replay will be available from February 25, 2026 to March 11, 2026, by calling 877-660-6853 domestically or 201-612-7415 internationally and then entering the replay passcode 13756501.

Financial Statements and Guidance Documents

Fourth quarter and full year 2025 earnings results and supplemental information regarding quarterly data such as production volumes, pricing, financial statements, and non-GAAP reconciliations are available on our website at ir.gulfportenergy.com.

Non-GAAP Disclosures

This news release includes non-GAAP financial measures. Such non-GAAP measures should be not considered as an alternative to GAAP measures. Reconciliations of these non-GAAP measures and other disclosures are provided with the supplemental financial tables available on our website at ir.gulfportenergy.com.

About Gulfport

Gulfport is an independent natural gas-weighted exploration and production company focused on the exploration, acquisition and production of natural gas, crude oil and NGL in the United States with primary focus in the Appalachia and Anadarko basins. Our principal properties are located in eastern Ohio targeting the Utica and Marcellus formations and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations.

Forward Looking Statements

Forward-looking statements notice

This press release includes “forward-looking statements” for purposes of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact. They include statements regarding Gulfport’s current expectations, management’s outlook guidance or forecasts of future events, projected cash flow and liquidity, inflation, share repurchases and other return of capital plans, its ability to enhance cash flow and financial flexibility, future production and commodity mix, plans and objectives for future operations, the ability of our employees, portfolio strength and operational leadership to create long-term value and the assumptions on which such statements are based. Gulfport believes the expectations and forecasts reflected in the forward-looking statements are reasonable, Gulfport can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties. Important risks, assumptions and other important factors that could cause future results to differ materially from those expressed in the forward-looking statements are described under “Risk Factors” in Item 1A of Gulfport’s annual report on Form 10-K for the year ended December 31, 2025 and any updates to those factors set forth in Gulfport’s subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at https://www.gulfportenergy.com/investors/sec-filings). Gulfport undertakes no obligation to release publicly any revisions to any forward-looking statements, to report events or to report the occurrence of unanticipated events.

Investors should note that Gulfport announces financial information in SEC filings, press releases and public conference calls. Gulfport may use the Investors section of its website (www.gulfportenergy.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on Gulfport’s website is not part of this filing.

Contacts
Jessica Antle - Vice President, Investor Relations jantle@gulfportenergy.com
405-252-4550